10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2006 OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission File Number _______________		Exact Name of Registrant as specified in its charter _______________		State or other Jurisdiction of Incorporation ______________			IRS Employer Identification Number ___________
1-12609		PG&E Corporation		California			94-3234914
1-2348		Pacific Gas and Electric Company		California			94-0742640
Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ________________________________________				PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105 ______________________________________
Address of principal executive offices, including zip code
Pacific Gas and Electric Company (415) 973-7000 ________________________________________				PG&E Corporation (415) 267-7000 ______________________________________
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. [X] Yes     [  ] No
Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
PG&E Corporation:			[X] Large accelerated filer		[  ] Accelerated Filer	[  ] Non-accelerated filer
Pacific Gas and Electric Company:			[  ] Large accelerated filer		[  ] Accelerated Filer	[X] Non-accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:					[  ] Yes	[X] No
Pacific Gas and Electric Company:					[  ] Yes	[X] No
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common Stock Outstanding as of April 28, 2006:
PG&E Corporation				347,166,931 shares (excluding 24,665,500 shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company				Wholly owned by PG&E Corporation

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	13
	NOTE 2:		New and Significant Accounting Policies	14
	NOTE 3:		Regulatory Assets, Liabilities and Balancing Accounts	17
	NOTE 4:		Debt	20
	NOTE 5:		Shareholders' Equity	21
	NOTE 6:		Earnings Per Common Share	22
	NOTE 7:		Risk Management Activities	23
	NOTE 8:		Share-Based Compensation	24
	NOTE 9:		Related Party Agreements and Transactions	27
	NOTE 10:		The Utility's Emergence from Chapter 11	28
	NOTE 11:		Commitments and Contingencies	28
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			38
	Results of Operations			43
	Liquidity and Financial Resources			50
	Contractual Commitments			54
	Capital Expenditures			55
	Off-Balance Sheet Arrangements			55
	Contingencies			56
	Regulatory Matters			56
	Risk Management Activities			61
	Critical Accounting Policies			63
	New Accounting Policies			63
	Additional Security Measures			63
	Environmental and Legal Matters			63
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			64
ITEM 4.	CONTROLS AND PROCEDURES			64
PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS			64
ITEM 1A.	RISK FACTORS			65
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			66
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			66
ITEM 5.	OTHER INFORMATION			67
ITEM 6.	EXHIBITS			67
SIGNATURES				69

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
(in millions, except per share amounts)	Three Months Ended
	March 31,
	2006		2005
Operating Revenues
Electric	$	1,863	$		1,660
Natural gas	1,285		1,009
Total operating revenues	3,148		2,669
Operating Expenses
Cost of electricity	530		396
Cost of natural gas	873		620
Operating and maintenance	862		767
Depreciation, amortization and decommissioning	414		385
Total operating expenses	2,679		2,168
Operating Income	469		501
Interest income	23		21
Interest expense	(154)		(161)
Other expense, net	-		(1)
Income Before Income Taxes	338		360
Income tax provision	124		142
Net Income	$	214	$	218
Weighted Average Common Shares Outstanding, Basic	344		388
Net Earnings Per Common Share, Basic	$	0.61	$	0.55
Net Earnings Per Common Share, Diluted	$	0.60	$	0.54
Dividends Declared Per Common Share	$	0.33	$	0.30
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	March 31,		December 31,
	2006 (Unaudited)		2005
ASSETS
Current Assets
Cash and cash equivalents	$	903	$	713
Restricted cash	1,494		1,546
Accounts receivable:
Customers (net of allowance for doubtful accounts of $40 million          in 2006 and $77 million in 2005)	2,121		2,422
Regulatory balancing accounts	999		727
Inventories:
Gas stored underground and fuel oil	81		231
Materials and supplies	137		133
Income taxes receivable	-		21
Prepaid expenses and other	256		187
Total current assets	5,991		5,980
Property, Plant and Equipment
Electric	22,733		22,482
Gas	8,858		8,794
Construction work in progress	897		738
Other	15		16
Total property, plant and equipment	32,503		32,030
Accumulated depreciation	(12,249)		(12,075)
Net property, plant and equipment	20,254		19,955
Other Noncurrent Assets
Regulatory assets	5,361		5,578
Nuclear decommissioning funds	1,761		1,719
Other	707		842
Total other noncurrent assets	7,829		8,139
TOTAL ASSETS	$	34,074	$	34,074
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,		December 31,
	2006 (Unaudited)		2005
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	-	$	260
Long-term debt, classified as current		2		2
Rate reduction bonds, classified as current	290		290
Energy recovery bonds, classified as current	343		316
Accounts payable:
Trade creditors	760		980
Disputed claims and customer refunds	1,731		1,733
Regulatory balancing accounts	1,057		840
Other	470		441
Interest payable	441		473
Income taxes payable	229		-
Deferred income taxes	195		181
Other	1,555		1,416
Total current liabilities	7,073		6,932
Noncurrent Liabilities
Long-term debt	6,976		6,976
Rate reduction bonds	216		290
Energy recovery bonds	2,193		2,276
Regulatory liabilities	3,392		3,506
Asset retirement obligations	1,611		1,587
Deferred income taxes	3,046		3,092
Deferred tax credits	111		112
Other	1,847		1,833
Total noncurrent liabilities	19,392		19,672
Commitments and Contingencies (Notes 2, 4, 5, 10 and 11)
Preferred Stock of Subsidiaries	252		252
Preferred Stock
Preferred stock, no par value, authorized 80,000,000 shares, $100 par       value, authorized 5,000,000 shares, none issued	-		-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued       370,282,838 common and 1,349,490 restricted shares in 2006 and       366,868,512 common and 1,399,990 restricted shares in 2005	5,844		5,827
Common stock held by subsidiary, at cost, 24,665,500 shares	(718)		(718)
Unearned compensation	-		(22)
Reinvested earnings	2,239		2,139
Accumulated other comprehensive loss	(8)		(8)
Total common shareholders' equity	7,357		7,218
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,074	$	34,074
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
(in millions)	Three Months Ended
	March 31,
	2006		2005
Cash Flows From Operating Activities
Net income	$	214	$	218
Adjustments to reconcile net income to net cash provided by operating       activities:
Depreciation, amortization, decommissioning and allowance for             equity funds used during construction	402		385
Deferred income taxes and tax credits, net	(30)		(63)
Other deferred charges and noncurrent liabilities	58		(45)
Net effect of changes in operating assets and liabilities:
Accounts receivable	303		169
Inventories	146		90
Accounts payable	(124)		(115)
Accrued taxes	250		202
Regulatory balancing accounts, net	(55)		254
Other current assets	(80)		(14)
Other current liabilities	16		(168)
Other	29		39
Net cash provided by operating activities	1,129		952
Cash Flows From Investing Activities
Capital expenditures	(576)		(349)
Net proceeds from sale of assets	3		11
Decrease in restricted cash	52		122
Proceeds from nuclear decommissioning trust sales	435		1,675
Purchases of nuclear decommissioning trust investments	(477)		(1,673)
Other	11		24
Net cash used in investing activities	(552)		(190)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility	50		-
Repayments under working capital facility and accounts receivable       facility	(310)		(300)
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)
Rate reduction bonds matured	(74)		(74)
Energy recovery bonds matured	(56)		-
Preferred stock with mandatory redemption provisions redeemed	-		(2)
Common stock issued	66		120
Common stock repurchased	(58)		(1,065)
Preferred dividends paid	(3)		(4)
Common stock dividends paid	(114)		-
Other	112		-
Net cash used in financing activities	(387)		(353)
Net change in cash and cash equivalents	190		409
Cash and cash equivalents at January 1	713		972
Cash and cash equivalents at March 31	$	903	$	1,381
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	-	$	6
Cash paid for:
Interest (net of amounts capitalized)	167		267
Income taxes refunded, net	(103)		(14)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	114	$	111
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended
(in millions)	March 31,
	2006		2005
Operating Revenues
Electric	$	1,863	$	1,660
Natural gas	1,285		1,009
Total operating revenues	3,148		2,669
Operating Expenses
Cost of electricity	530		396
Cost of natural gas	873		620
Operating and maintenance	862		773
Depreciation, amortization and decommissioning	413		385
Total operating expenses	2,678		2,174
Operating Income	470		495
Interest income	19		20
Interest expense	(146)		(154)
Other income, net	6		4
Income Before Income Taxes	349		365
Income tax provision	132		142
Net Income	217		223
Preferred stock dividend requirement	3		4
Income Available for Common Stock	$	214	$	219
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	March 31,		December 31,
	2006		2005
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	604	$	463
Restricted cash	1,494		1,546
Accounts receivable:
Customers (net of allowance for doubtful accounts of $40          million in 2006 and $77 million in 2005)	2,121		2,422
Related parties	1		3
Regulatory balancing accounts	999		727
Inventories:
Gas stored underground and fuel oil	81		231
Materials and supplies	137		133
Income taxes receivable	-		48
Prepaid expenses and other	253		183
Total current assets	5,690		5,756
Property, Plant and Equipment
Electric	22,733		22,482
Gas	8,858		8,794
Construction work in progress	897		738
Total property, plant and equipment	32,488		32,014
Accumulated depreciation	(12,235)		(12,061)
Net property, plant and equipment	20,253		19,953
Other Noncurrent Assets
Regulatory assets	5,361		5,578
Nuclear decommissioning funds	1,761		1,719
Related parties receivable	22		23
Other	617		754
Total other noncurrent assets	7,761		8,074
TOTAL ASSETS	$	33,704	$	33,783
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions, except share amounts)	March 31,		December 31,
	2006		2005
	(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	-	$	260
Long-term debt, classified as current		2		2
Rate reduction bonds, classified as current	290		290
Energy recovery bonds, classified as current	343		316
Accounts payable:
Trade creditors	760		980
Disputed claims and customer refunds	1,731		1,733
Related parties	33		37
Regulatory balancing accounts	1,057		840
Other	457		423
Interest payable	435		460
Income taxes payable	154		-
Deferred income taxes	176		161
Other	1,407		1,255
Total current liabilities	6,845		6,757
Noncurrent Liabilities
Long-term debt	6,696		6,696
Rate reduction bonds	216		290
Energy recovery bonds	2,193		2,276
Regulatory liabilities	3,392		3,506
Asset retirement obligations	1,611		1,587
Deferred income taxes	3,177		3,218
Deferred tax credits	111		112
Other	1,702		1,691
Total noncurrent liabilities	19,098		19,376
Commitments and Contingencies (Notes 2, 4, 5, 10 and 11)
Shareholders' Equity
Preferred stock without mandatory redemption provisions:
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares	145		145
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares	113		113
Common stock, $5 par value, authorized 800,000,000 shares,       issued 279,624,823 shares	1,398		1,398
Common stock held by subsidiary, at cost, 19,481,213 shares	(475)		(475)
Additional paid-in capital	1,788		1,776
Reinvested earnings	4,801		4,702
Accumulated other comprehensive loss	(9)		(9)
Total shareholders' equity	7,761		7,650
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	33,704	$	33,783
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
(in millions)	Three Months Ended
	March 31,
2006		2005
Cash Flows From Operating Activities
Net income	$	217	$	223
Adjustments to reconcile net income to net cash provided by operating       activities:
Depreciation, amortization, decommissioning and allowance for equity             funds used during construction	401		385
Deferred income taxes and tax credits, net	(27)		(70)
Other deferred charges and noncurrent liabilities	55		(49)
Net effect of changes in operating assets and liabilities:
Accounts receivable	303		169
Inventories	146		90
Accounts payable	(124)		(115)
Accrued taxes	202		220
Regulatory balancing accounts, net	(55)		254
Other current assets	(80)		(11)
Other current liabilities	41		(168)
Other	15		10
Net cash provided by operating activities	1,094		938
Cash Flows From Investing Activities
Capital expenditures	(576)		(349)
Net proceeds from sale of assets	3		11
Decrease in restricted cash	52		123
Proceeds from nuclear decommissioning trust sales	435		1,675
Purchases of nuclear decommissioning trust investments	(477)		(1,673)
Other	11		24
Net cash used in investing activities	(552)		(189)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility	50		-
Repayments under working capital facility and accounts receivable facility	(310)		(300)
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)
Rate reduction bonds matured	(74)		(74)
Energy recovery bonds matured	(56)		-
Common stock dividends paid	(115)		(110)
Preferred dividends paid	(3)		(4)
Preferred stock with mandatory redemption provisions redeemed	-		(2)
Common stock repurchased	-		(960)
Other	107		-
Net cash used in financing activities	(401)		(476)
Net change in cash and cash equivalents	141		273
Cash and cash equivalents at January 1	463		783
Cash and cash equivalents at March 31	$	604	$	1,056
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	-	$	6
Cash paid for:
Interest (net of amounts capitalized)	154		169
Income taxes refunded, net	(42)		-
See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: Organization and Basis of Presentation

               PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. The company 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, procurement and transmission, and natural gas procurement, transportation and storage. The Utility is primarily regulated by the California Public Utilities Commission, or CPUC, and the Federal Energy Regulatory Commission, or FERC.

               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 a variable interest entity which the Utility is required to consolidate under applicable accounting standards. 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 accounting principles generally accepted in the United States of America, or GAAP, for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission, or SEC, and do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. The information at December 31, 2005 in both PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined Annual Report on Form 10-K for the year ended December 31, 2005. (PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended Dece mber 31, 2005, together with the information incorporated by reference into such report, is referred to in this quarterly report as the "2005 Annual Report.")

               Except for the new and significant accounting policies described in Note 2 below, the accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 in the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

               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. A change in management's estimates or assumptions could have a material impact on PG&E Corporation's and the Utility's financial condition and results of operations during the period in which such change occurred. 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 materially from these estimates and assumptions. 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 condition and results of operations for the periods presented. The results of operations for in terim periods are not necessarily indicative of the results of operations for the full year.

               As discussed below in Note 10, the U.S. Bankruptcy Court for the Northern District of California, or bankruptcy court, which oversaw the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, retains jurisdiction, among other things, to resolve the remaining disputed claims that were 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 in the 2005 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

Share-Based Payment

               On January 1, 2006, PG&E Corporation and the Utility adopted the provisions of SFAS No. 123R, "Share-Based Payment," or SFAS No.123R, using the modified prospective method which requires that compensation cost be recognized for all share-based payment awards, including unvested stock options, based on the grant-date fair value. Prior to January 1, 2006, PG&E Corporation and the Utility accounted for share-based payments, such as stock options, restricted stock and other share-based incentive awards, under the recognition and measurement provisions of Accounting Principles Board, or APB, Opinion No. 25, "Accounting for Stock Issued to Employees," or Opinion 25, as permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," or SFAS No. 123. Under the provisions of Opinion 25, compensation cost for stock options was not recognized for periods prior to January 1, 2006, as all options granted under tho se plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

               SFAS No. 123R requires that an estimate of future forfeitures be made and that compensation cost be recognized only for shares that are expected to vest. As a result, PG&E Corporation and the Utility recorded a cumulative effect adjustment to reverse expense previously recorded for awards that are not expected to vest. The cumulative effect adjustments did not have a material impact on the Condensed Consolidated Financial Statements.

               For the three months ended March 31, 2006, PG&E Corporation's and the Utility's operating income and income before income taxes are $13 million and $9 million, respectively, lower than if it had continued to account for share-based payments under Opinion 25. Additionally, PG&E Corporation's and the Utility's net income would have been lower by $8 million and $6 million, respectively, than if it had continued to account for share-based payments under Opinion 25. PG&E Corporation's basic and diluted earnings per common share, or EPS, for the three months ended March 31, 2006 would have been $0.63 and $0.62, respectively, if PG&E Corporation had not adopted SFAS No. 123R. The impact on net income for the three months ended March 31, 2006 is primarily attributed to the prospective application of accounting for share-based payment awards with terms that accelerate vesting on retirement and expense recog nition of previously unvested stock options.

               Prior to the adoption of SFAS No. 123R, PG&E Corporation and the Utility expensed share-based awards over the stated vesting period regardless of terms that accelerate vesting upon retirement. Subsequent to the adoption of SFAS No. 123R, compensation expense for all awards will be recognized over the shorter of the stated vesting period or the requisite service period. If awards granted prior to adopting 123R were expensed over the requisite service period instead of the stated vesting period, there would have been an immaterial impact on the Condensed Consolidated Financial Statements of PG&E Corporation and the Utility for the three months ended March 31, 2006.

               Prior to the adoption of SFAS No. 123R, PG&E Corporation and the Utility presented all tax benefits from share-based payment awards as operating cash flows in the Statement of Cash Flows. SFAS No. 123R requires the cash flows from the tax benefits resulting from tax deductions in excess of the compensation cost recognized for those awards (excess tax benefits) to be classified as financing cash flows. PG&E Corporation's and the Utility's excess tax benefit of $24 million and $12 million, respectively, would have been classified as an operating cash inflow if PG&E Corporation and the Utility had not adopted SFAS No. 123R (see Note 8 to the Condensed Consolidated Financial Statements for further discussion of share-based compensation).

               The following table illustrates the effect on PG&E Corporation's net income and EPS for the three months ended March 31, 2005 if PG&E Corporation had applied the fair value recognition provisions of SFAS No. 123 to outstanding options.

(in millions, except per share amounts)		Three Months Ended
		March 31,
		2005
Net income:
As reported	$	218
Deduct: Incremental share-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(3)
Pro forma	$	215
Basic earnings per common share:
As reported	$	0.55
Pro forma		0.55
Diluted earnings per common share:
As reported		0.54
Pro forma		0.53

               The following table illustrates the effect on the Utility's net income for the three months ended March 31, 2005 if the fair value recognition provisions of SFAS No. 123 had been applied to outstanding options.

(in millions)		Three Months Ended
		March 31,
		2005
Income available for common stock:
As reported	$	219
Deduct: Incremental share-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(2)
Pro forma	$	217

Accounting Changes and Error Corrections

               On January 1, 2006, PG&E Corporation and the Utility adopted SFAS No. 154, "Accounting Changes and Error Corrections Disclosure," or SFAS No. 154. SFAS No. 154 replaces APB Opinion No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," or SFAS No. 3. SFAS No. 154 requires retrospective application to prior periods' financial statements of changes in accounting principle unless it is impracticable. SFAS No. 154 applies to all voluntary changes in accounting principle. It also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include explicit transition provisions. For example, the retrospective provision of SFAS No. 154 does not apply to the adoption of SFAS No. 123R which includes specific transition provisions. The adoption of SFAS No. 154 did not have a material impact on the Condensed Consolidated Financial Statements of PG&E Corporation or the Utility for the three months ended March 31, 2006.

Other-Than-Temporary Impairment

               In November 2005, the Financial Accounting Standards Board, or FASB, issued Staff Position Nos. FAS 115-1 and 124-1, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments," or FSP 115-1 and 124-1, to provide guidance in determining when an investment is impaired; whether that impairment is other-than-temporary; and the measurement of an impairment loss. PG&E Corporation and the Utility adopted FSP 115-1 and 124-1 on January 1, 2006. The adoption of FSP 115-1 and 124-1 did not have a material impact on the Condensed Consolidated Financial Statements of PG&E Corporation or the Utility for the three months ended March 31, 2006.

Changes in Accounting for Certain Derivative Contracts

               Derivatives Implementation Group, or DIG, Issue No. B38, "Embedded Derivatives: Evaluation of Net Settlement with respect to the Settlement of a Debt Instrument through Exercise of an Embedded Put Option or Call Option," or DIG B38, and DIG Issue No. B39 "Embedded Derivatives: Application of Paragraph 13(b) to Call Options That Are Exercisable Only by the Debtor," or DIG B39, address the circumstances in which a put or call option embedded in a debt instrument would be bifurcated from the debt instrument and accounted for separately. DIG B38 and DIG B39 are effective in the first quarter of 2006. The adoption of DIG B38 and DIG B39 did not have a material impact on the Condensed Consolidated Financial Statements of PG&E Corporation or the Utility for the three months ended March 31, 2006.

Comprehensive Income

               For the three months ended March 31, 2005, PG&E Corporation's and the Utility's comprehensive income consisted of changes in the effects of the remeasurement of the Utility's defined benefit pension plan. PG&E Corporation and the Utility did not have any comprehensive income activity other than net income for the three months ended March 31, 2006.

(in millions)	PG&E Corporation				Utility
	2006		2005		2006		2005
Three months ended March 31
Net income available for common stock	$	214	$	218	$	214	$	219
Minimum pension liability adjustment (net of income tax benefit    of $2 million in 2005)		-		(1)		-		(2)
Comprehensive income	$	214	$	217	$	214	$	217

Accumulated Other Comprehensive Income (Loss)

               Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of PG&E Corporation and the Utility that result 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, 2004	$		(1)	$		-	$	(4)	$	1	$		(4)
Period change in:
Minimum pension liability adjustment	-			-			(1)		-		(1)
Other	1			-			-		(1)		-
Balance at March 31, 2005			-		-			(5)	-				(5)
Balance at December 31, 2005	-			-			(8)		-		(8)
Balance at March 31, 2006		$	-	$	-		$	(8)	$	-		$	(8)

               There were no changes in PG&E Corporation's or the Utility's accumulated other comprehensive income (loss) components for the three months ended March 31, 2006.

Pension and Other Postretirement Benefits

               PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan 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 the Utility use a December 31 measurement date for all of their 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 periods ended March 31, 2006 and 2005 are as follows:

PG&E Corporation

(in millions)	Pension Benefits Three Months Ended March 31,				Other Benefits Three Months Ended March 31,
	2006		2005		2006			2005
Service cost for benefits earned	$	59	$	56	$	8	$		9
Interest cost	130		125		19		20
Expected return on plan assets	(157)		(151)		(23)		(21)
Amortization of transition obligation	-		-		6		6
Amortization of prior service cost	14		14		4		3
Amortization of unrecognized loss	8		6		-		-
Net periodic benefit cost	$	54	$	50	$	14	$		17

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

               Under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended, or SFAS No. 71, regulatory adjustments are recorded in the Condensed Consolidated Statements of Income and Condensed 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 purposes, which is based on a funding approach.

Nuclear Decommissioning Trust Investment Presentation on Statement of Cash Flows

               As reported in the 2005 Annual Report, PG&E Corporation and the Utility changed the presentation of the Nuclear Decommissioning Trust investment in their Consolidated Statements of Cash Flows for the year ended December 31, 2005, to present investing cash outflows separately from investing cash inflows. Cash inflows and outflows in the Nuclear Decommissioning Trust investment balances were previously presented as a single line (net) within the investing section of the Statements of Cash Flows. PG&E Corporation and the Utility have presented cash inflows and outflows for the quarter ended March 31, 2006 and 2005 consistent with this presentation. There was no impact to net cash provided by (used in) operating, investing or financing activities as a result of this change in presentation.

NOTE 3: REGULATORY ASSETS, LIABILITIES AND BALANCING ACCOUNTS

               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.

               Under SFAS No. 71, incurred costs that would otherwise be charged to expense, may be capitalized and recorded as regulatory assets if it is probable that the incurred costs will be recovered in rates in the future. The regulatory assets are amortized over future periods consistent with the related increase in customer revenue. If a regulated enterprise is currently recovering through rates costs that it expects to incur in the future, SFAS No. 71 requires that the regulated enterprise record those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future must also be recorded as regulatory liabilities.

               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, changes in customer demand or other reasons, the related regulatory assets and liabilities are written off.

Regulatory Assets

               The Utility's regulatory assets are comprised of the following:

	Balance At
(in millions)	March 31,		December 31,
	2006		2005
Energy recovery bond regulatory assets	$	2,435	$	2,509
Utility retained generation regulatory assets	1,079		1,099
Rate reduction bond assets	394		456
Regulatory assets for deferred income tax	549		536
Unamortized loss, net of gain on reacquired debt	313		321
Environmental compliance costs	273		310
Regulatory assets associated with plan of reorganization	150		163
Post-transition period contract termination costs	129		131
Other, net	39		53
Total regulatory assets	$	5,361	$	5,578

               On February 10, 2005 and November 9, 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 and second series, respectively, of energy recovery bonds, or ERBs. The first series was issued for approximately $1.9 billion to refinance the after-tax balance of the settlement regulatory asset established under the settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility's Chapter 11 proceeding, or the Settlement Agreement. The second series was issued for approximately $844 million to pre-fund the Utility's tax liability that will be due as the Utility collects the dedicated rate component, or DRC, related to the first series of ERBs. Upon issuance of the first and second series, the Utility recorded ERB regulatory assets for approximately $1.9 billion and $838 million, respectively. For the three months ended March 31, 2006, the Utility recorded amortization of the ERB regulatory assets of approximately $74 million. The Utility expects to fully recover the ERB regulatory assets by the end of 2012.

              As a result of the Settlement Agreement, the Utility recognized a one-time non-cash gain of $1.2 billion, pre-tax ($0.7 billion, after-tax), for the Utility retained generation regulatory assets in the first quarter of 2004. The individual components of these regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years. For the three months ended March 31, 2006, the Utility recorded amortization of the Utility retained generation regulatory assets of approximately $20 million.

               The Utility's regulatory asset related to the rate reduction bonds, or RRBs, represents electric industry restructuring costs that the Utility expects to collect over the term of the RRBs. For the three months ended March 31, 2006, the Utility recorded amortization of the RRB regulatory asset of approximately $62 million. The Utility expects to fully recover the RRB regulatory asset by the end of 2007.

               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. Tax benefits to customers have been passed through as the CPUC requires utilities under its jurisdiction to follow the "flow through" method of passing benefits to customers. The "flow through" method ignores the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income tax-related regulatory assets over periods ranging from 1 to 40 years.

               The regulatory asset related to unamortized loss, net of gain, on reacquired debt represents costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over the next 1 to 21 years.

               The regulatory asset related to environmental compliance costs represents the portion of estimated environmental remediation liabilities that the Utility expects to recover in future rates as remediation costs are incurred.

               The regulatory asset related to post-transition period contract termination costs represent amounts the Utility incurred in terminating a 30-year power purchase agreement. This regulatory asset will be amortized and collected in rates on a straight-line basis until the end of September 2014, the power purchase agreement's original termination date.

               Finally, regulatory assets associated with the Utility's Chapter 11 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. The Utility expects to recover these costs over periods ranging from 2 to 30 years.

               In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the only regulatory assets 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.

Regulatory Liabilities

               The Utility's regulatory liabilities are comprised of the following:

	Balance At
(in millions)	March 31,		December 31,
	2006		2005
Cost of removal obligation	$	2,185	$	2,141
Asset retirement costs	560		538
Employee benefit plans	152		195
Price risk management	85		213
Public purpose programs	163		154
Rate reduction bonds	144		157
Other	103		108
Total regulatory liabilities	$	3,392	$	3,506

               The Utility's regulatory liabilities related to the cost of removal obligation 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 asset retirement obligations in accordance with GAAP applicable to non-regulated entities under SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143 and FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143", or FIN 47, and the amounts recognized for ratemaking purposes. The Utility's regulatory liabilities related to employee benefit plans represent the cumulative differences between expenses recognized in accordance with GAAP and expenses recognized for ratemaking purposes. The Utility's regulatory liability related to price risk management represents contracts entered into by the Utility to procure electricity and natural gas to reduce commodity price risks, which are accounted for as derivatives under SFAS No. 133. The costs and proceeds of these derivatives are recovered in regulated rates charged to customers. 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 RRBs represents the deferral of over-collected revenue associated with the RRBs that the Utility expects to return to customers in the future.

Regulatory Balancing Accounts

               The Utility's regulatory balancing accounts are used as a mechanism for the Utility to recover amounts incurred for certain costs, primarily commodity costs. Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. The Utility also obtained CPUC approval for balancing account treatment of variances between forecasted and actual commodity costs and volumes. This approval results in eliminating the earnings impact from any throughput and revenue variances from adopted forecast levels. 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 current regulatory balancing accounts accumulate balances the Utility expects to collect or refund 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 noncurrent regulatory assets and liabilities.

Current Regulatory Balancing Account Assets

	Balance At
(in millions)	March 31,		December 31,
	2006		2005
Natural gas revenue and cost balancing accounts	$	121	$	159
Electricity revenue and cost balancing accounts	878		568
Total	$	999	$	727

Current Regulatory Balancing Account Liabilities

	Balance At
(in millions)	March 31,		December 31,
	2006		2005
Natural gas revenue and cost balancing accounts	$	188	$	13
Electricity revenue and cost balancing accounts	869		827
Total	$	1,057	$	840

               The CPUC does not allow the Utility to offset regulatory balancing account assets against balancing account liabilities. During 2005, the Utility completed its first annual true-up proceeding which provided the Utility with a mechanism to recover under-collections and refund over-collections from the prior year on a timely basis and to recover current year forecasts over the next twelve months.

               During the first quarter when electric customers' usage decreases due to cooler weather, the Utility generally experiences increases in its under-collection of electricity revenues as compared to its electricity revenue requirements which are recorded on a straight-line basis throughout the year. Conversely, customers' usage of gas generally increases during the first quarter resulting in an over-collection of gas revenues as compared to the gas revenue requirements.

NOTE 4: DEBT

PG&E Corporation

               For details on PG&E Corporation's and the Utility's debt obligations, credit facilities and short-term borrowings not discussed below, refer to Note 4 in the Notes to the Consolidated Financial Statements in the 2005 Annual Report.

Convertible Subordinated Notes

               PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes, or 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 an 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" determined by multiplying the amount of the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Note s divided by the conversion price. In connection with each of the common stock dividends paid on January 17, and April 17, 2006, PG&E Corporation paid approximately $6 million of "pass through dividends" to the holders of 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 unpaid "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 recorded at fair value in PG&E Corporation's Condensed Consolidated Financial Statements. Changes in the fair value are recognized in PG&E Corporation's Condensed Consolidated Statements of Income as a non-operating expense or income (included in Other income (expense), net). At March 31, 2006 and December 31, 2005, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $89 million and $92 million, respectively, of which $22 million and $22 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $67 million and $70 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabil ities - Other). The change in value of the liability was immaterial for the quarter ended March 31, 2006.

Utility

Pollution Control Bonds

               The California Pollution Control Financing Authority and the California Infrastructure & Economic Development Bank issued various series of tax-exempt pollution control bonds for the benefit of the Utility. At March 31, 2006, there were $1.6 billion principal amount of these pollution control bonds outstanding. Under the pollution control bond loan agreements, the Utility is obligated to pay on the due dates an amount equal to the principal, premium (if any) and interest on these bonds to the trustees for the bonds.

               The majority of the pollution control bonds financed or refinanced pollution control facilities at the Utility's Geysers geothermal power plant, or the Geysers Project, or at the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon. In 1999, the Utility sold the Geysers Project to Geysers Power Company LLC, a subsidiary of Calpine Corporation. The Geysers Project purchase and sale agreements state that Geysers Power Company LLC will use the facilities solely as pollution control facilities within the meaning of Section 103(b)(4)(F) of the Internal Revenue Code and associated regulations, or the Code. On February 3, 2006, Geysers Power Company LLC filed for reorganization under Chapter 11. The Utility believes that the Geysers Project will continue to meet the use requirements of the Code.

Commercial Paper Program

               On January 10, 2006, the Utility entered into various agreements to establish the terms and procedures for the issuance of up to $1 billion of unsecured commercial paper by the Utility for general corporate purposes. The commercial paper will not be registered under the Securities Act of 1933 or applicable state securities laws and may not be offered or sold in the United States absent registration under the Securities Act of 1933 or applicable state securities laws or an applicable exemption from registration requirements. The commercial paper may have maturities up to 365 days and will rank equally with the Utility's unsubordinated and unsecured indebtedness. At March 31, 2006, the Utility had no commercial paper outstanding.

Rate Reduction Bonds

               In December 1997, PG&E Funding, LLC, a limited liability corporation wholly owned by and consolidated by the Utility, issued $2.9 billion of RRBs. The proceeds of the RRBs were used by PG&E Funding, LLC to purchase from the Utility the right, known as "transition property," to be paid a specified amount from a charge levied on residential and small commercial customers. The total principal amount of RRBs outstanding at March 31, 2006 was $506 million.

               While PG&E Funding, LLC is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets of PG&E Funding, LLC are not available to creditors of the Utility or PG&E Corporation, and the transition property is not legally an asset of the Utility or PG&E Corporation. The RRBs are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation.

Energy Recovery Bonds

               In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion. 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. The total principal amount of ERBs outstanding at March 31, 2006 was $2.5 billion.

               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 the Utility or PG&E Corporation 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, 2006 were as follows:

	PG&E Corporation		Utility
(in millions)	Total Common Shareholders' Equity		Total Shareholders' Equity
Balance at December 31, 2005	$	7,218	$	7,650
Net income	214		217
Common stock issued	66		-
PG&E Corporation common stock repurchased:
Settlement of accelerated share repurchase obligation -   March 2006	(58)		-
Common restricted stock amortization	7		-
Common stock dividends paid	-		(115)
Common stock dividends declared but not yet paid	(114)		-
Preferred stock dividends	-		(3)
Tax benefit from share-based payment awards	24		12
Balance at March 31, 2006	$	7,357	$	7,761

Stock Repurchases

               On November 16, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement, or ASR, with Goldman Sachs & Co. Inc., or GS&Co., under which PG&E Corporation repurchased and retired 31,650,300 shares of its outstanding common stock for an initial aggregate purchase price of approximately $1.1 billion, or $34.75 per share. PG&E Corporation recorded approximately $504 million to Common Stock and approximately $596 million to Reinvested Earnings within Common Shareholders' Equity with respect to this transaction.

               Under the share forward agreement related to the ASR, certain additional payments are required by both PG&E Corporation and GS&Co. Most significantly, PG&E Corporation may receive from, or be required to pay to, GS&Co. a price adjustment based on the average of the daily volume weighted average price, or VWAP, of PG&E Corporation common stock over a period of approximately seven months.

               On March 28, 2006, the share forward agreement related to the ASR was terminated in accordance with its terms as the result of a declaration of the PG&E Corporation common stock dividend payable on April 15, 2006. In connection with the termination, on March 31, 2006, PG&E Corporation paid GS&Co. approximately $58 million (net of amounts payable by GS&Co. to PG&E Corporation), including a price adjustment based on the VWAP of PG&E Corporation common stock from November 17, 2005 through March 28, 2006. Because the price adjustment and any additional payment obligations could 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 accounted for its payment obligation as equity. Accordingly, approximately 1.5 million additional shares of PG&E Corporation common stock that were potentially issuable under the t erminated share forward agreement were treated as outstanding for purposes of calculating diluted EPS for the quarter ended March 31, 2006.

               On March 28, 2006, PG&E Corporation entered into a new share forward agreement with GS&Co. to complete the ASR. Under the new share forward agreement, PG&E Corporation and GS&Co. will continue to be required to make certain payments, including a price adjustment based on the VWAP from March 29, 2006 through June 8, 2006.

               The price adjustment and any additional payment obligations that PG&E Corporation or GS&Co. may incur can be settled, at PG&E Corporation's option, in cash or in shares of its common stock, or a combination of the two. Accordingly, PG&E Corporation accounts for its payment obligations under the new share forward agreement as equity. PG&E Corporation must calculate the number of shares that would be required to satisfy its obligations upon completion of the share forward agreement 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 EPS. Over the remaining term of the new share forward agreement, for every $1 that the VWAP exceeds $34.75, PG&E Corporation will owe GS&Co. an additional price adjustment of $ 10.7 million. Conversely, for every $1 that the VWAP is less than $34.75, the price adjustment will be reduced by $10.7 million. Based on the market price of PG&E Corporation stock at March 31, 2006, PG&E Corporation would have an obligation to GS&Co. of approximately $49.6 million upon completion of the new share forward agreement. Accordingly, approximately 1.3 million additional shares of PG&E Corporation common stock were treated as outstanding for purposes of calculating diluted EPS for the quarter ended March 31, 2006 (in addition to the 1.5 million shares treated as outstanding under the terminated share forward agreement discussed above).

Dividends

               On February 15, 2006, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.33 per share payable on April 15, 2006, to shareholders of record on March 31, 2006. On February 15, 2006, the Board of Directors of the Utility declared a common stock dividend in the aggregate amount of $124 million that was paid on February 16, 2006. Approximately $115 million of the common stock dividends were paid to PG&E Corporation and the remainder were paid to PG&E Holdings, LLC, a wholly owned subsidiary of the Utility.

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

NOTE 6: EARNINGS PER COMMON SHARE

               EPS 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 shares and participating securities. PG&E Corporation's Convertible Subordinated Notes are entitled to receive "pass through dividends" prior to 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.

               PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS in accordance with SFAS No. 128, "Earnings Per Share," or SFAS 128. SFAS 128 requires that proceeds from the exercise of options and warrants shall be assumed to be used to purchase common shares at the average market price during the reported period. The incremental shares, the difference between the number of shares assumed issued upon exercise and the number of shares assumed purchased, must be included in the number of weighted average common shares used for the calculation of diluted EPS.

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

		Three Months Ended
		March 31,
(in millions, except share amounts)		2006		2005
Net income		$	214	$	218
Less: distributed earnings to common shareholders			114		111
Undistributed earnings		$	100	$	107
Common shareholders earnings
Basic
Distributed earnings to common shareholders		$	114	$	111
Undistributed earnings allocated to common shareholders			95		102
Total common shareholders earnings, basic		$	209	$	213
Diluted
Distributed earnings to common shareholders		$	114	$	111
Undistributed earnings allocated to common shareholders			95		102
Total common shareholders earnings, diluted		$	209	$	213
Weighted average common shares outstanding, basic		344		388
9.50% Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, basic		363		407
Weighted average common shares outstanding, basic		344		388
Employee share-based compensation and accelerated share repurchase program (1)		5		4
Weighted average common shares outstanding, diluted		349		392
9.50% Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, diluted		368		411
Net earnings per common share, basic
Distributed earnings, basic		$	0.33	$	0.29
Undistributed earnings, basic			0.28		0.26
Total		$	0.61	$	0.55
Net earnings per common share, diluted
Distributed earnings, diluted		$	0.33	$	0.28
Undistributed earnings, diluted			0.27		0.26
Total		$	0.60	$	0.54
(1)	Includes approximately 2.8 million shares treated as outstanding in connection with the ASR (see Note 5 for further discussion). The remaining approximately 3 million shares relate to share-based compensation and are deemed to be outstanding per SFAS No. 128 for the purpose of calculating EPS (see Note 8 for further discussion).

               Options to purchase PG&E Corporation common shares of 16,600 and 6,500 for the three months ended March 31, 2006 and March 31, 2005, respectively, were outstanding, but not included in the computation of diluted EPS because the option exercise prices were greater than the average market price.

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

NOTE 7: RISK MANAGEMENT ACTIVITIES

Commodity Procurement Activities

               The Utility enters into contracts to procure electricity, natural gas, nuclear fuel and firm transmission rights. Except for contracts that meet the definition of normal purchases and sales, all derivative contracts including contracts designated as cash flow hedges of natural gas in the natural gas portfolios are recorded at fair value and presented as price risk management assets and liabilities on the balance sheet. On PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets, price risk management activities consist of $58 million in Current Assets - Prepaid expenses and other and $85 million in Other Noncurrent Assets - Other, and $73 million in Current Liabilities - Other, as of March 31, 2006, and $140 million in Current Assets - Prepaid expenses and other and $212 million in Other Noncurrent Assets - Other, and $2 million in Current Liabilities - Other, as of December 31, 2005. However , since these contracts are used within the regulatory framework, regulatory accounts are recorded to offset the costs and proceeds of these derivatives recognized in earnings and subsequently recovered in regulated rates charged to customers.

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. The Utility's regional concentration of credit risk associated with receivables from the sale of natural gas and electricity to residential and small commercial customers in northern and central California is limited. Credit risk exposure is mitigated by requiring deposits from new customers and from those customers whose past payment practices are below standard. A material loss associated with retail receivables is not considered likely.

               Additionally, the Utility has a concentration of credit risk associated with its 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. If a counterparty failed to perform on its contractual obligation to deliver electricity, then the Utility may need to procure electricity at current market prices, which may be higher than those originally contracted for. However, credit losses attributable to receivables and electrical and gas procurement activities from both retail and wholesale customers and counterparties are expected to be recoverable from customers through rates and are, therefore, not expected to have a material impact on earnings.

               The Utility manages credit risk for its wholesale customers or 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. Further, the Utility relies on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractual specified limits.

               The schedule below summarizes the Utility's net credit risk exposure, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at March 31, 2006 and December 31, 2005:

(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, 2006		$	211	$	24	$	187	2	$	69
December 31, 2005		447		105		342		3	165
(1)	Gross credit exposure equals mark-to-market value on financially settled contracts, 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 or liquidity. The Utility's gross credit exposure includes wholesale activity only.
(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.

NOTE 8: SHARE-BASED COMPENSATION

               On January 1, 2006, the PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, became effective. The 2006 LTIP permits the award of various forms of incentive awards including stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance shares, performance units, deferred compensation awards, and other stock-based awards to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive restricted stock and either stock options or restricted stock units under the formula grant provisions of the 2006 LTIP. A maximum of 12 million shares of PG&E Corporation common stock (subject to adjustment for changes in capital structure, stock dividends, or other similar events) have been reserved for issuance under the 2006 LTIP, of which 11,457,540 shares were available for award at March 3 1, 2006.

               The 2006 LTIP replaced the PG&E Corporation Long-Term Incentive Program, which expired on December 31, 2005. Awards made under the PG&E Corporation Long-Term Incentive Program before December 31, 2005 and that are still outstanding continue to be governed by the terms and conditions of the PG&E Corporation Long-Term Incentive Program. Some of the stock options that are still outstanding under the PG&E Corporation Long-Term Incentive Program have associated dividend equivalents.

               Total compensation expense for share-based incentive awards was approximately $26 million ($15 million, after-tax) for the three months ended March 31, 2006, of which approximately $19 million ($11 million, after-tax) was recognized by the Utility.

               As discussed in Note 2, "New and Significant Accounting Policies - Share-Based Payment," effective January 1, 2006, PG&E Corporation adopted the fair value recognition provisions for share-based payment using the modified prospective application method provided by SFAS No. 123R.

Stock Options

               Stock options are granted with an exercise price equal to the market price of PG&E Corporation's stock at the date of grant and generally vest over 4 years of continuous service. The options have a 10-year contractual term.

               The fair value of each stock option is estimated on the date of grant using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $6.98 and $8.51 per share in 2006 and 2005, respectively. The significant assumptions used for shares granted in 2006 and 2005 were:

		2006		2005
Expected stock price volatility		22.1%		40.6%
Expected annual dividend payment	$	1.32	$	1.20
Risk-free interest rate		4.46%		3.74%
Expected life		5.6 years		5.9 years

               Expected volatilities are based on historical volatility of PG&E Corporation's common stock. The expected life of stock options is derived from historical data that estimates stock option exercise and employee departure behavior. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. treasury rates in effect at the date of grant.

               The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005 was approximately $49 million and approximately $60 million, respectively, of which approximately $25 million and approximately $24 million was recorded by the Utility. Cash received from options exercised for the three months ended March 31, 2006 and 2005, was $63 million and $120 million, respectively. The tax benefit from option exercises totaled $20 million for the period ended March 31, 2006, of which approximately $10 million was recognized by the Utility.

               The following table summarizes stock option activity for PG&E Corporation and the Utility for the three months ended March 31, 2006:

Options		Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2006		11,899,059	$	23.26
Granted (1)		12,457		37.47
Exercised		(2,902,792)		21.64
Forfeited or expired		(57,260)		23.42
Outstanding at March 31, 2006		8,951,464		23.79	5.1	$	135,235,667
Exercisable at March 31, 2006		6,468,777		19.80	4.0	$	105,006,064
(1)	No stock options were awarded to employees in 2006; however certain non-employee directors of PG&E Corporation were awarded stock options.

               The following table summarizes stock option activity for the Utility for the three months ended March 31, 2006:

Options	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2006	7,371,761	$	23.15
Granted	-		-
Exercised	(1,493,392)		21.99
Forfeited or expired	(31,139)		27.29
Outstanding at March 31, 2006	5,847,230		23.49		5.7	$	90,432,538
Exercisable at March 31, 2006	4,067,333		20.48		4.8	$	68,525,620

As of March 31, 2006, there was approximately $19 million of total unrecognized compensation cost, of which $14 million related to the Utility. That cost is expected to be recognized over a weighted average period of 2.0 years and 1.9 years for PG&E Corporation and the Utility, respectively.

Restricted Stock

 During the three months ended March 31, 2006, PG&E Corporation awarded 519,865 shares of PG&E Corporation restricted common stock to eligible participants of PG&E Corporation and its subsidiaries, of which 363,720 shares were awarded to the Utility's eligible participants.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. For the restricted stock awarded in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation's annual total shareholder return, or TSR, is in the top quartile of its comparator group as measured at the end of the immediately preceding year. For restricted stock awarded in 2005 and 2004, there are no performance criteria and the restrictions will lapse ratably over four years. For restricted stock awarded in 2006, the restrictions on 60% of the shares will lapse automatically over a period of three years at the rate of 20% per year. If PG&E Corporation' s annual TSR is in the top quartile of its comparator group as measured for the three immediately preceding calendar years, the restrictions on the remaining 40% of the shares will lapse on the first business day of 2009. If PG&E Corporation's TSR is not in the top quartile for such period, then the restrictions on the remaining 40% of the shares will lapse on the first business day of 2011. Compensation expense related to the portion of the 2006 restricted stock award subject to conditions based on TSR is recognized over the shorter of the requisite service period and three years.

The tax benefit from restricted stock settlements totaled $4 million for the three months ended March 31, 2006, of which approximately $2 million was recognized by the Utility.

The following table summarizes restricted stock activity for PG&E Corporation and the Utility for the three months ended March 31, 2006:

	Number of Shares of Restricted Stock	Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2006	1,399,990	$	22.31
Granted	519,865	37.47
Vested	(493,874)	20.97
Forfeited	(76,491)	17.94
Nonvested at March 31, 2006	1,349,490		29.01

The following table summarizes restricted stock activity for the Utility for the three months ended March 31, 2006:

	Number of Shares of Restricted Stock	Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2006	958,997	$	22.47
Granted	363,720	37.47
Vested	(339,322)	21.08
Forfeited	(66,338)	19.19
Nonvested at March 31, 2006	917,057		29.17

As of March 31, 2006, there was approximately $28 million of total unrecognized compensation cost, of which $19 million related to the Utility. PG&E Corporation and the Utility expect to recognize this cost over a weighted average period of 1.8 years.

Performance Shares

During the three months ended March 31, 2006, PG&E Corporation awarded 519,865 performance shares to certain officers and employees of PG&E Corporation and its subsidiaries, of which 363,720 shares were awarded to certain Utility officers and employees. Performance shares are hypothetical shares of PG&E Corporation common stock that vest at the end of a three-year period and are settled in cash. Upon vesting, the amount of cash recipients are entitled to receive is based on the average closing price of PG&E Corporation stock for the last 30 calendar days of the year preceding the vesting dateand a payout percentage, ranging from 0% to 200%, as measured by PG&E Corporation's TSRrelative to its co mparator group.

The following table summarizes performance share activity for PG&E Corporation and the Utility for the three months ended March 31, 2006:

	Number of Performance Shares
Nonvested at January 1, 2006	803,975
Granted	519,865
Vested	-
Forfeited	(18,527)
Nonvested at March 31, 2006	1,305,313

The following table summarizes performance shares activity for the Utility for the three months ended March 31, 2006:

	Number of Performance Shares
Nonvested at January 1, 2006	566,086
Granted	363,720
Vested	-
Forfeited	(18,457)
Nonvested at March 31, 2006	911,349

               Outstanding performance shares are classified as a liability on the Condensed Consolidated Financial Statements of PG&E Corporation and the Utility because the performance shares can only be settled in cash upon satisfaction of the performance criteria. The liability related to the performance shares is marked-to-market at each reporting date to reflect the market price of PG&E Corporation common stock and the payout percentage at the end of the reporting period. Accordingly, compensation expense recognized for performance shares will fluctuate with PG&E Corporation's common stock price and its performance relative to its peer group.

NOTE 9: 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. Services provided directly to PG&E Corporation by the Utility 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. Services provided directly to the Utility by PG&E Corporation are priced either at the fully loaded cost or at the lower 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, at cost, to the Utility and other subsidiaries using agre ed upon allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets, and other cost allocation methodologies. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

		Three Months Ended					Receivable (Payable) Balance Outstanding at
(in millions)	March 31,					March 31,			December 31,
	2006			2005		2006			2005
Utility revenues from:
Administrative services provided to    PG&E Corporation	$		1	$	1	$		-	$	2
Utility employee benefit assets due from    PG&E Corporation	(1)			-		22			23
Utility expenses from:
Administrative services received from    PG&E Corporation	$		39	$	25	$		(33)	$	(37)

NOTE 10: THE UTILITY'S EMERGENCE FROM CHAPTER 11

               The Utility emerged from Chapter 11 when its plan of reorganization became effective on April 12, 2004. The plan of reorganization incorporated the terms of the Settlement Agreement. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the plan of reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims. Refer to the 2005 Annual Report for a further discussion of the Utility's emergence from Chapter 11.

               On March 16, 2006, the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, dismissed as moot an appeal of the order issued by the bankruptcy court that confirmed the Utility's plan of reorganization. The appeal was filed by two former commissioners of the CPUC who did not vote to approve the Settlement Agreement. On March 30, 2006, one of the two former commissioners filed a petition for rehearing with the Ninth Circuit. On April 7, 2006, the Ninth Circuit denied the petition. The former commissioners may choose to file a petition for rehearing with the U.S. Supreme Court which would be due July 6, 2006.

               As of March 31, 2006 and December 31, 2005, the Utility had accrued approximately $1.2 billion for remaining net disputed claims, consisting of approximately $1.7 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator, or ISO, and the California Power Exchange, or PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion. The Utility held $1.2 billion in escrow, which is recorded as restricted cash, for the payment of the remaining disputed claims as of March 31, 2006 and December 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 escrow in connection with settlements with certain ISO and PX sellers.

NOTE 11: 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

               Other than those related to the Utility and disclosed elsewhere in the Notes to the Condensed Consolidated Financial Statements at March 31, 2006, PG&E Corporation did not have any material commitments.

Utility

Power Purchase Agreements

               As part of the ordinary course of business, throughout the year, the Utility enters into various agreements to purchase energy and makes payments on existing power purchase agreements. At March 31, 2006, the expected payments for power purchase agreements based on March 31, 2006 forward prices were as follows:

(in millions)
2006	$	1,809
2007		2,397
2008		2,223
2009		1,888
2010		1,581
Thereafter		11,220
Total	$	21,118

               Payments made by the Utility under power purchase agreements amounted to approximately $439 million for the three months ended March 31, 2006, and $422 million for the same period in 2005. As the Utility acts as only an agent for the Department of Water Resources, or DWR, the amounts described above do not include DWR power purchases.

Natural Gas Supply and Transportation Commitments

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

               At March 31, 2006, the Utility's expected payments for natural gas purchases based on March 31, 2006 forward prices and gas transportation services based on existing contract prices were as follows:

(in millions)
2006	$	710
2007		150
2008		13
2009		9
2010		4
Thereafter		-
Total	$	886

               Payments made by the Utility for natural gas purchases and gas transportation services amounted to approximately $821 million for the three months ended March 31, 2006, and $588 million for the same period in 2005.

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 in certain power plants, known as RMR units, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. As a participating transmission owner under the Transmission Control Agreement, the Utility is responsible for the ISO's costs paid under RMR agreements to power plant owners within or adjacent to the Utility's service territory. At March 31, 2006, the Utility estimated that it could be obligated to pay the ISO approximately $240 million for costs incurred under these RMR agreements during the period April 1, 2006 to December 31, 2006. Under the Utility's transmission owner tariff, the Utility recovers the costs, without mark-up or service fees. The Utility estimates it would receive approximately $31 million during the same period under the RMR agreements the Utility has with the ISO for the Utility's units that have been designated as RMR units. The Utility tracks these costs and related recoveries in the reliability services balancing account. Periodically the Utility's electricity transmission rates are adjusted to reflect new forecasts of these costs and to refund over-collections to the Utility's customers or to collect any under-collections from customers.

               In November 2001, the Utility and other interested California parties filed a complaint with the FERC against RMR owners other than the Utility, alleging that certain rates under those owners' RMR agreements with the ISO were unlawfully high and proposing that the FERC apply a ratemaking methodology to these other RMR agreements that would significantly reduce those rates. The FERC dismissed the complaint in 2005. In September 2005, the Utility and other interested California parties filed a petition for review of the FERC's decision with the United States Court of Appeals for the District of Columbia Circuit, or D.C. Circuit Court. If the appeal is successful and the FERC applies the revised ratemaking methodology, the Utility may be able to obtain a refund of RMR charges of approximately $50 million that would be credited to the Utility's electricity customers. PG&E Corporation and the U tility are unable to predict the outcome of this matter.

               In November 2005, two affiliates of Calpine Corporation filed with the FERC large proposed rate increases for fixed-cost payments under the RMR contracts for the Delta Energy Center and Los Esteros Critical Energy Facility. The proposed rates increase the Utility's combined RMR payments for these facilities by approximately $70 million per year over the amounts paid in 2005. On January 26, 2006, the FERC made these rates effective, subject to hearing and possible refund. The FERC deferred the hearing and directed the parties to engage in settlement efforts. On February 28, 2006, the Utility filed a complaint with the FERC alleging that these affiliates of Calpine Corporation violated the FERC's market behavior rule that prohibits furnishing false or misleading information to independent system operators, among others, because the proposed rates were far higher than their July 2005 bids to the ISO for RMR service in 2006. This complaint asks the FERC to reduce the rates for these RMR units to a level no higher than would have resulted from these bids. Any refunds the Utility may obtain when these cases are decided will be credited to the Utility's electricity customers. PG&E Corporation and the Utility are unable to predict the outcome of this matter.

Contingencies

PG&E Corporation

               PG&E Corporation retains a guarantee of up to $150 million related to certain indemnity obligations of its former subsidiary, National Energy and Gas Transmission, Inc., or NEGT, that were issued to the purchaser of an NEGT subsidiary company during 2000. The underlying indemnity obligations of NEGT have expired and PG&E Corporation's sole remaining exposure relates to any potential 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 be made under the guarantee. Accordingly, PG&E Corporation has made no provision for this guarantee at March 31, 2006.

               PG&E Corporation also retains a guarantee of the Utility's underlying obligation to pay workers' compensation claims. As of March 31, 2006, the Utility's actuarially determined workers' compensation liability was approximately $211 million.

Utility

PX Block-Forward Contracts

               In February 2001, during the energy crisis, the California Governor seized all of the Utility's contracts for the forward delivery of power in the PX market, otherwise known as "block-forward contracts," for the benefit of the state under California's Emergency Services Act. These block-forward contracts had an estimated unrealized value 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 competing claims in state court against the state of California to recover the value of these seized contracts. In November 2005, the PX assigned its interest in this litigation to certain market participants that elected to take assignment of the litigation, subject to the terms and conditions of a settlement agreement approved by the FERC. A motion by the PX for court approval of the assignment is pending in the Sacramento Superior Court. The state of California disputes this assignment and the plaintiffs' rights to recover the value of the contracts and also disputes plaintiffs' contentions that the contracts had any value beyond the price at which the block-forward transactions were executed. This state court litigation is pending. Although the Utility has recorded a receivable of approximately $243 million relating to the estimated value of the contracts at the time of seizure, the Utility also has established a reserve of $243 million for these contracts. If the Utility ultimately prevails, it would record income in the amount of any recovery. PG&E Corporation and the Utility are unable to predict the outcome of this litigation or the amount of any potential recovery.

California Energy Crisis Proceedings

FERC Proceedings

               Various entities, including the Utility and the state of California, are seeking refunds from energy suppliers in the California ISO and PX markets for electricity overcharges on behalf of California electricity purchasers for the period May 2000 to June 2001 through various proceedings pending at the FERC and judicial proceedings. Refer to the 2005 Annual Report for a further discussion of the Utility's California Energy Crisis Proceedings.

               The FERC established a refund methodology and directed the ISO and the PX to make compliance filings to enable the FERC to establish the amount of refunds. The ISO had previously indicated that it planned to make its compliance filing in the first quarter of 2006 with the PX to follow. However, the ISO cannot make its filing until the FERC rules on pending claims made by energy suppliers for recovery of certain costs that could offset any refunds the FERC determines those suppliers owe.

               In September 2005, the Ninth Circuit issued a partial decision finding that the FERC did not have the authority to order governmental and municipal utilities to provide refunds. This decision remains subject to rehearing or further appellate review. On March 16, 2006, the California utilities and the California Electric Oversight Board filed a lawsuit against 19 municipal and governmental entities seeking refunds. Additional refund claims also are being pursued against three other governmental entities. Based on preliminary rulings by a FERC administrative law judge, the amount being sought by the California utilities in the claims against the governmental and municipal entities is estimated to be approximately $150 million or more. A further Ninth Circuit decision on the extent of the FERC's power to order refunds from other sellers is still pending. Final refunds will not be determined until the FERC issues a final order after the ISO and PX compliance filings are made and after the resolution of appeals.

               The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceedings as disputed claims. This amount is subject to pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under bankruptcy court order, the aggregate allowable amount of unpaid PX and generator claims was limited to approximately $1.6 billion.

               The Utility has entered into settlements with various power suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. The Utility has recorded credits to customers of approximately $1 billion under these settlements. These settlement agreements provide that the amounts payable by the parties are subject to adjustment based on the ultimate judicial determination of the FERC's refund authority, and the FERC's final decisions regarding refund amounts, cost filings, gas and emissions recovery and allocation, and interest. Future amounts received under these settlements, and any future settlements with energy suppliers will be credited to customers, except for those related to wholesale power purchasers.

Enron Settlement

               In November 2005, the FERC approved an agreement among the Utility, along with the Attorney General of the State of California, the DWR, Southern California Edison, San Diego Gas & Electric Company, the California Electric Oversight Board and the CPUC (collectively, the California Parties), along with the Attorney Generals of the States of Oregon and Washington, and the FERC's Office of Market Oversight and Investigations (collectively, the Other Parties) and Enron Corporation and various of its subsidiaries, or Enron, to satisfy Enron's liabilities to make refunds.

               The settlement provides Enron would pay $47 million in cash to the California Parties and Other Parties and allow them an unsecured claim of $875 million in the bankruptcy proceedings of Enron Power Marketing, Inc., a subsidiary through which Enron conducted its power marketing operations in California, to settle electric and gas market overcharges. Of these amounts, the Utility expects to receive approximately $12 million in cash, over time, and approximately $345 million of the unsecured bankruptcy claim. In the first quarter of 2006, the Utility received cash proceeds of approximately $20 million, consisting of $5 million from the cash portion of the settlement proceeds and $15 million as a partial distribution of the allowed claim, which was credited to customers. In April 2006, the Utility received a second distribution on its allowed unsecured bankruptcy claim, consisting of $41 million i n cash and 281,828 shares of Portland General Electric. The proceeds from this distribution will be credited to customers. The final value of the allowed unsecured bankruptcy claim will not be determined until the conclusion of Enron's bankruptcy case unless liquidated earlier in a secondary market for such claims.

Reliant Settlement

               In December 2005, the FERC approved an agreement between the Utility, along with the Attorney Generals of the States of Oregon and Washington, the DWR, the FERC's Office of Market Oversight and Investigations, Southern California Edison and San Diego Gas & Electric Company and Reliant Energy, Inc. and various of its subsidiaries, or Reliant, to resolve claims against Reliant for gas and electric market manipulation and overcharges during the California energy crisis in 2000 and 2001.

               Under the terms of the agreement, Reliant has assigned to the counterparties approximately $300 million of its receivables from the ISO or the PX and agreed to pay the counterparties approximately $131 million in cash. In 2005, the Utility recognized approximately $105 million of its share of the assignment of Reliant's receivable from the ISO or PX as a reduction in the Utility's payable to the PX. In addition, in March 2006, the Utility received its share of initial cash proceeds of approximately $88 million, which was credited to customers. The Utility expects to receive additional cash proceeds of approximately $10 million over time.

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, related to claims outstanding in Mirant's Chapter 11 proceeding.

               The first part of the two-part settlement is between Mirant, the California Attorney General's Office, the DWR, the CPUC, Southern California Edison, San Diego Gas & Electric Company, and the Utility, among others, resolving market manipulation claims against Mirant and 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 approximately $320 million in cash equivalents and $175 million of allowed claims in the bankruptcy proceeding of Mirant America's Energy Marketing, LP. Of these amounts, the Utility has received approximately $134 million, in cash and as a reduction in the Utility's payable to the PX. Additionally, the Utility received approximately $45 million in allowed claims excluding interest, which the Utility sold in December 2005 for approximately $ 48 million, including interest owed by Mirant. The consideration received, after deductions for contingencies, amounts related to certain wholesale power purchases and amounts due to shareholders, has been credited to the Utility's customers.

               The second part of the settlement is between the Utility and Mirant and is designed to settle claims that Mirant overcharged the Utility under Mirant's RMR contracts and other disputes. Under the terms of the settlement agreement, the Utility received consideration, in the form of cash and new Mirant stock, in January 2006 of approximately $43 million in settlement of an RMR claim and $20 million in settlement of a claim relating to sulfur dioxide emission allowances. These proceeds have been credited to the Utility's customers during the quarter ended March 31, 2006. In addition, Mirant agreed to transfer to the Utility the equipment, permits and contracts for the construction of Contra Costa Unit 8, a modern 530 megawatt, or MW, electric generating facility Mirant started to build but never completed. On June 10, 2005, the Utility and Mirant completed negotiations of an Asset Transfer Agreem ent, which provides the terms and conditions under which the Contra Costa Unit 8 equipment, permits, and contracts would be transferred to the Utility and development and construction of the plant would be completed. On June 17, 2005, the Utility filed an application with the CPUC requesting approval of the Asset Transfer Agreement and cost-of-service funding to complete the $310 million construction of the facility and to operate it for up to three years. A final decision by the CPUC is expected in the second quarter of 2006. If the Utility and Mirant do not receive the necessary approvals, including CPUC authorization, the Utility will be paid $70 million, plus accrued interest, from an escrow account funded by Mirant in lieu of transferring the assets. The settlement agreement also includes a contract that gives the Utility the right, from 2006 through 2012, to dispatch power from certain RMR units owned by Mirant subsidiaries, subject to continued RMR status, when the facilities are not needed by the ISO to meet local reliability needs. In addition, Mirant has withdrawn the claim it filed in the Utility's bankruptcy proceeding of approximately $20 million.

Scheduling Coordinator Costs

               Before the ISO commenced operation in 1998, the Utility had entered into several wholesale electric transmission contracts with various governmental entities. After the ISO began operations, the Utility served as the scheduling coordinator, or SC, with the ISO for these existing wholesale transmission customers, or ETCs. The ISO billed the Utility for providing certain services associated with this scheduling. These ISO charges are referred to as "SC costs." The SC costs were historically tracked in the transmission revenue balancing account, or TRBA, in order to recover the SC costs from retail and new wholesale transmission customers, or TO Tariff customers.

In 1999, a FERC administrative law judge ruled that the Utility could not recover the SC costs through the TRBA and instead should seek to recover them from the ETCs. In January 2000, the FERC accepted a filing by the Utility to establish the Scheduling Coordinator Services, or SCS, Tariff, to serve as an alternative mechanism for recovery of the SC costs from the ETCs if the Utility were ultimately unable to recover these costs in the TRBA. The Utility began billing the ETCs in June 2004 for SC charges retroactive to March 31, 1998. In July 2005, the D.C. Circuit Court issued an order finding that the Utility was not barred from recovering the SC costs through the TRBA and remanded the matter to the FERC for further action. In December 2005, the FERC issued an order on remand concluding that the Utility should recover the SC costs through the TRBA mechanism or through bilateral agreements with the ETCs, but could not recover the costs through the SCS Tariff, and terminated the SCS Tariff proceeding.

               In January 2006, the Utility submitted a request for clarification or, alternatively, for rehearing to seek clarification of the FERC's December 2005 order. In particular, the Utility asked that the FERC clarify that the Utility can recover through the TRBA all of the costs it incurred as an SC or, alternatively on rehearing, reverse its decision to terminate the SCS Tariff proceeding. In February 2006, the FERC confirmed that they will rehear the December 2005 order.

               On April 4, 2006, the Utility filed at FERC for recovery through the TRBA of $109 million of SC costs and $47 million of interest for the time period April 1998 through September 30, 2005, to be recovered over three and a half years from TO Tariff customers. The Utility has also filed an advice letter with the CPUC requesting a pass-through of these costs, if approved by FERC, to its retail customers. The Utility cannot predict when a final decision will be received from the FERC or the CPUC. However, PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations, and could have a positive impact of approximately $120 million if the FERC and CPUC approve the recovery of these costs.

Nuclear Insurance

               The Utility has several types of nuclear insurance for Diablo Canyon and its retired nuclear facility at Humboldt Bay, or Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $43.6 million per one-year policy term.

               NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. There is no policy coverage limitation for an act caused by foreign terrorism because NEIL would be entitled to receive substantial reimbursement by the federal government under the Terrorism Risk Insurance Extension Act of 2005. The Terrorism Risk Insurance Extension Act of 2005 expires on December 31, 2007.

               Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for Diablo Canyon. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $15 million per incident until the Utility has fully paid its share of the liability. Since Diablo Canyon has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $30 million per incident. Under the Energy Policy Act of 2005, the Price-Anderson Act was extended through December 31, 2025. Both the maximum assessment per reactor and the maximum yearly assessment will be adjusted for inflation beginning August 31, 2008.

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

California Department of Water Resources Contracts

               Electricity from the DWR contracts to the Utility provided approximately 25% of the electricity delivered to the Utility's customers for the three months ended March 31, 2006. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, 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. The Utility's net open position is the portion of the Utility's customers' demand, plus the applicable reserve margins, that is not satisfied from the Utility's own generation facilities and existing electricity contracts. The DWR remains legally and financially responsible for its electricity procurement contracts. The Utility acts as a billing and collection agent of the DWR's revenue requirements from the Utility's customers.

               The DWR contracts currently allocated to the Utility terminate at various dates through 2015 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 the Utility dispatches the resource and delivers the required electricity. In the Utility's CPUC-approved long-term electricity procurement plan, the Utility has not assumed the DWR contracts will be renewed beyond their current expiration dates.

               The DWR has stated publicly in the past 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 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 Investors Service will be no less than A2 and the Utility's long-term issuer credit rating by Standard and Poor's Ratings Service 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.

Defined Benefit Pension Plan

               In December 2005, the CPUC issued a decision to allow the Utility to file a rate increase application to recover the revenue requirement associated with the portion of a pension contribution in 2006 attributable to the Utility's distribution and generation businesses. The decision also authorized the Utility to make that revenue requirement effective in rates beginning January 1, 2006, subject to refund depending on the outcome of the application. As a result of the CPUC decision, in December 2005, the Utility filed an application requesting a revenue requirement increase of $155 million associated with the 2006 pension contribution. On January 1, 2006, electric and gas rate increases to recover the amount of $155 million became effective, subject to refund. In December 2005, the Utility also filed its 2007 General Rate Case application requesting, among other things, approval of pension revenue requirements for 2007, 2008, and 2009. As of March 31, 2006, the Utility has not recognized revenue associated with the 2006 pension contribution request pending the outcome of a final CPUC decision.

               In March 2006, the Utility requested that the CPUC approve a proposed settlement among the Utility, the CPUC's Division of Ratepayer Advocates, and the Coalition of California Utility Employees that would permit the Utility to recover pension revenue requirements attributable to its distribution and generation operations of $155 million in 2006 and $98 million per year for 2007, 2008, and 2009. The Utility is unable to predict the outcome of the application to the CPUC, or the impact it will have on its financial condition or results of operations.

Underground Electric Facilities

               At March 31, 2006, the Utility was committed to spending approximately $430 million for the conversion of existing overhead electric facilities to underground electric facilities. The timing of the work is dependent upon a number of factors, including the schedules of the respective cities and counties and telephone utilities involved. The Utility expects to spend approximately $50 to $55 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

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 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 the se 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 $466 million at March 31, 2006, and approximately $469 million at December 31, 2005. The $466 million accrued at March 31, 2006, includes approximately $189 million for remediation at gas compressor sites, approximately $100 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $177 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, 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 $466 million environmental remediation liability, approximately $140 million has been inc luded in prior rate setting proceedings. The Utility expects that an additional approximately $233 million will be allowable for inclusion in future rates in accordance with the hazardous waste ratemaking mechanism which permits the Utility to recover 90% of hazardous waste remediation costs from customers without a reasonableness review. 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 $677 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 $677 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 $87 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS Appeals Office.

               The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. The IRS has indicated that it plans to complete the audit and issue a Revenue Agent Report in the first quarter of 2007. At the beginning of its examination, the IRS indicated it would disallow synthetic fuel credits claimed by PG&E Corporation. In January 2006, a partnership, wholly owned by PG&E Corporation, which owned a portion of those synthetic fuel facilities, received a letter from the IRS disallowing approximately $40 million of synthetic fuel credits. These credits are part of $104 million of synthetic fuel credits claimed by PG&E Corporation in its 2001 and 2002 consolidated federal income tax returns. PG&E Corporation expects the IRS to take similar action with respect to the remaining $64 million of synthetic fuel credits claimed in its 2001 and 2002 consolidated fede ral income tax returns. In addition, the IRS has proposed to disallow a number of deductions, the largest of which is a deduction for abandoned or worthless assets owned by NEGT. PG&E Corporation believes that it properly reported these transactions in its tax returns and will contest any IRS assessment. If the IRS includes all of its proposed disallowances in the final Revenue Agent Report, the alleged tax deficiency would approximate $452 million. Of this deficiency, approximately $104 million relates to the synthetic fuel credits and approximately $316 million represents timing differences and would be recovered by PG&E Corporation in the future.

               The IRS began its audit of PG&E Corporation's 2003 and 2004 tax returns in the third quarter of 2005. Since the IRS is in the early stages of its investigation, the IRS has proposed no new adjustments for the tax returns.

               As of March 31, 2006, PG&E Corporation has accrued approximately $138 million to cover potential tax obligations and interest related to outstanding audits, including $89 million related to the proposed disallowance of deduction for abandoned or worthless assets owned by NEGT discussed above, and $49 million to cover potential tax obligations related to non-NEGT issues. The Utility has accrued $52 million as of March 31, 2006 to cover potential tax obligations for outstanding audits.

               After considering the above accruals, PG&E Corporation and the Utility do not expect the final resolution of the outstanding audits to have a material impact on their financial condition or results of operations.

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.

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

               The accrued liability for legal matters is included in PG&E Corporation's and the Utility's other noncurrent liabilities in the Condensed Consolidated Balance Sheets, and totaled approximately $362 million at March 31, 2006 and $388 million at December 31, 2005.

               PG&E Corporation and the Utility do not believe it is probable that losses associated with legal matters that exceed amounts already recognized will be incurred in amounts that would be material to PG&E Corporation's or the Utility's financial condition or results of operations.

Chromium Litigation

               Twelve complaints were filed against the Utility in the Superior Court for the County of Los Angeles in which approximately 1,200 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 injuries, referred to as the Chromium Litigation. One of these complaints also named PG&E Corporation as a defendant. Although the plaintiffs' complaints in the Chromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000 of the 1,200 plaintiffs filed claims in the Utility's Chapter 11 case requesting compensatory damages in an approximate aggregate amount of $500 million and others filed claims for an "unknown amount." (The Utility's exit from Chapter 11 in April 2004 did not affect the plai ntiffs' claims for compensatory and punitive damages).

               On February 3, 2006, counsel for approximately 1,100 plaintiffs in the Chromium Litigation entered into a settlement agreement with the Utility under which the Utility agreed to pay settling plaintiffs $295 million. In accordance with the terms of the settlement agreement, attorneys for the settling plaintiffs have submitted releases from or on behalf of all of the settling plaintiffs. On April 21, 2006, the Utility released the $295 million settlement amount for payment to the settling plaintiffs and the Superior Court dismissed the ten pending cases covered by the settlement agreement.

               With respect to the unresolved claims, the Utility will continue to pursue appropriate defenses, including the statute of limitations, the exclusivity of workers' compensation laws, lack of exposure to chromium, and the inability of chromium to cause certain of the illnesses alleged.

               PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets for the quarter ended March 31, 2006, include an accrual of approximately $314 million to reflect both the settlement and the remaining unresolved claims. PG&E Corporation and the Utility do not expect that the outcome with respect to the remaining unresolved claims will have a material adverse effect on their financial condition or results of operations.

Pending CPUC Investigation

               In February 2005, the CPUC issued a ruling opening an investigation into the Utility's billing and collection practices and credit policies. The investigation was begun at the request of The Utility Reform Network, or TURN, after the CPUC's January 13, 2005 decision that characterized the definition of "billing error" in a revised Utility tariff to include delayed bills and Utility-caused estimated bills as being consistent with "existing CPUC policy, tariffs, and requirements." The Utility contends that prior to the CPUC's January 13, 2005 decision, "billing error" under the Utility's former tariffs did not encompass delayed bills or Utility-caused estimated bills. The Utility's petition asking the appellate court to review the CPUC's decision denying rehearing of its January 13, 2005 decision is still pending.

               On February 3, 2006, the CPUC's Consumer Protection and Safety Division, or CPSD, and TURN submitted their reports to the CPUC concluding that the Utility violated applicable tariffs related to delayed and estimated bills. The CPSD recommends that the Utility refund to customers $117 million, plus interest at the three-month commercial paper interest rate, that allegedly was collected in violation of the tariffs. TURN recommends that the Utility refund to customers $53 million, plus interest at the three-month commercial paper interest rate, that allegedly was collected in violation of the tariffs. The two refunds are not additive. The CPSD also recommends that the Utility pay fines of $6.75 million, while TURN recommends fines in the form of a $1 million contribution to Relief for Energy Assistance through Community Help. Both the CPSD and TURN recommend that refunds and fines be funded by s hareholders.

               If the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may seek to order the Utility to refund any amounts collected in violation of tariffs, plus interest, to customers who paid such amounts. In addition, if the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may seek to impose penalties on the Utility ranging from $500 to $20,000 for each separate violation.

               The Utility filed its response to the reports on March 31, 2006. Rebuttal testimony is due on May 5, 2006, and hearings are set to begin on May 24, 2006.

               PG&E Corporation and the Utility are unable to predict the outcome of this matter, which could have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

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

OVERVIEW

               PG&E Corporation, incorporated in California in 1995, is a company whose primary purpose is to hold interests in energy-based businesses. The company 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, procurement and 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. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

               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 which the Utility is required to consolidate under applicable accounting standards. 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 incorporated by reference into their joint Annual Report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission, or SEC. PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2005, together with the information incorporated by reference into such report, is referred to in this quarterly report as the "2005 Annual Report."

              The Utility served approximately 5.0 million electricity distribution customers and approximately 4.2 million natural gas distribution customers at March 31, 2006. The Utility had approximately $33.7 billion in assets at March 31, 2006 and generated revenues of approximately $3.1 billion in the three months ended March 31, 2006.

               The Utility is regulated primarily by the California Public Utilities Commission, or CPUC, and the Federal Energy Regulatory Commission, or FERC. The Utility's revenues are generated mainly through the sale and delivery of electricity and natural gas at rates set by the CPUC and the FERC. Rates are set to permit the Utility to recover its authorized "revenue requirements" from customers. Revenue requirements are designed to allow the Utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. 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 the 2005 Annual Report. Significant developments that have occurred since the 2005 Annual Report was filed with the SEC are discussed in this report.

Factors Affecting Financial Condition and Results of Operations

               Several factors have had, and are expected to continue to have, a significant impact on PG&E Corporation's and the Utility's financial condition and results of operations, including:

· Issuance of Energy Recovery Bonds - During 2005, PG&E Energy Recovery Funding LLC, a limited liability company wholly owned by the Utility, or PERF, issued two separate series of Energy Recovery Bonds, or ERBs, for an aggregate amount of approximately $2.7 billion. In February 2005, the proceeds of the first series of ERBs in the amount of $1.9 billion were used to refinance the after-tax portion of the settlement regulatory asset established by the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC to resolve the Utility's Chapter 11 proceeding, or the Settlement Agreement. As a result, the Utility's net income for the three months ended March 31, 2006, was reduced by approximately $12 million as compared to the same period in 2005, when the Utility earned its authorized 11.22% return on equity, or ROE, on the after-tax portion of the settlement regulatory asset. The November 2005 issuance of the second series of ERBs in the amount of $844 m illion was used to pre-fund the Utility's tax liability that will be due as the Utility collects the dedicated rate component, or DRC, used to secure repayment of the ERBs from its customers. Until these taxes are fully paid, the Utility provides customers a carrying cost credit. The equity portion of this carrying cost credit reduced the Utility's 2006 net income for the three months ended March 31, 2006, by approximately $15 million, as compared to the same period in 2005;

· Improved Capital Structure - In January 2005, the equity component of the Utility's capital structure reached 52%, the target specified in the Settlement Agreement. Since this allowed the Utility to restore dividends and repurchase shares held by PG&E Corporation, PG&E Corporation reinstated the payment of a regular quarterly dividend. For 2006, the CPUC has authorized the equity component of the Utility's capital structure to remain at 52% and has set a ROE for 2006 of 11.35%. The Utility has requested the CPUC to waive the requirement for the Utility to file a 2007 cost of capital application. Instead, the Utility has requested the CPUC to authorize the same cost of capital and capital structure for 2007 as it has authorized for 2006;

· Stock Repurchases - On November 16, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement, or ASR, with Goldman Sachs & Co., Inc., or GS&Co., under which PG&E Corporation repurchased a total of 31,650,300 shares of common stock. On March 28, 2006, obligations with respect to the share forward component of the ASR were terminated. On the same date, PG&E Corporation entered into a new share forward agreement with GS&Co. to complete the ASR. In connection with the termination, PG&E Corporation paid GS&Co. $58 million, net of certain payments by GS&Co. to PG&E Corporation. Under the new share forward agreement, PG&E Corporation and GS&Co. will continue to be required to make certain payments, including a price adjustment with respect to the remaining shares subject to the agreement. The aggregate amounts of the payments required of each of the parties, including the amount of the price adjustment, ca nnot be determined until June 8, 2006. Based on the market price of PG&E Corporation common stock at March 31, 2006, PG&E Corporation would have an obligation to GS&Co. of approximately $49.6 million upon the completion of the March 2006 share forward. Any amounts that are due under the share forward can be settled, at PG&E Corporation's option, in cash, in shares of its common stock, or a combination of the two;

· The Outcome of Regulatory Proceedings, including the 2007 General Rate Case - Various regulatory proceedings are pending at the FERC and the CPUC, including the Utility's 2007 General Rate Case, or GRC, pending at the CPUC to determine the amount of the Utility's authorized base revenues to be collected from customers for the period 2007 through 2009. In the GRC, the Utility has requested increases in its 2007 revenue requirements for its electric distribution and existing electric generation operations, and for its natural gas distribution operations of $389 million and $44 million, respectively, over the authorized 2006 revenue requirements. The Utility also has requested attrition increases for 2008 and 2009. Other parties have recommended lower amounts (see "Regulatory Matters" below);

· The Success of the Utility's Strategy to Achieve Operational Excellence and Improved Customer Service - During 2006, the Utility is continuing to undertake various initiatives to implement changes to its business processes and systems in an effort to provide better, faster and more cost-effective service to its customers. The Utility aims to achieve these goals in a three- to five-year period. The Utility's 2007 GRC application included a proposed mechanism to share with customers savings that may be achieved through implementation of these initiatives. In addition, the Utility's 2007 GRC application includes a proposal to replace the current incentive mechanism for reliability performance for the 2007-2009 period with a new customer service performance incentive mechanism. Under the proposal, the Utility would be rewarded or penalized up to $60 million per year to the extent that the Utility's actual performance exceeds or falls short of pre-set annual performance improvement targ ets over the 2007-2009 period (see "Regulatory Matters" below);

· The Amount and Timing of Capital Expenditures - The Utility has requested, in various proceedings including the 2007 GRC, that the CPUC approve various capital expenditures to fund (1) investments in transmission and distribution infrastructure needed to serve its customers (i.e., to extend the life of existing infrastructure, to replace existing infrastructure, and to add new infrastructure to meet load growth), (2) the installation of advanced meters, and (3) investment in new long-term generation resources, as may be authorized by the CPUC in accordance with the Utility's long-term electricity procurement plan. As discussed below under "Capital Expenditures," it is estimated that the Utility's capital expenditures will average approximately $2.5 billion annually from 2006 through 2010, resulting in a projected rate base of approximately $20.7 billion in 2010, reflecting a projected rate base growth of approximately 6.3% per year;

· Proposed New Long-Term Generation Resources - On April 11, 2006, the Utility filed an application with the CPUC seeking approval of seven agreements for new long-term electricity generation resource commitments, including four power purchase agreements and a letter of intent to execute a power purchase agreement that together would provide over 1,400 megawatts, or MW, of capacity to the Utility from new generation facilities that would be owned and operated by other parties. The remaining two contracts provide for the construction by third parties of two new power plants to be owned and operated by the Utility. One contract calls for the construction of a 657 MW power plant and the other contract calls for the construction of a 163 MW power plant at the Utility's Humboldt Bay facility. The Utility anticipates that the CPUC will issue its decision on the Utility's application by the end of the year. Assuming the CPUC approves the agreements and that permitting and construction sched ules are met, the new generation facilities are anticipated to begin delivering power to the grid during the 2009 through 2010 time-frame. In addition, the Utility's application seeking approval to acquire and build a 530 MW power plant to be located in Contra Costa County, or Contra Costa Unit 8, is still pending at the CPUC. The estimated capital expenditures described in the previous paragraph do not include any estimated amounts for new long-term generation resources, other than estimated amounts for the proposed Humboldt Bay and Contra Costa Unit 8 power plants;

· Chromium Litigation Settlement - On April 21, 2006, the Utility paid approximately $295 million to settle most of the claims involving allegations that exposure to chromium at or near some of the Utility's natural gas compressor stations caused personal injuries, wrongful deaths, or other injuries, referred to as the Chromium Litigation (discussed in Note 11 of the Notes to the Condensed Consolidated Financial Statements). PG&E Corporation and the Utility had previously accrued $314 million for the settlement and they do not believe that the outcome of the remaining unresolved claims in the Chromium Litigation will have a material adverse effect on their future results of operations or financial condition; and

· The Outcome of the CPUC's Investigation into the Utility's Billing and Collection Practices - PG&E Corporation and the Utility are unable to predict the outcome of the CPUC's investigation into the Utility's billing and collection practices as discussed below under "Regulatory Matters." In light of the recommended refunds and penalties, the outcome of the investigation could have a material adverse effect on their future results of operations or financial condition (see Note 11 of the Notes to the Condensed Consolidated Financial Statements).

Forward-Looking Statements

               This combined Quarterly Report on Form 10-Q, including 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 date of this report. These forward-looking statements are identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "might," "should," "would," "could," "goal," "potential" and similar expressions. PG&E Corporation's and the Utility's results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. 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, are discussed in the section of the 2005 Annual Report entitled "Risk Factors." These factors include, but are not limited to:

Operating Environment

· How the Utility manages its responsibility to procure electric capacity and energy for its customers, which can be affected by, among other factors, the extent to which the Utility's distribution customers are permitted to switch between purchasing electricity from the Utility or from alternate energy service providers as direct access customers or from cities, counties and others in the Utility's service territory as community choice aggregators, potentially resulting in stranded generating asset costs and non-recoverable procurement costs;

· The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its customers;

· Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards that affect demand for electricity or natural gas, result in power outages, reduce generating output, disrupt natural gas supply, cause damage to the Utility's assets or generating facilities, cause damage to the operations or assets of third parties on which the Utility relies, or subject the Utility to third party claims for damage or injury;

· Unanticipated population growth or decline, general economic and financial market conditions, changes in technology including the development of alternative energy sources, all of which may affect customer demand for natural gas or electricity;

· Whether the Utility is required to cease operations temporarily or permanently at its Diablo Canyon nuclear power plant, or Diablo Canyon, because the Utility is unable to increase its on-site spent nuclear fuel storage capacity, find another depositary for spent fuel, or timely complete the replacement of the steam generators, or because of mechanical breakdown, lack of nuclear fuel, environmental constraints, or for some other reason and the risk that the Utility may be required to purchase electricity from more expensive sources; and

· Whether the Utility is able to recognize the anticipated cost benefits and savings expected to result from its efforts to improve customer service through implementation of specific initiatives to streamline business processes and deploy new technology.

Legislative Actions and Regulatory Proceedings

· The outcome of the regulatory proceedings pending at the CPUC and the FERC, including those discussed in "Regulatory Matters" below, and the impact of future ratemaking actions by the CPUC and the FERC;

· The impact of the recently enacted Energy Policy Act of 2005 which, among other provisions, repeals the Public Utility Holding Company Act of 1935 making electric utility industry consolidation more likely; expands the FERC's authority to review proposed mergers; changes the FERC regulatory scheme applicable to qualifying co-generation facilities, or QFs; authorizes the formation of an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards; and modifies certain other aspects of energy regulation and federal tax policies applicable to the Utility;

· The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity or gas 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 assets;

· How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's past decisions permitting the establishment of holding companies for the California investor-owned electric utilities and the outcome of the CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates, which may include (1) establishing reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changing the CPUC's affiliate transaction rules;

· Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, including tariffs related to the Utility's billing and collection practices as discussed below in "Regulatory Matters," and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses, such as has been recommended with respect to the CPUC's investigation into the Utility's billing and collection practices; and

· Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities, including the Utility's natural gas compressor stations, to comply with existing and future environmental laws, regulations and policies.

Pending Litigation

· The outcome of pending litigation.

Municipalization and Bypass

· Continuing efforts by local public utilities to take over the Utility's distribution assets through exercise of their condemnation power or by duplication of the Utility's distribution assets or service, and other forms of municipalization that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery.

               See the section entitled "Risk Factors" in the 2005 Annual Report for further discussion of the more significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future financial condition and results of operations.

RESULTS OF OPERATIONS

               The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three-month periods ended March 31, 2006 and 2005.

	Three Months Ended
	March 31,
	2006		2005
(in millions)
Utility
Electric operating revenues	$	1,863	$	1,660
Natural gas operating revenues		1,285		1,009
Total operating revenues		3,148		2,669
Cost of electricity		530		396
Cost of natural gas		873		620
Operating and maintenance		862		773
Depreciation, amortization and decommissioning		413		385
Total operating expenses		2,678		2,174
Operating income		470		495
Interest income		19		20
Interest expense		(146)		(154)
Other income, net(1)		3		-
Income before income taxes		346		361
Income tax provision		132		142
Income available for common stock	$	214	$	219
PG&E Corporation, Eliminations and Other(2)
Operating revenues	$	-	$	-
Operating expenses		1		(6)
Operating income (loss)		(1)		6
Interest income		4		1
Interest expense		(8)		(7)
Other expense, net(1)		(3)		(1)
Loss before income taxes		(8)		(1)
Income tax benefit		(8)		-
Net income (loss)	$	-	$	(1)
Consolidated Total
Operating revenues	$	3,148	$	2,669
Operating expenses		2,679		2,168
Operating income		469		501
Interest income		23		21
Interest expense		(154)		(161)
Other expenses, net(1)		-		(1)
Income before income taxes		338		360
Income tax provision		124		142
Net income	$	214	$	218
(1)Includes preferred stock dividend requirement as other expense.
(2)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 differences between actual sales or demand compared to forecasted sales or demand used in setting rates. The CPUC and the FERC determine the amount of "revenue requirements" the Utility is authorized to collect from its customers to recover the Utility's operating and capital costs and earn a fair return. Revenue requirements are primarily determined based on the Utility's forecast of future costs, including the costs of purchasing electricity and natural gas on behalf of the Utility's customers.

The Utility's primary revenue requirement proceeding is the GRC filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from customers an amount known as base revenues to recover basic business and operational costs related to the Utility's electricity and natural gas distribution and electricity generation operations. The GRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedings based on a forecast of costs for the first, or test, year. In the past, the CPUC has authorized future revenue requirement adjustments (attrition adjustments) in the second or third year of the GRC cycle. In addition, the CPUC generally conducts an annual cost of capital proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in the Utility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debt that the Utility will collect in its authorized rates. The CPUC also has established ratemaking mechanisms to permit the Utility to timely recover its costs to procure electricity and natural gas on behalf of its customers in the energy markets.

The Utility's electricity and natural gas distribution and electric generation rates reflect the sum of individual revenue requirement components authorized by the CPUC. 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 the section entitled "Regulatory Matters" in the 2005 Annual Report. Developments that have occurred in significant regulatory proceedings discussed in the 2005 Annual Report and significant new regulatory matters that have been initiated since the 2005 Annual Report was filed with the SEC are discussed below in the section entitled "Regulatory Matters." Each year the Utility requests the CPUC to authorize an adjustment to electric and gas rates effective on t he first day of the following year to (1) reflect over- and under- collections in the Utility's major electric and gas balancing accounts, and (2) consolidate various other electricity and gas revenue requirement changes authorized by the CPUC or the FERC. Balances in all accounts authorized for recovery are subject to review, verification, and adjustment, if necessary, by the CPUC.

The timing of the CPUC and other regulatory decisions affect when the Utility is able to record the authorized revenues. In the 2007 GRC, the Utility requested the CPUC to approve an increase in 2007 electric and gas revenue requirements over the amount authorized for 2006 in the last GRC, as discussed below. The Utility has requested the CPUC to issue a decision in the 2007 GRC before the end of 2006 so the Utility can begin to record any authorized changes to revenues on January 1, 2007. The Utility has also requested attrition adjustments for 2008 and 2009. Further, the Utility has requested the CPUC waive the requirement for the Utility to file a cost of capital application for 2007 and to maintain the Utility's 2006 authorized cost of capital and capital structure.

               The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transmission capacity that is not subscribed under long-term contracts with fixed reservation charges to core customers or other long-term contract holders (see further discussion in the Transportation and Storage section in the section entitled "Risk Management Activities" of the 2005 Annual Report). In addition, the Utility is 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.

Electric Operating Revenues

               The Utility's electricity rates are determined based on its cost of service.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.

               In addition to electricity provided by the Utility's own generation facilities and electricity provided under the Utility's power purchase agreements with third party providers, the Utility relies on electricity provided under long-term electricity procurement contracts entered into in 2001 through December 2002 with the California Department of Water Resources, or the DWR, to meet a material portion of its customers' demand. Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Condensed Consolidated Statements of Income, reflecting the Utility's role as a billing and collection agent for the DWR's sales to the Utility's customers. Changes in the DWR's revenue requirements will not affect the Utility's revenues. Although the Utility is permitted to pass through the DWR charges to customers, any changes in the amount of DWR charges that the Utility's customers are re quired to pay can affect regulatory willingness to increase overall rates to permit the Utility to recover its own costs. As overall rates rise or decline, there may be changes regarding the risk of regulatory disallowance of costs.

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 re corded as a reduction to the cost of electricity.

               The following table provides a summary of the Utility's electric operating revenues:

		Three Months Ended
		March 31,
(in millions)		2006		2005
Electric revenues		$	2,239	$	2,084
DWR pass-through revenue		(513)		(446)
Subtotal		1,726		1,638
Miscellaneous		137		22
Total electric operating revenues		$	1,863	$	1,660
Total electricity sales (in GWh) (1)			19,914		19,034
(1)	Includes DWR electricity sales.

For the three months ended March 31, 2006, the Utility's electric operating revenues increased by approximately $203 million, or 12%, compared to the same period in 2005 mainly due to the following factors:

· Attrition adjustments, as authorized in the 2003 GRC, in which the CPUC approved the minimum and maximum yearly adjustments to the Utility's 2003 base revenue requirements, increased electric operating revenues by approximately $30 million;

· The DRC charge related to the ERBs increased electric operating revenues by approximately $87 million (see further discussion in Note 4 of the Notes to the Condensed Consolidated Financial Statements). During the first quarter of 2005, the Utility began collection of the DRC for the first series of ERBs that were issued on February 10, 2005. During the first quarter of 2006, the Utility collected the DRC associated with the first series of ERBs in addition to the DRC related to the second series of ERBs, issued on November 9, 2005, for the entire quarter;

· Higher transmission revenues, including an increase in revenues as authorized in the FERC transmission rate case (refer to "Regulatory Matters" of this MD&A for further discussion of the FERC transmission rate case), increased electric operating revenues by approximately $30 million;

· Higher electricity procurement costs, which are passed through to customers, increased electric operating revenues by approximately $120 million; and

· Miscellaneous other electric operating revenues, including revenues associated with public purpose programs and advanced metering and demand response programs, increased by approximately $30 million.

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

· A decrease in the revenue requirement associated with the settlement regulatory asset (as discussed in further detail in the 2005 Annual Report) decreased electric operating revenues by approximately $53 million. 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; and

· The carrying cost credit, including both the debt and equity components, associated with the issuance of the second series of ERBs decreased electric operating revenues by approximately $35 million. The second series of ERBs were issued to pre-fund the Utility's tax liability that will be due as the Utility collects the DRC related to the first series from its customers over the term of the ERBs. Until these taxes are fully paid, the Utility provides customers a carrying cost credit, computed at the Utility's authorized rate of return on rate base, to compensate them for the use of proceeds from the second series of ERBs as well as the after-tax proceeds of energy supplier refunds used to reduce the size of the second series of ERBs (see further discussion in the section entitled "Regulatory Matters" in the 2005 Annual Report).

               The Utility's electric operating revenues are expected to increase in 2006 primarily due to an attrition adjustment authorized in the 2003 GRC decision. Revenues for the period 2007 through 2009 would also increase to the extent authorized by the CPUC in the 2007 GRC (for further discussion see "2007 General Rate Case" under "Regulatory Matters" of the MD&A). In addition, revenues associated with the collection of the DRC charge are scheduled to continue through 2012 when the ERBs mature.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities, but excludes costs to operate the Utility's 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 (see "Electric Operating Revenues" above for further details).

The following table provides a summary 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)	2006		2005
Cost of purchased power	$	608	$	452
Proceeds from surplus sales allocated to the Utility	(129)		(100)
Fuel used in owned generation	51		44
Total cost of electricity	$	530	$	396
Average cost of purchased power per GWh	$	0.076	$	0.065
Total purchased power (GWh)	7,956		6,985

The Utility's cost of electricity increased by approximately $134 million, or 34%, in the three months ended March 31, 2006 as compared to the same period in 2005, mainly due to the following factors:

· An increase in the cost of purchased power of approximately $156 million, or 35%, that resulted primarily from both an increase in the average cost of purchased power of $0.011 per Gigawatt hours, or GWh, and an increase in the volume of total purchased power of 971 GWh. The volume of total purchased power increased mainly due to an increase in customer usage and a decrease in the volume of electricity provided by the DWR to the Utility's customers; and

· An increase in the cost of fuel used in the Utility's owned generation of approximately $7 million resulted in a corresponding increase in the cost of electricity.

               During the three months ended March 31, 2006, the Utility received approximately $29 million more than it received in the same period in 2005 for sales of surplus electricity which partially offset the increases in costs of electricity discussed above.

               The Utility's cost of electricity in 2006 will depend upon electricity prices, the duration of the Diablo Canyon refueling outage, and any change in customer usage which will directly impact the Utility's net open position (see the "Risk Management Activities" section of this MD&A). Cost of electricity is also dependent upon weather patterns and seasonality. The above average rainfall in the first quarter of 2006 is expected to increase hydroelectric energy production for the remainder of the year. As hydroelectric production is typically purchased at lower prices than spot market purchases, this may decrease the cost of electricity, assuming customer usage does not increase heavily during the remainder of the year. Additionally, increased hydroelectric production may result in an increase in proceeds from surplus sales causing a corresponding decrease in cost of electricity.

Natural Gas Operating Revenues

               The Utility sells natural gas and natural gas transportation (transmission and distribution) services to its customers. The Utility's transportation system transports gas throughout California to the Utility's distribution system, which, in turn, delivers gas to end-use customers. The Utility's natural gas customers consist of two categories: core and non-core customers. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial and larger commercial natural gas customers. The Utility provides natural gas delivery services to all core and non-core 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.

The Utility's natural gas transmission and storage rates for the 2005 through 2007 period have been determined by a December 2004 CPUC decision which approved the Gas Accord III Settlement Agreement reached among the Utility and other interested parties. Under the Gas Accord III Settlement Agreement, the Utility agreed to not have a balancing account for the over-collections or under-collections of natural gas transmission or storage revenues, thus assuming the risk of not recovering its full natural gas transmission and storage costs that are not covered by long-term contracts with fixed reservation charges with its core customers or other customers (see discussion under "Risk Management Activities - Transportation and Storage" in the 2005 Annual Report). Under the terms of the Gas Accord III Settlement Agreement, the Utility will establish gas trans mission and storage rates for 2008 (and possibly subsequent years) in its Gas Transmission and Storage 2008 Rate Case, which the Utility must file no later than February 9, 2007.

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

               The following table provides a summary of the Utility's natural gas operating revenues:

	Three Months Ended
	March 31,
(in millions)	2006		2005
Bundled natural gas revenues	$	1,217	$	944
Transportation service-only revenues	68		65
Total natural gas operating revenues	$	1,285	$	1,009
Average bundled revenue per Mcf of natural gas sold	$	11.75	$	8.77
Total bundled natural gas sales (in millions of Mcf)		104		108

               The Utility's natural gas operating revenues increased by approximately $276 million, or 27%, during the three months ended March 31, 2006 compared to the same period in 2005. The increase in natural gas operating revenues was primarily due to the following factors:

· Excluding the impact of the 2003 GRC decision, 2006 cost of capital proceeding, and miscellaneous other natural gas operating revenues as discussed below, bundled natural gas operating revenues increased by approximately $241 million, or 26%. This increase was primarily due to an increase in the cost of natural gas, which the Utility is permitted by the CPUC to pass on to its customers through higher rates, resulting in an increase in the average bundled revenue per thousand cubic feet, or Mcf, of natural gas sold of approximately $2.87 per Mcf, or 33%, partially offset by a decrease in volume of approximately 4 million Mcf, or 4%;

· Attrition adjustments, as authorized in the 2003 GRC, and revenues authorized in the 2006 cost of capital proceeding increased natural gas operating revenues by approximately $9 million;

· Miscellaneous other natural gas operating revenues increased by approximately $23 million; and

· Transportation service-only revenues increased by approximately $3 million, or 5%, primarily as a result of an increase in rates.

The Utility's natural gas revenues in 2006 are expected to increase due to an attrition rate increase authorized in the 2003 GRC decision and an annual rate escalation authorized in the Gas Accord III Settlement, and will be further impacted by changes in the cost of natural gas.

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 operating and maintaining the Utility's intrastate pipeline, which are included in operating and maintenance expense.

The following table provides a summary of the Utility's cost of natural gas:

	Three Months Ended
	March 31,
(in millions)	2006		2005
Cost of natural gas sold	$	837	$	584
Cost of natural gas transportation	36		36
Total cost of natural gas	$	873	$	620
Average cost per Mcf of natural gas sold	$	8.05	$	5.41
Total natural gas sold (in millions of Mcf)		104		108

               The Utility's total cost of natural gas increased by approximately $253 million, or 41%, in the three months ended March 31, 2006 as compared to the same period in 2005, primarily due to an increase in the average market price of natural gas purchased of approximately $2.64 per Mcf, or 49%, partially offset by a decrease in volume of 4 million Mcf, or 4%.

The Utility's cost of natural gas sold in 2006 will be primarily affected by the prevailing costs of natural gas, which are determined by North American regions that supply the Utility. In October 2005, the CPUC granted the Utility authority to execute hedges on behalf of the Utility's core gas customers, and to record the costs and any payouts of such hedges in a separate balancing account, outside of CPIM. This action was undertaken because of rapidly rising natural gas prices in the wake of Hurricanes Katrina and Rita. The CPUC's decision authorizes enhanced hedging activity on behalf of core customers for the winter of 2005 through 2006 and for two subsequent winters. The Utility has agreed to forego a shareholder award for the CPIM year ending October 31, 2005 (for further discussion see "Risk Management" section of the MD&A in the 2005 Ann ual Report). The cost of gas will also be affected by customer demand.

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. Generally, these expenses are recoverable from customers through rates.

               During the three months ended March 31, 2006, the Utility's operating and maintenance expenses increased by approximately $89 million, or 12%, compared to the same period in 2005, mainly due to the following factors:

· An increase of approximately $40 million related to administrative and general salary expenses reflecting increased costs associated with base salaries and incentives;

· An increase of approximately $30 million related to administrative expenses for low-income customer assistance programs, the Self-Generation Incentive Program, Advanced Metering Infrastructure, or AMI, and community outreach programs; and

· An increase of approximately $10 million related to outside consulting, contract expense, and various programs and initiatives including strategies to achieve operational excellence and improved customer service.

               The Utility's operating and maintenance expenses in 2006 are expected to increase as a result of increased expenses related to various programs and initiatives including public purpose programs and strategies to achieve operational excellence and improved customer service (see "Overview" section in this MD&A for further discussion). In addition, operating and maintenance expenses are influenced by wage inflation, benefits, property taxes, the timing and length of Diablo Canyon refueling outages, environmental remediation costs that cannot be recovered through rates, legal costs and various other administrative and general expenses.

Depreciation, Amortization and Decommissioning

The Utility charges the original cost of retired plant less salvage value to accumulated depreciation upon retirement of plant in service for its lines of business that apply Statement of Financial Accounting Standards, or SFAS, No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended, which includes electricity and natural gas distribution, electricity generation and transmission, and natural gas transportation and storage.

In the three months ended March 31, 2006, the Utility's depreciation, amortization and decommissioning expenses increased by $28 million, or 7%, compared to the same period in 2005, primarily as a result of an increase in the amortization of the ERB regulatory asset by approximately $70 million. During the first quarter of 2005, the Utility began amortizing the ERB regulatory assets related to the first series of ERBs that were issued on February 10, 2005. During the first quarter of 2006, the Utility amortized the ERB regulatory assets for the first series of ERBs as well as the second series of ERBs, issued on November 9, 2005, for the entire quarter.

               This increase was partially offset by the decrease in amortization of the settlement regulatory asset resulting from the refinancing of the settlement regulatory asset by the issuance of the first series of ERBs. The Utility recorded approximately $35 million in the three months ended March 31, 2005 for amortization of the settlement regulatory asset, with no similar amount in 2006.

The Utility's depreciation, amortization and decommissioning expenses in 2006 are expected to increase as a result of an overall increase in capital expenditures.

Interest Income

               In the three months ended March 31, 2006, interest income decreased by approximately $1 million, or 5%, compared to the same period in 2005. The CPUC authorized the Utility to record reasonable net interest costs relating to energy supplier claims to the Energy Recovery Bond Balancing Account, or ERBBA, for recovery, commencing with the issuance of the first series of ERBs on February 10, 2005 (see "Regulatory Matters" in the MD&A of the 2005 Annual Report for further discussion). In 2005, the interest income associated with the disputed claims balance held in escrow was not recorded to the ERBBA for recovery until the second quarter of 2005, retroactive to the issuance date of the first series of ERBs. As such, interest income for the first quarter of 2005 included interest income on the disputed claims balance held in escrow. In 2006, this interest income was recorded to the ERBBA for the entire quarter. T his decrease was partially offset by an increase in interest rates during the period.

               The Utility's interest income during 2006 will be primarily affected by interest rate levels.

Interest Expense

               In the three months ended March 31, 2006, the Utility's interest expense decreased by approximately $8 million, or 5%, compared to the same period in 2005, primarily due to a decrease of approximately $25 million as a result of net interest costs relating to energy supplier claims being recorded to the ERBBA for recovery, as authorized by the CPUC, instead of interest expense (see further discussion in "Interest Income" above). In 2005, interest expense relating to energy supplier claims was not recorded to the ERBBA for recovery until the second quarter of 2005, retroactive to the issuance date of the first series of ERBs. As such, interest expense for the first quarter of 2005 included the interest expense relating to energy supplier claims. In 2006, interest expense was recorded to the ERBBA for the entire quarter, resulting in a decrease in interest expense.

               This decrease was partially offset by an increase of approximately $18 million related to interest associated with the first and second series of ERBs which were issued on February 10, 2005 and November 9, 2005, respectively. Interest expense increased during the three months ended March 31, 2006, as compared to the same period in 2005, as interest expense associated with the ERBs was not incurred until after issuance of each series of bonds in 2005, resulting in interest being recorded for only a portion of the quarter in 2005 for the first series of ERBs, as compared to interest being recorded for both the first and second series of ERBs for a three month period in 2006.

               The Utility's interest expense in 2006 is expected to increase due to higher expected financing resulting from an overall increase in infrastructure investments.

Income Tax Expense

               In the three months ended March 31, 2006, the Utility's tax expense decreased approximately $10 million, or 7%, compared to the same period in 2005, primarily due to a decrease in pre-tax income of approximately $16 million, or 4%, and increased fixed asset deductions. The effective tax rate decreased approximately 1.1 percentage points. This decrease is due mainly to the regulatory treatment of property items.

PG&E Corporation, Eliminations and Other

Operating Revenues and Expenses

               PG&E Corporation's revenues consist mainly of billings to the Utility and its other affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to its affiliates. Operating expenses are allocated to affiliates without mark-up and are eliminated in consolidation.

               The increase in operating expenses of $7 million was primarily due to an increase in administrative and general expenses for the three months ended March 31, 2006, as compared to the same period in 2005.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

               The level of PG&E Corporation's and the Utility's current assets and current liabilities is subject to fluctuation as a result of seasonal demand for electricity and natural gas, energy commodity costs, and the timing and effect of regulatory decisions and financings, among other factors.

               PG&E Corporation and the Utility manage liquidity and debt levels in order to meet expected operating and financial needs and maintain access to credit for contingencies. PG&E Corporation and the Utility intend to manage the Utility's equity level to maintain the Utility's 52% authorized common equity ratio of the Utility's capital structure.

               At March 31, 2006, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $903 million and restricted cash of approximately $1.5 billion. PG&E Corporation and the Utility maintain separate bank accounts. At March 31, 2006, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $299 million; the Utility had cash and cash equivalents of approximately $604 million, and restricted cash of approximately $1.5 billion. The Utility's restricted cash includes amounts deposited in escrow related to the remaining disputed Chapter 11 claims 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.

               As of March 31, 2006, PG&E Corporation and the Utility had credit facilities totaling $200 million and $2 billion, respectively, with remaining borrowing capacity under these credit facilities of $200 million and $1.8 billion, respectively. In January 2006, the Utility established a $1 billion commercial paper program. Because the Utility has same-day access to liquidity through the commercial paper program, it no longer needs to hold material levels of unrestricted cash. At March 31, 2006, the Utility had no outstanding borrowings under the commercial paper program.

               During the three months ended March 31, 2006, the Utility used cash in excess of amounts needed for operations, debt service, capital expenditures, and preferred stock requirements to pay a quarterly common stock dividend.

               Depending on the timing and amount of capital expenditures and liquidity needs, PG&E Corporation may use cash available after capital expenditures and dividends to repurchase shares using cash distributions received from the Utility, and cash available from option exercises. PG&E Corporation anticipates over the next five years it may issue shares (possibly through a combination of employee plans and direct issuance to the market) and contribute the proceeds to the Utility to fund capital expenditures in years of higher capital expenditures while it may repurchase shares in years with lower capital expenditures. Over the five year period, these share issuances and repurchases are expected to approximately offset each other and result in no net issuance of equity.

Dividends

               On February 15, 2006, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.33 per share payable on April 15, 2006 to shareholders of record on March 31, 2006. On February 15, 2006, the Board of Directors of the Utility declared a common stock dividend in the aggregate amount of $124 million that was paid on February 16, 2006, which is consistent with the dividend target. Approximately $115 million of the common stock dividends were paid to PG&E Corporation and the remainder were paid to PG&E Holdings, LLC, a wholly owned subsidiary of the Utility.

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

Stock Repurchases

               On March 28, 2006, the obligations of PG&E Corporation and GS&Co. with respect to the share forward agreement related to the November 16, 2005 ASR (under which PG&E Corporation repurchased and retired 31,650,300 shares of its outstanding common stock) was terminated in accordance with its terms as a result of a declaration of the PG&E Corporation common stock dividend payable on April 15, 2006. In connection with the termination, on March 31, 2006, PG&E Corporation paid GS&Co. approximately $58 million (net of amounts payable by GS&Co. to PG&E Corporation), including a price adjustment based on the daily volume weighted average price, or VWAP, of PG&E Corporation common stock from November 17, 2005 through March 28, 2006. Because the price adjustment and any additional payment obligations could be settled, at PG&E Corporation's option, in cash or in shares of its common s tock, or a combination of the two, PG&E Corporation accounted for its payment obligation as equity. Accordingly, approximately 1.5 million additional shares of PG&E Corporation common stock that were potentially issuable under the terminated share forward agreement were treated as outstanding for purposes of calculating diluted earnings per common share, or EPS, for the quarter ended March 31, 2006.

               On March 28, 2006, PG&E Corporation entered into a new share forward agreement with GS&Co. to complete the ASR. Under the new share forward agreement, PG&E Corporation and GS&Co. will continue to be required to make certain payments, including a price adjustment based on the VWAP from March 29, 2006 through June 8, 2006. The price adjustment and any additional payment obligations that PG&E Corporation or GS&Co. may incur can be settled, at PG&E Corporation's option, in cash or in shares of its common stock, or a combination of the two. Accordingly, PG&E Corporation accounts for its payment obligations under the new share forward agreement as equity.

               PG&E Corporation must calculate the number of shares that would be required to satisfy its obligations upon completion of the share forward agreement based on the market price of PG&E Corporation's common stock at the end of the reporting period. Over the remaining term of the new share forward agreement, for every $1 that the VWAP exceeds $34.75, PG&E Corporation will owe GS&Co. an additional price adjustment of approximately $10.7 million. Conversely, for every $1 that the VWAP is less than $34.75, the price adjustment will be reduced by approximately $10.7 million. Based on the market price of PG&E Corporation common stock at March 31, 2006, PG&E Corporation would have an obligation to GS&Co. of approximately $49.6 million upon the completion of the new share forward agreement. Accordingly, approximately 1.3 million additional shares of PG&E Corporation common stock were treated as outstanding for purposes of calculating diluted EPS for the quarter ended March 31, 2006 (in addition to the 1.5 million shares treated as outstanding under the terminated share forward agreement discussed above).

               For further discussion, see Note 5 of the Notes to the Condensed Consolidated Financial Statements.

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, 2006 and 2005 were as follows:

	Three Months Ended
(in millions)	March 31,
	2006			2005
Net income	$	217		$	223
Non-cash (income) expenses:
Depreciation, amortization, decommissioning and allowance for       equity funds used during construction	401		385
Deferred income taxes and tax credits, net	(27)		(70)
Other deferred charges and noncurrent liabilities	55		(49)
Change in accounts receivable	303		169
Change in accrued taxes	202		220
Change in regulatory balancing accounts, net	(55)		254
Other changes in operating assets and liabilities	(2)		(194)
Net cash provided by operating activities	$	1,094		$	938

               Net cash provided by operating activities increased by approximately $156 million during the three months ended March 31, 2006 compared to the same period in 2005. This is primarily due to the receipt of proceeds associated with settlements with energy suppliers of approximately $170 million during the three months ended March 31, 2006 (see Note 11 of the Notes to the Condensed Consolidated Financial Statements for further discussion).

               In November 2005, the CPUC approved an initiative to help consumers manage high natural gas bills in the winter. The 10/20 Winter Gas Savings Program was a conservation incentive that offered residential and small business customers a 20 percent rebate for reducing their gas usage by 10 percent or more this winter, January through March 2006. The Utility forecasts that this initiative will result in approximately $45 million in rebates to customers. As a result, the Utility's cash inflows will be lower during the second quarter of 2006. However, the Utility expects to recover this cash through rates during April through July 2006.

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 months ended March 31, 2006 and 2005. Year-to-year variances depend upon the amount and type of construction activities, which can be influenced by storms and other factors.

               The Utility's cash flows from investing activities for the three months ended March 31, 2006 and 2005 were as follows:

	Three Months Ended
(in millions)	March 31,
	2006		2005
Capital expenditures	$	(576)	$	(349)
Net proceeds from sale of assets	3		11
Decrease in restricted cash	52		123
Proceeds from nuclear decommissioning trust    sales	435		1,675
Purchases of nuclear decommissioning trust    investments	(477)		(1,673)
Other investing activities	11		24
Net cash used in investing activities	$	(552)	$	(189)

               Net cash used by investing activities increased by approximately $363 million primarily due to an increase in capital expenditures of approximately $227 million for the three months ended March 31, 2006. The Utility estimates that in 2006 it will invest approximately $2.5 billion in plant and equipment (see "Capital Expenditures" section in this MD&A for further discussion).

Financing Activities

               The Utility's cash flows from financing activities for the three months ended March 31, 2006 and 2005 were as follows:

	Three Months Ended
	March 31,
	2006		2005
(in millions)
Borrowings under accounts receivable facility	$	50	$	-
Repayments under working capital facility and accounts receivable facility		(310)		(300)
Net proceeds from energy recovery bonds issued		-		1,874
Long-term debt, matured, redeemed or repurchased		-		(900)
Rate reduction bonds matured		(74)		(74)
Energy recovery bonds matured		(56)		-
Common stock dividends paid		(115)		(110)
Preferred dividends paid		(3)		(4)
Preferred stock with mandatory redemption provisions redeemed		-		(2)
Common stock repurchased		-		(960)
Other financing activities		107		-
Net cash used in financing activities	$	(401)	$	(476)

               For the three months ended March 31, 2006, net cash used in financing activities decreased by approximately $75 million compared to the same period in 2005, primarily due to the following factors:

· In February 2005, PERF issued approximately $1.9 billion of ERBs with no similar issuance in 2006 (see Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion);

· Approximately $56 million of ERBs matured in the first quarter of 2006 with no similar maturities in 2005;

· 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. There was no similar repayment in 2006; 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 with no similar repurchase in 2006.

PG&E Corporation

               As of March 31, 2006, PG&E Corporation had stand-alone cash and cash equivalents of approximately $299 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 approximately $124 million to PG&E Corporation and PG&E Holdings LLC on February 16, 2006.

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, on a stand alone basis, did not have any material operating activities for the three months ended March 31, 2006 and 2005.

Investing Activities

               PG&E Corporation, on a stand alone basis, did not have any material investing activities for the three months ended March 31, 2006 and 2005.

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, 2006 and 2005 were as follows:

	Three Months Ended
	March 31,
	2006		2005
(in millions)
Borrowings under accounts receivable facility	$	50	$	-
Repayments under working capital facility and accounts    receivable facility		(310)		(300)
Net proceeds from issuance of energy recovery bonds		-		1,874
Long-term debt matured, redeemed or repurchased		-		(902)
Rate reduction bonds matured		(74)		(74)
Energy recovery bonds matured		(56)		-
Preferred stock with mandatory redemption provisions    redeemed		-		(2)
Common stock issued		66		120
Common stock repurchased		(58)		(1,065)
Preferred dividends paid		(3)		(4)
Common stock dividends paid		(114)		-
Other		112		-
Net cash used by financing activities	$	(387)	$	(353)

               For the three months ended March 31, 2006, PG&E Corporation's consolidated net cash used by financing activities increased by approximately $34 million, compared to the same period in 2005. The increase is primarily due to the fourth quarter 2005 common stock dividend payment on January 16, 2006, after consideration of the Utility's cash flows from financing activities.

CONTRACTUAL COMMITMENTS

               PG&E Corporation and the Utility enter into contractual obligations and commitments in connection with business activities. These future obligations 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 activities. Refer to Notes 4 and 11 in the Notes to the Condensed Consolidated Financial Statements and the 2005 Annual Report for further discussion.

Utility

               The Utility's contractual commitments include power purchase agreements (including agreements with qualifying facilities, irrigation districts and water agencies, and renewable energy providers), natural gas supply and transportation agreements, nuclear fuel agreements, operating leases, and other commitments (see the section entitled "Regulatory Matters - Electricity Generation Resources" below for a discussion of new power purchase agreements the Utility has entered into that the Utility has submitted to the CPUC for approval).

CAPITAL EXPENDITURES

                The Utility's investment in plant and equipment totaled approximately $1.9 billion in 2005, resulting in a weighted average rate base of $15.1 billion for the year ended December 31, 2005. The Utility estimates that in 2006 it will invest $2.5 billion in plant and equipment, resulting in a projected weighted average rate base of $15.9 billion for the year ended December 31, 2006. Over the next five years (2006 through 2010), the Utility projects average annual capital expenditures of approximately $2.5 billion, including potential investments associated with the Utility's proposals to implement an AMI; to acquire and develop the Contra Costa Unit 8 power plant; and to own and operate a new 163 MW power plant to be built by a third party at the Utility's Humboldt Bay facility. A significant portion of these projected capital expenditures (including those associated with AMI, the Utility's electricity and gas di stribution and existing generation businesses over the 2007 through 2009 period, and proposed investments in new generation resources) are subject to CPUC approval. As discussed below under "Regulatory Matters - Electricity Generation Resources," the Utility also has requested that the CPUC approve an agreement for a third party to build a new 657 MW power plant that would be owned and operated by the Utility. Potential capital expenditures associated with this proposed project are not included in the projections discussed above.

AMI

               The Utility estimates that deployment of AMI will cost approximately $227 million in 2006, including an estimated capital cost of $147 million, based on the installation schedule for its electric and gas customers. The Utility anticipates that the CPUC will issue a decision on the Utility's application for approval of full deployment of its AMI project later in 2006.

Diablo Canyon Steam Generator Replacement Project

               In November 2005, the CPUC approved the Utility's steam generator replacement project, or SGRP, to replace the steam generators at the two nuclear operating units at Diablo Canyon. The Utility plans to replace Unit 2's steam generators in 2008 and replace Unit 1's steam generators in 2009. Because the fabrication of new steam generators requires a long lead-time, in August 2004, the Utility entered into contracts with Westinghouse Electric Company LLC, or Westinghouse, for the design, fabrication and delivery of eight steam generators. Under the contracts, the Utility must pay Westinghouse for all work done and pro-rated profit up to the time the contracts are completed or cancelled. The contracts require progress payments in line with actual expenditures for materials and work completed over the life of the contracts.

               As of March 31, 2006, the Utility had incurred approximately $88 million in connection with the SGRP under various construction and installation contracts the Utility has executed. Based on updated estimates of the cost to complete the SGRP, the Utility estimates it will spend an additional $540 million to complete the SGRP through 2009.

               To implement the SGRP, the Utility requires two permits from San Luis Obispo County; a conditional use permit to store the old generators on site at Diablo Canyon and a coastal development permit to build temporary structures at Diablo Canyon to house the new generators as they are prepared for installation. At a public hearing on January 12, 2006, the San Luis Obispo County Planning Commission denied approval of both permits. The Utility appealed the denials to the Board of Supervisors of San Luis Obispo County at a public hearing on March 7, 2006, and both permits were approved. On March 20, 2006, the Mothers for Peace, along with the Santa Lucia Chapter of the Sierra Club, appealed the Board of Supervisors' approval of both permits to the California Coastal Commission. The Utility expects that the Coastal Commission will issue a decision by the end of 2006.

Off-Balance Sheet Arrangements

               For financing and other business purposes, PG&E Corporation and the Utility utilize certain arrangements that are not reflected in their Condensed Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E Corporation's or the Utility's activities or a significant ongoing source of financing. These arrangements are used to enable PG&E Corporation or the Utility to obtain financing or execute commercial transactions on favorable terms, and amounts due under these contracts are contingent upon terms contained in these arrangements. For further information related to letter of credit agreements, credit facilities, pollution control bond insurance and bank reimbursement agreements, aspects of PG&E Corporation's accelerated share repurchase program, and PG&E Corporation's guarantee related to certain National Energy and Gas Transmission, Inc., or NEGT, inde mnity obligations and the Utility's workers' compensation obligations, see the 2005 Annual Report and Notes 4, 5 and 11 of the Notes to the Condensed Consolidated Financial Statements.

CONTINGENCIES

               PG&E Corporation and the Utility have significant contingencies that are discussed below. Also, refer to Note 11 in the Notes to the Condensed Consolidated Financial Statements for further discussion.

REGULATORY MATTERS

               This section of MD&A discusses developments that have occurred in significant regulatory proceedings discussed in the 2005 Annual Report and significant new regulatory proceedings that have been initiated since the 2005 Annual Report was filed with the SEC.

2007 General Rate Case

               The Utility's 2007 GRC application includes a request for approval of pension contributions of $345 million per year in 2007, 2008 and 2009, and seeks an annual revenue requirement of $216 million to fund the portion of each year's pension contribution attributable to the Utility's distribution and generation businesses. In December 2005, the CPUC approved, in part, the Utility's July 2005 petition, giving the Utility permission to file an application for a pension contribution in 2006 and to begin collecting the requested revenue requirement through rates effective January 1, 2006, subject to refund. On March 8, 2006, the Utility requested that the CPUC approve a proposed pension settlement reached among the Utility, the CPUC's Division of Ratepayer Advocates, or the DRA, and the Coalition of California Utility Employees. The settlement provides for an annual pension-related revenue requirement of $98 million att ributable to distribution and generation operations in 2007, 2008 and 2009 (see the "Defined Benefit Pension Plan Contributions" section of "Regulatory Matters" for further information regarding the 2006 pension contribution settlement).

               On April 14, 2006, the DRA submitted testimony recommending that the Utility's 2007 revenue requirements be set at a level approximately $20 million lower than existing 2006 authorized amounts. The DRA's submission of testimony is part of the regular process in every GRC proceeding. The Utility's current requested increase in electric and gas service revenue requirements for 2007 is $389 million and $44 million, respectively, over the authorized 2006 revenue requirements. The Utility's current request is lower than its original December 2, 2005 request because it reflects increases in the Utility's authorized 2006 revenue requirements that became effective on January 1, 2006, including $155 million that the CPUC authorized the Utility to collect, subject to refund, to fund a 2006 pension contribution, as discussed in the previous paragraph. Further, in accordance with the settlement agreement discussed in the pre vious paragraph, the Utility also has lowered its original request for an annual revenue requirement to fund a pension contribution in 2007, 2008 and 2009 from $216 million to $98 million. The revised pension-related request reflects the increased 2006 revenue requirement and a reduction the Utility agreed to in the settlement agreement. As a result of the lower amounts requested for 2007 and other revisions, the Utility's current request for attrition increases are approximately $143 million for 2008 and $141 million for 2009, which are net of cost savings the Utility estimates will result from the implementation of various initiatives to improve the Utility's business processes and systems.

               The DRA's recommended net reduction in 2007 revenue requirements from the existing 2006 authorized amounts is comprised of a recommended $17 million increase in electric revenue requirements offset by a recommended $37 million decrease in gas revenue requirements. The DRA's recommended 2007 electric and gas revenue requirement reflects approximately $85 million of differences in the Utility's and the DRA's estimates for depreciation expenses. Among other assumptions as to future costs which differ from the Utility's assumptions, the DRA has assumed that the Utility would make fewer capital expenditures and that some capital additions would be made over a longer period of time than the Utility projected in its application. The DRA assumes the Utility's average annual capital expenditures for electric and gas distribution, and existing electric generation over the 2007 through 2009 period would be $1.4 billion, as c ompared to the Utility's projection of average annual capital expenditures of $1.8 billion over the same period. (Capital expenditures related to the GRC do not include projected capital spending related to the proposed AMI project, electric transmission, or proposed new generation resources.) In addition, the DRA recommended attrition increases of $98 million for 2008 and $51 million for 2009.

               As previously disclosed, due to uncertainty about savings to be realized from the implementation of the various initiatives the Utility is undertaking to improve its business processes and systems, the Utility proposed a sharing mechanism in its 2007 GRC application by which shareholders and customers would share equally in any earnings over the amount needed to achieve an ROE on GRC rate base equal to the then-authorized ROE plus 50 basis points. The Utility's customers would receive 100% of the earnings over the amount needed to achieve an ROE equal to the then-authorized ROE plus 300 basis points. If the Utility's actual ROE were less than an amount equal to the then-authorized ROE minus 50 basis points, shareholders and customers would share the shortfall equally.

               The DRA recommended a sharing mechanism by which the Utility's shareholders would receive 100% of the earnings over the amount needed to achieve an ROE on GRC rate base equal to the then-authorized ROE, up to 50 basis points. Customers would receive 75% of the earnings over the amount needed to achieve the then-authorized ROE plus 50 basis points. Shareholders and customers would share equally in any earnings over the amount needed to achieve an ROE equal to the then-authorized ROE plus 150 basis points. If the Utility's actual ROE were less than an amount equal to the then-authorized ROE, shareholders would bear 100% of the earnings shortfall.

               The following table summarizes the Utility's proposed sharing mechanism based on the Utility's 2006 authorized ROE of 11.35%:

ROE	Customer	Shareholder
Below 10.85%	50%	50%
10.85% - 11.85%	0%	100%
11.86% - 14.35%	50%	50%
Above 14.35%	100%	0%

               The following table summarizes the DRA's recommended sharing mechanism for the Utility based on the Utility's 2006 authorized ROE:

ROE	Customer	Shareholder
Below 11.35%	0%	100%
11.35% - 11.85%	0%	100%
11.86% - 12.85%	75%	25%
Above 12.85%	50%	50%

               On April 28, 2006, additional parties, including The Utility Reform Network, or TURN, submitted testimony in the Utility's 2007 GRC proceeding. TURN's testimony recommends forecasts of certain cost items that differ from those the Utility included in its forecasts. In general, TURN has adopted DRA's recommendations. The Utility estimates that TURN's recommendations would result in revenue requirements that are approximately $230 million lower than the amount recommended by the DRA, including a recommended annual depreciation expense that would be approximately $194 million less than the annual depreciation expense recommended by the DRA.

               The CPUC's 2007 GRC schedule provides for a final decision by December 14, 2006 on all issues except the proposed customer service performance incentive mechanism, for which a decision is expected in April 2007. PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the 2007 through 2009 period, if the current schedule calling for a final decision in December 2006 will be maintained, or what the impact of a final 2007 GRC decision will be on their financial condition or results of operations.

Electricity Generation Resources

               California legislation allows the California investor-owned utilities to recover their reasonably incurred wholesale electricity procurement costs. The legislation's mandatory rate adjustment provision requiring the CPUC to adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR) expired on January 1, 2006. In December 2004, in approving the California investor-owned utilities' long-term procurement plans, the CPUC decided it would continue the mandatory rate adjustment mechanism for the length of a utility's resource commitment or 10 years, whichever is longer.

               In the first quarter of 2006 and extending into April 2006, the Utility filed applications with the CPUC requesting approval of seven power purchase agreements, as described below. Five of these power purchase agreements were arranged to secure new generation resources in accordance with the Utility's long-term electricity procurement plan, one power purchase agreement was executed to meet the Utility's resource adequacy requirement, and another agreement was executed to meet the Utility's renewable energy requirements. The Utility has requested that the CPUC approve these power purchase agreements, which call for fixed payments totaling approximately $5 billion over the terms of the contracts. The Utility has requested that these costs, along with other variable costs, be recovered through the Energy Resource Recovery Account. In addition, as described below, the Utility also has executed two agreements for new Utility-owned generation resources which have also been submitted to the CPUC for approval.

New Long-Term Generation Resource Commitments

               As discussed above, as a result of the Utility's request for offers for long-term generation resources, in April 2006, the Utility filed an application with the CPUC requesting approval of five power purchase agreements. Four of the agreements have been executed and the parties have executed a letter of intent to execute the fifth power purchase agreement. Together these power purchase agreements would provide over 1,400 megawatts, or MW, of capacity with terms from 10 to 20 years. Under the power purchase agreements, the Utility would provide the fuel and in return receive the capacity, energy, and all products generated by the new facilities that would be owned and operated by other parties. The letter of intent, entered into with an affiliate of Calpine Corporation, provides that a power purchase agreement (relating to 601 MW of capacity) will be executed upon satisfaction of certain financ ial conditions, including that the associated Calpine affiliate emerge from bankruptcy or transfer the project site to a bankruptcy remote entity. If these conditions are not satisfied by October 2006, the letter of intent will terminate. In addition, the Utility's application included two agreements providing for the construction of generation facilities to be owned and operated by the Utility. One of these agreements calls for the development and construction of a 657 MW power plant. The other agreement calls for the construction of a 163 MW power plant at the Utility's Humboldt Bay facility. The Utility anticipates that the CPUC will issue its decision on the Utility's application by the end of the year. Assuming the CPUC approves the contracts and the permitting and construction schedules are met, the new generation resources are anticipated to begin delivering power to the grid during the 2009 through 2010 time-frame.

               In addition, as discussed under Note 11 of the Notes to the Condensed Consolidated Financial Statements, pursuant to the Utility's settlement with Mirant Corporation and certain of its subsidiaries, or Mirant, the Utility has requested that the CPUC approve an agreement with Mirant implementing one part of the settlement under which the Utility would acquire and complete the Contra Costa Unit 8, a 530 MW power plant. With respect to this request, the Utility has reached a settlement with key consumer groups, though this settlement has been contested by other parties to the proceeding. CPUC action is expected on this application by June 2006.

               The Utility's 2004 long-term procurement plan indicates that the Utility has a long-term generation resource need for up to 2,200 MW of capacity through 2010, based on certain assumptions. Including Contra Costa Unit 8, the Utility has requested the CPUC to approve long-term resources that together exceed the 2,200 MW forecast included in the Utility's long-term procurement plan due to uncertainties regarding the permitting and construction schedules of the proposed resource additions, whether the conditions to the letter of intent discussed above will be met, the retirement of existing aging power plants, and the rate of future load growth. The Utility has requested the CPUC authorize all of the proposed resource additions to maintain a reliable source of generation supplies in northern California.

               In December 2004, in approving the California investor-owned utilities' long-term procurement plans, the CPUC decided that the utilities should be allowed to recover stranded costs for their long-term resource commitments from departing customers, through a non-bypassable charge, for at least ten years from the date of signing a power purchase agreement or the date of commercial operation of a utility-owned power plant. The CPUC also decided that the utilities should be allowed to justify a cost recovery period longer than ten years on a case-by-case basis. In the Utility's application to the CPUC related to the acquisition and completion of Contra Costa Unit 8, the Utility has proposed to recover the non-bypassable charge over 30 years. In addition, the California legislature has added Assembly Bill 380 to the Public Utilities Code, allowing the CPUC to authorize a non-bypassable charge under certain conditions, without specifying an end date. In its application for approval of the seven new agreements to meet the Utility's long-term generation resource needs, the Utility has requested that the CPUC approve the Utility's recovery of a non-bypassable charge for each commitment over the term of each power purchase agreement or expected life of each Utility-owned generation project, as applicable.

               The CPUC also determined that for utility-owned generation resources, the utilities are prohibited from recovering construction costs in excess of their final bid price. If final construction costs are less than the final bid price, the savings would be shared with customers, while any cost overruns would be absorbed by the utilities. In September 2005, the CPUC granted limited rehearing of its determination that construction cost savings should be shared with customers, while any cost overruns would be absorbed by the utilities. In December 2005, the CPUC agreed to revisit its determination regarding the "cost cap" and the sharing of construction cost savings in 2006.

               The CPUC determined that costs of future plant additions and annual operating and maintenance costs for utility-owned generation and similar costs incurred by a utility would be eligible for cost-of-service ratemaking treatment. If the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

Resource Adequacy

               In October 2005, the CPUC issued a decision that sets forth numerous rules in furtherance of the CPUC's resource adequacy policy, including a penalty provision for failure to acquire sufficient capacity needed to meet annual resource adequacy requirements. The penalty is equal to three times the cost of the new capacity the deficient load-serving entity should have secured; however, for 2006 the penalty is set at one-half of the amount. The Utility's CPUC-approved long-term procurement plan forecasts that the Utility will be able to meet future resource adequacy requirements. If the CPUC determines that the Utility has not met the requirements in a particular year, the Utility could be subject to penalties in an amount determined by the CPUC in accordance with the new penalty provision. A subsequent phase of resource adequacy, dealing with local resource adequacy requirements to be implemented in 2007, is ongoing, with an expected decision from the CPUC in June 2006.

               In order to meet its resource adequacy requirements, in the first quarter of 2006, the Utility filed an application with the CPUC requesting approval of a recently executed power purchase agreement that represents approximately 1,500 MW of capacity for the next four years. If approved by the CPUC, this power purchase agreement would contribute towards meeting the Utility's 2007 to 2010 resource adequacy requirements. A CPUC decision is expected in the second quarter of 2006.

Renewable Energy Contracts

               California law established the Renewables Portfolio Standard Program, which requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. To meet the Renewables Portfolio Standard, in the first quarter 2006, the Utility filed an application with the CPUC requesting approval of a power purchase agreement with a term of 20 years for up to 120 MW of capacity. A CPUC decision is expected in the second quarter of 2006.

               The CPUC is assessing the ability of the utilities to achieve the 20% target by 2010 instead of 2017. In its December 2005 supplement to its long-term renewable procurement plan, the Utility stated that, although it expects it will achieve the 20% target through signed contracts by 2010, actual deliveries of renewable power may not comprise 20% of its bundled retail sales by 2010 due to the time required for new project construction. Failure to satisfy the annual procurement targets may result in a CPUC imposed penalty of five cents per kilowatt hour, with an annual penalty cap of $25 million and failure to meet the 20% renewable procurement obligation may result in additional penalties.

               To meet the 20% target, the CPUC has taken steps to facilitate development of the electric transmission infrastructure in California so that providers of renewable energy resources can have greater access to the electricity transmission system. In 2006, the Utility will continue to plan for and begin implementation of various transmission projects, in order to improve access to renewable energy resources, among other purposes.

Qualifying Facility Power Purchase Agreements

               In April 2006, the Utility and the Independent Energy Producers on behalf of certain qualifying facility, or QF, generators, entered into a settlement agreement that would, if approved by the CPUC, resolve several outstanding issues relating to QF policy and pricing issues. The proposed settlement would result in a reduction of above-market energy payments to QFs, establish a new five-year fixed pricing option for renewable QFs, and resolve outstanding QF-related energy crisis pricing issues. The proposed settlement agreement would apply only to those QFs choosing to execute the agreement and would not be binding on all other QF parties. The Utility cannot predict the number of QFs that will execute the settlement agreement, nor can it predict whether the settlement agreement will be approved by the CPUC.

FERC Transmission Rate Cases

               The Utility's electric transmission revenues and wholesale and retail transmission rates are subject to authorization by the FERC. In August 2005, the Utility filed an application with the FERC requesting an annual retail network transmission revenue requirement of approximately $654 million. The revenue requirement became effective March 1, 2006, subject to refund. On April 3, 2006, the Utility filed with the FERC a settlement-in-principle reached with active parties in the rate case that provides for an annual retail network transmission revenue requirement of $606 million which, if accepted by the FERC, would result in an increase of approximately $87 million over previously authorized retail transmission rates. The Utility began accruing approximately $4 million per month for potential refunds in March 2006, which will continue until the FERC approves the settlement-in-principle and rates are adjusted. PG&E Corporation and the Utility are unable to predict whether the settlement agreement will be approved by the FERC.

Scheduling Coordinator Costs

               Before the Independent System Operator, or ISO, commenced operation in 1998, the Utility had entered into several wholesale electric transmission contracts with various governmental entities. After the ISO began operations, the Utility served as the scheduling coordinator, or SC, with the ISO for these existing wholesale transmission customers, or ETCs. The ISO billed the Utility for providing certain services associated with this scheduling. These ISO charges are referred to as "SC costs." The SC costs were historically tracked in the transmission revenue balancing account, or TRBA, in order to recover the SC costs from retail and new wholesale transmission customers, or TO Tariff customers.

In 1999, a FERC administrative law judge ruled that the Utility could not recover the SC costs through the TRBA and instead should seek to recover them from the ETCs. In January 2000, the FERC accepted a filing by the Utility to establish the Scheduling Coordinator Services, or SCS, Tariff, to serve as an alternative mechanism for recovery of the SC costs from the ETCs if the Utility were ultimately unable to recover these costs in the TRBA. The Utility began billing the ETCs in June 2004 for SC charges retroactive to March 31, 1998. In July 2005, the United States Court of Appeals for the District of Columbia Circuit issued an order finding that the Utility was not barred from recovering the SC costs through the TRBA and remanded the matter to the FERC for further action. In December 2005, the FERC issued an order on remand concluding that the Util ity should recover the SC costs through the TRBA mechanism or through bilateral agreements with the ETCs, but could not recover the costs through the SCS Tariff, and terminated the SCS Tariff proceeding.

               In January 2006, the Utility submitted a request for clarification or, alternatively, for rehearing to seek clarification of the FERC's December 2005 order. In particular, the Utility asked that the FERC clarify that the Utility can recover through the TRBA all of the costs it incurred as an SC or, alternatively on rehearing, reverse its decision to terminate the SCS Tariff proceeding. In February 2006, the FERC confirmed that they will rehear the December 2005 order.

               On April 4, 2006, the Utility filed at FERC for recovery through the TRBA of $109 million of SC costs and $47 million of interest for the time period April 1998 through September 30, 2005, to be recovered over three and a half years from TO Tariff customers. The Utility has also filed an advice letter with the CPUC requesting a pass-through of these costs, if approved by FERC, to its retail customers. The Utility cannot predict when a final decision will be received from the FERC or the CPUC. However, PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations, and could have a positive impact of approximately $120 million if the FERC and CPUC approve the recovery of these costs.

Defined Benefit Pension Plan Contribution

               In the Utility's last GRC decision in 2004, the CPUC denied the Utility's request to resume pension contributions based on a finding that the Employee Retirement Income Security Act of 1974 funded status of the Utility's pension plan was in excess of 100%. As of January 1, 2005, the funded status of the pension plan fell below 100% to 98.6%. In December 2005, the CPUC issued a decision that authorized the Utility to file an application for a revenue requirement increase to fund the estimated costs of a pension contribution in 2006. The decision also authorized the Utility to make that revenue increase effective in rates on January 1, 2006, subject to refund depending on the outcome of the application. As a result of the CPUC decision, in December 2005, the Utility filed an application for a 2006 pension contribution requesting a revenue requirement increase of $155 million attributable to its distribution and generation operations to fund a net pension contribution in 2006 of $250 million on a total company basis. Approximately $75 million of the $250 million contribution in 2006, if approved, would be capitalized. The remaining $20 million relates to revenue requirements for gas transmission and storage, for electric transmission, and nuclear decommissioning, which have been or will be addressed in other CPUC or FERC proceedings. As of March 31, 2006, the Utility has not recognized revenue associated with the 2006 pension contribution request pending the final CPUC decision.

               In the 2007 GRC application filed in early December 2005, the Utility included a request for approval of an annual revenue requirement of $216 million in 2007, 2008 and 2009 to fund pension contributions for the Utility's distribution and generation businesses.

               On March 8, 2006, the Utility requested that the CPUC approve a proposed settlement among the Utility, the DRA, and the Coalition of California Utility Employees, or the Settling Parties, that would permit the Utility to recover revenue requirements associated with annual contributions to fund the Utility's pension plan in 2006, 2007, 2008 and 2009 that are projected to be necessary for the pension plan to reach fully funded status as of January 1, 2010. The settlement would resolve the Utility's application for approval of funding to make a 2006 pension contribution as well as the Utility's separate request for pension contribution funding for 2007, 2008 and 2009 made in the 2007 GRC application. For 2006, the Settling Parties agreed that the $155 million distribution and generation revenue requirement that the CPUC authorized the Utility to collect beginning January 1, 2006, subject to refund, to fund a $250 mill ion pension contribution on a total company basis, would become final and no longer subject to refund. For 2007, 2008 and 2009, the Settling Parties agreed that the Utility would need an annual pension-related revenue requirement of $98 million attributable to distribution and generation operations.

               A CPUC hearing on the settlement was held in March 2006 and no comments on the settlement were submitted. A final decision on the pension contribution applications is expected from the CPUC by the third quarter of 2006. The Utility is unable to predict the ultimate outcome of these proceedings, or the impact it will have on its financial condition or result of operations.

Pending CPUC Investigation

               In February 2005, the CPUC issued a ruling opening an investigation into the Utility's billing and collection practices and credit policies. The investigation was begun at the request of TURN after the CPUC's January 13, 2005 decision that characterized the definition of "billing error" in a revised Utility tariff to include delayed bills and Utility-caused estimated bills as being consistent with "existing CPUC policy, tariffs, and requirements." The Utility contends that prior to the CPUC's January 13, 2005 decision, "billing error" under the Utility's former tariffs did not encompass delayed bills or Utility-caused estimated bills. The Utility's petition asking the appellate court to review the CPUC's decision denying rehearing of its January 13, 2005 decision is still pending.

               On February 3, 2006, the CPUC's Consumer Protection and Safety Division, or CPSD, and TURN submitted their reports to the CPUC concluding that the Utility violated applicable tariffs related to delayed and estimated bills. The CPSD recommends that the Utility refund to customers $117 million, plus interest at the three-month commercial paper interest rate, that allegedly was collected in violation of the tariffs. TURN recommends that the Utility refund to customers $53 million, plus interest at the three-month commercial paper interest rate, that allegedly was collected in violation of the tariffs. The two refunds are not additive. The CPSD also recommends that the Utility pay fines of $6.75 million, while TURN recommends fines in the form of a $1 million contribution to Relief for Energy Assistance through Community Help. Both the CPSD and TURN recommend that refunds and fines be funded by s hareholders.

               If the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may seek to order the Utility to refund any amounts collected in violation of tariffs, plus interest, to customers who paid such amounts. In addition, if the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may seek to impose penalties on the Utility ranging from $500 to $20,000 for each separate violation.

               The Utility filed its response to the reports on March 31, 2006. Rebuttal testimony is due on May 5, 2006, and hearings are set to begin on May 24, 2006.

               PG&E Corporation and the Utility are unable to predict the outcome of this matter, which could have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

Pacific Connector Gas Pipeline

               PG&E Strategic Capital, Inc., a wholly owned subsidiary of PG&E Corporation, Fort Chicago Energy Partners L.P., or Fort Chicago, and The Williams Companies, Inc., or Williams, have formed a partnership, Pacific Connector Gas Pipeline L.P., to develop and build a new natural gas transmission pipeline that would increase West Coast access to natural gas supplies. The three partners hold equal interests in the partnership. The proposed 223-mile natural gas pipeline, the Pacific Connector Gas Pipeline, would connect to the proposed Jordan Cove liquefied natural gas, or LNG, terminal proposed to be developed near Coos Bay, Oregon by Fort Chicago affiliate, Jordan Cove Energy Project L.P. The pipeline would then join the Williams' Northwest Pipeline system near Roseburg, Oregon, and tie in near the California-Oregon border to the Utility's gas transmission system. As proposed, the Pacific Connector Gas Pipe line would deliver as much as 1 billion cubic feet per day of natural gas to the West Coast. Certain filings have been made at the FERC to initiate the regulatory review and approval process for both the proposed Pacific Connector Gas Pipeline and the Jordan Cove LNG terminal. The FERC certificate application is scheduled to be submitted in January 2007, with construction planned to start in 2009. The final route and estimated costs will be determined following further analysis and public review. The pipeline is scheduled to be completed in 2010, subject to environmental reviews and FERC approval. PG&E Corporation is unable to predict whether the Pacific Connector Gas Pipeline or the Jordan Cove LNG terminal will be approved.

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 transmission and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk and interest rate risk. For a comprehensive discussion of PG&E Corporation's market risks, see "Risk Management Activities" in the MD&A section of the 2005 Annual Report. The following disclosures omit certain information that has not changed since the 2005 Annual Report was filed with the SEC.

Price Risk

Natural Gas Transmission and Storage

The Utility uses value-at-risk to measure the Utility's exposure to price and volumetric risks that could impact revenues due to changes in market prices, customer demand and weather. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 99% confidence level, which means that there is a 1% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. The Utility's value-at-risk calculated under the methodology described above were approximately $27 million and $31 million at March 31, 2006 and December 31, 2005, respectively. The Utility's high, low, and average value-at-risk during the three months ended March 31, 2006 were approxima tely $31 million, $22 million and $27 million, respectively. The Utility's high, low, and average value-at-risk during the year ended December 31, 2005 were approximately $43 million, $31 million and $36 million, respectively.

Convertible Subordinated Notes

               As of March 31, 2006, PG&E Corporation has outstanding $280 million of 9.50% Convertible Subordinated Notes, or Convertible Subordinated Notes, that are scheduled to mature on June 30, 2010. Holders of the Convertible Subordinated Notes are entitled to receive "pass-through dividends" at the same payout ratio as common shareholders with the number of shares determined by dividing the principal amount of the Convertible Subordinated Notes by the conversion price.

               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 recorded at fair value in PG&E Corporation's Condensed Consolidated Financial Statements. Changes in the fair value are recognized in PG&E Corporation's Condensed Consolidated Statements of Income as a non-operating expense or income (included in Other expense, net). At March 31, 2006 and December 31, 2005, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $89 million and $92 million, respectively, of which $22 million and $22 million, respectively, is classified as a current liability (in Current Liabilities - Other) and $67 million an d $70 million, respectively, is classified as a noncurrent liability (in Noncurrent Liabilities - Other).

Accelerated Share Repurchase

               As discussed above under "Liquidity and Financial Resources," on March 28, 2006, PG&E Corporation entered into a new share forward agreement with GS&Co. to complete the ASR. Under the new share forward agreement, PG&E Corporation and GS&Co. will continue to be required to make certain payments, including a price adjustment with respect to the remaining 11,385,000 shares subject to the agreement based on the difference between the specified forward price of $34.75 per share and the average of the daily VWAP from March 29, 2006 through June 8, 2006. The aggregate amounts of the payments required of each of the parties, including the amount of the price adjustment based on the VWAP, cannot be determined until June 8, 2006.

               Over the remaining term of the new share forward agreement, for every $1 that the VWAP exceeds $34.75, PG&E Corporation will owe GS&Co. an additional price adjustment of approximately $10.7 million. Conversely, for every $1 that the VWAP is less than $34.75, the price adjustment will be reduced by approximately $10.7 million. Based on the market price of PG&E Corporation common stock at March 31, 2006, PG&E Corporation would have an obligation to GS&Co. of approximately $49.6 million upon the completion of the new share forward agreement. Since the price adjustment and any additional payment obligations that PG&E Corporation or GS&Co. may incur 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 under the new share forward agreement as equity .

Interest Rate Risk

               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, 2006, 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.

CRITICAL ACCOUNTING POLICIES

               The preparation of Condensed Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America 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 to their complexity, because their application is 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 discussed in detail in the 2005 Annual Report. They include:

· Regulatory Assets and Liabilities;

· Unbilled Revenues;

· Environmental Remediation Liabilities;

· Asset Retirement Obligations;

· Income Taxes; and

· Pension and Other Postretirement Benefits.

               For the period ended March 31, 2006, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and there were no material changes to the important assumptions underlying the critical accounting estimates.

NEW ACCOUNTING POLICIES

               In December 2004, the Financial Accounting Standards Board, or FASB, issued SFAS No. 123 (revised December 2004), "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R requires that the cost of all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such costs.

               Effective January 1, 2006, PG&E Corporation and the Utility adopted the fair value recognition provisions of SFAS No. 123R. The impact of adopting SFAS No. 123R is disclosed in Note 2 and Note 8 to the Condensed Consolidated Financial Statements. See Note 2 for additional new accounting policies.

ADDITIONAL SECURITY MEASURES

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

ENVIRONMENTAL AND LEGAL MATTERS

               PG&E Corporation and the Utility are subject to laws and regulations established both to maintain and improve the quality of the environment. Where PG&E Corporation's and the Utility's properties contain hazardous substances, these laws and regulations may require PG&E Corporation and the Utility to remove those substances or to remedy effects on the environment. As described in Note 11 of the Notes to the Condensed Consolidated Financial Statements, the Utility had an undiscounted environmental remediation liability of approximately $466 million at March 31, 2006, and approximately $469 million at December 31, 2005.

               In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. As described in Note 11 of the Notes to the Condensed Consolidated Financial Statements, the accrued liability for legal matters is included in PG&E Corporation's and the Utility's other noncurrent liabilities in the Condensed Consolidated Balance Sheets, and totaled approximately $362 million at March 31, 2006, and $388 million at December 31, 2005. The Utility has accrued approximately $314 million with respect to the Chromium Litigation described in Note 11. PG&E Corporation and the Utility do not believe that the ultimate outcome of the Chromium Litigation will have an additional material adverse impact on their financial condition or results of operations.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4: CONTROLS AND PROCEDURES

               Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures as of March 31, 2006, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934, or the Act, is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Act is accumulated and communicated to PG&E Corporation's and the Utility's management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

               As of January 1, 2004, PG&E Corporation and the Utility adopted Financial Accounting Standards Board, or FASB, revision to FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of a low-income housing partnership that was determined to be a variable interest entity, or VIE, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of the VIE. Therefore, PG&E Corporation's and the Utility's evaluation of disclosure controls and procedures performed as of March 31, 2006, did not include this entity in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for the con solidated VIE.

               There were no changes in internal controls over financial reporting that occurred during the quarter ended March 31, 2006, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Pacific Gas and Electric Company Chapter 11 Filing

               For more information regarding the Utility's Chapter 11 proceeding, see "Part I, Item 3: Legal Proceedings" of the 2005 Annual Report and Note 10 of the Notes to the Condensed Consolidated Financial Statements included in this report.

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

               For information regarding this matter, see "Part I, Item 3: Legal Proceedings" in the 2005 Annual Report.

Diablo Canyon Power Plant

               For information regarding matters relating to the Diablo Canyon Power Plant, see "Part I, Item 3: Legal Proceedings" in the 2005 Annual Report.

Compressor Station Chromium Litigation

               For more information regarding the Chromium Litigation, see "Part I, Item 3: Legal Proceedings" in the 2005 Annual Report and Note 11 to the Notes to the Condensed Consolidated Financial Statements included in this report.

               On April 21, 2006, the Utility released $295 million from escrow to pay approximately 1,000 plaintiffs in the Chromium Litigation who participated in the settlement reached between the Utility and plaintiffs' counsel on February 3, 2006. In accordance with the terms of the settlement agreement, attorneys for the settling plaintiffs have submitted releases from or on behalf of all of the settling plaintiffs. Also on April 21, 2006, the Superior Court for the County of Los Angeles dismissed the ten pending cases covered by the settlement agreement.

               With respect to the unresolved claims, the Utility will continue to pursue appropriate defenses, including the statute of limitations, the exclusivity of workers' compensation laws, lack of exposure to chromium, and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation and the Utility do not expect that the outcome with respect to the remaining unresolved claims will have a material adverse effect on their financial condition or results of operations.

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

               On April 5, 2006, the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, denied PG&E Corporation's request for an en banc rehearing regarding the Ninth Circuit's remand of plaintiffs' restitution claims back to the San Francisco Superior Court. PG&E Corporation is considering whether to file a petition seeking review of the Ninth Circuit's ruling with the U.S. Supreme Court, which petition would be due on July 5, 2006.

               PG&E Corporation believes that the California Attorney General's and CCSF's allegations have no merit and will continue to vigorously respond to and defend against the litigation. PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation's financial condition or results of operations.

               For more information regarding these cases, see "Part I, Item 3: Legal Proceedings" of the 2005 Annual Report.

ITEM 1A. RISK FACTORS

               A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors" in the 2005 Annual Report. There have been no material changes in the risks related to PG&E Corporation or the Utility from those disclosed in the 2005 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

               Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended March 31, 2006, the period covered by this report.

Issuer Purchases of Equity Securities

               PG&E Corporation common stock:

Period		Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1 through January 31, 2006		-	$	-		-	$	500,000,000
February 1 through February 28, 2006		-	$	-		-	$	500,000,000
March 1 through March 31, 2006		-	$	-		-	$	500,000,000
Total		-	$	-		-	$	500,000,000
(1)	On October 19, 2005, the PG&E Corporation Board of Directors authorized the repurchase of up to $1.6 billion in shares of PG&E Corporation's common stock, from time to time, but no later than December 31, 2006. The program was publicly announced in a Current Report on Form 8-K filed by PG&E Corporation on October 21, 2005. As described in a Current Report on Form 8-K filed by PG&E Corporation on November 18, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement with Goldman Sachs & Co., Inc., or GS&Co., on November 16, 2005, or the November 16 ASR, under which PG&E Corporation repurchased 31,650,300 shares of its outstanding common stock at an initial price of $34.75 per share and an aggregate price of approximately $1.1 billion. The forward share component of the November 16 ASR was terminated in accordance with its terms on March 28, 2006. In connection with the termination, PG&E Corporation paid GS&Co. approximately $58 million (net of amounts payable by GS&Co. to PG&E Corporation), including a price adjustment based on the difference between $34.75 per share, and the volume weighted average price, or VWAP, of PG&E Corporation common stock from November 17, 2005 through March 28, 2006. On March 28, 2006, PG&E Corporation entered into a new share forward agreement with GS&Co. to complete the share forward component of the November 16 ASR. Under the new share forward agreement, PG&E Corporation and GS&Co. will continue to be required to make certain payments, including a price adjustment with respect to the remaining 11,385,000 shares subject to the agreement based on the difference between $34.75 per share and the average of the daily VWAP from March 29, 2006 through June 8, 2006.

               During the first quarter of 2006, Pacific Gas and Electric Company did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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

PG&E Corporation:

On April 19, 2006, 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	228,650,856	17,905,010
Leslie S. Biller	228,724,835	17,831,031
David A. Coulter	226,156,981	20,398,885
C. Lee Cox	228,581,524	17,974,342
Peter A. Darbee	226,292,796	20,263,070
Maryellen C. Herringer	228,604,372	17,951,494
Mary S. Metz	228,495,217	18,060,649
Barbara L. Rambo	228,620,236	17,935,630
Barry Lawson Williams	227,174,867	19,380,999

2.  Ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2006 (included as Item 2 in the proxy statement):

For:	242,489,382
Against:	1,489,952
Abstain:	2,576,532

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 a shareholder proposal regarding poison pill (included as Item 3 in the proxy statement):

For:	61,741,937
Against:	143,807,159
Abstain:	4,729,775
Broker non-vote (1):	36,276,995

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.

4.  Consideration of a shareholder proposal regarding an independent board chairman (included as Item 4 in the proxy statement):

For:	47,002,403
Against:	158,986,047
Abstain:	4,290,421
Broker non-vote (1):	36,276,995

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.

(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 19, 2006, 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 96% of the combined voting power of the outstanding capital stock of the Utility. PG&E Corporation voted all of its shares of common stock for the nominees named in the 2006 joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2006. The shares of common stock held by the subsidiary were not voted. The balances of the votes shown below were 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	268,592,106	116,738
Leslie S. Biller	268,597,564	111,280
David A. Coulter	268,590,978	117,866
C. Lee Cox	268,592,479	116,365
Peter A. Darbee	268,591,288	117,556
Maryellen C. Herringer	268,592,489	116,355
Thomas B. King	268,595,341	113,503
Mary S. Metz	268,584,433	124,411
Barbara L. Rambo	268,592,575	116,269
Barry Lawson Williams	268,584,052	124,792

2.  Ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2006 (included as Item 2 in the proxy statement):

For:	268,611,063
Against:	49,854
Abstain:	47,927

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.

ITEM 5. OTHER INFORMATION

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

               The Utility's earnings to fixed charges ratio for the three months ended March 31, 2006 was 3.14. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2006, was 3.08. 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 notes, respectively.

ITEM 6. EXHIBITS

10	Supplemental Confirmation dated March 28, 2006, supplementing Master Confirmation Agreement dated November 16, 2005 between PG&E Corporation and Goldman Sachs & Co., Inc.
11	Computation of Earnings Per Common Share
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
** Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

SIGNATURES

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

PG&E CORPORATION

G. ROBERT POWELL

G. Robert Powell
Vice President and Controller
(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

G. ROBERT POWELL

G. Robert Powell
Vice President and Controller
(duly authorized officer and principal accounting officer)

Dated: May 3, 2006

EXHIBIT INDEX

10	Supplemental Confirmation dated March 28, 2006, supplementing Master Confirmation Agreement dated November 16, 2005 between PG&E Corporation and Goldman Sachs & Co., Inc.
11	Computation of Earnings Per Common Share
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
** Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

EX-10

GOLDMAN SACHS & CO. | 85 BROAD STREET | NEW YORK, NEW YORK 10004 | TEL: 212-902-1000

To:	PG&E Corporation One Market Street Spear Tower Suite 2400 San Francisco, CA 94105
From:	Goldman, Sachs & Co.
Subject:	Accelerated Share Repurchase Transaction - VWAP Pricing (Non-Collared)
Ref. No:	As provided in the Supplemental Confirmation
Date:	November 16, 2005

This master confirmation ("Master Confirmation") dated as of November 16, 2005 is intended to supplement the terms and provisions of certain Transactions (each, a "Transaction") entered into from time to time between Goldman, Sachs & Co. ("GS&Co.") and PG&E Corporation ("Counterparty"). This Master Confirmation, taken alone, is neither a commitment by either party to enter into any Transaction nor evidence of a Transaction. The terms of any particular Transaction shall be set forth in a Supplemental Confirmation in the form of Annex A, which references this Master Confirmation, in which event the terms and provisions of this Master Confirmation shall be deemed to be incorporated into and made a part of each such Supplemental Confirmation. This Master Confirmation and each Supplemental Confirmation together shall constitute a "Confirmation" as referred to in the Agreement specified below.

The definitions and provisions contained in the 2002 ISDA Equity Derivatives Definitions (the "Equity Definitions"), as published by the International Swaps and Derivatives Association, Inc., are incorporated into this Master Confirmation. This Master Confirmation and each Supplemental Confirmation evidences a complete binding agreement between Counterparty and GS&Co. as to the terms of each Transaction to which this Master Confirmation and the related Supplemental Confirmation relates.

This Master Confirmation and each Supplemental Confirmation, together with all other documents referring to the 1992 ISDA Master Agreement (Multicurrency-Cross Border) (the "ISDA Form" or the "Agreement), confirming Transactions entered into between GS&Co. and Counterparty, shall supplement, form a part of, and be subject to the ISDA Form as if GS&Co. and Counterparty had executed the Agreement (but without any Schedule) except that the following elections and modifications shall be made: (i) the election of Loss and Second Method, New York law (without regard to conflicts of law principles) as the governing law and US Dollars ("USD") as the Termination Currency, (ii) the election that subparagraph (ii) of Section 2(c) will not apply to Transactions, (iii) the replacement of the word "third" in the last li ne of Section 5(a)(i) with the word "first", (iv) the election that the "Cross Default" provisions of Section 5(a)(vi) shall apply to Counterparty, with a "Threshold Amount" of USD 100 million, and (v) the replacement of clause (1) in Section 6(d)(i) with the clause "(1) showing in reasonable detail such calculations and specifying any amount payable under Section 6(e) (including, without limitation, providing all relevant quotations and assumptions and specifying the methodologies used in sufficient detail so as to enable the other party to replicate the calculation)". Further, for purposes of determining whether an Event of Default pursuant to Section 5(a)(vi) of the Agreement has occurred, notwithstanding anything to the contrary stated in that provision, clause (1) of Section 5(a)(vi) will apply only to Specified Indebtedness that is actually declared to be due and payable before it would otherwise be due and pa yable under the relevant agreement or instrument, and not to Specified Indebtedness that is merely "capable at such time of being declared" so due and payable.

All provisions contained in the Agreement shall govern this Master Confirmation and the related Supplemental Confirmation relating to a Transaction except as expressly modified herein or in the related Supplemental Confirmation. With respect to any relevant Transaction, the Agreement, this Master Confirmation and the related Supplemental Confirmation shall represent the entire agreement and understanding of the parties with respect to the subject matter and terms of such Transaction and shall supersede all prior or contemporaneous written or oral communications with respect thereto.

If, in relation to any Transaction to which this Master Confirmation and related Supplemental Confirmation relate, there is any inconsistency between the Agreement, this Master Confirmation, any Supplemental Confirmation and the Equity Definitions that are incorporated into this Master Confirmation or any Supplemental Confirmation, the following will prevail for purposes of such Transaction in the order of precedence indicated: (i) such Supplemental Confirmation; (ii) this Master Confirmation; (iii) the Agreement; and (iv) the Equity Definitions.

1. Each Transaction constitutes a Share Forward Transaction for the purposes of the Equity Definitions. Set forth below are the terms and conditions which, together with the terms and conditions set forth in each Supplemental Confirmation (in respect of each relevant Transaction), shall govern each such Transaction.

General Terms:

Trade Date: For each Transaction, as set forth in the Supplemental Confirmation.

Seller: Counterparty

Buyer: GS&Co.

Shares: Common Stock of Counterparty (Ticker: PCG)

Number of Shares: For each Transaction, as set forth in the Supplemental Confirmation.

Forward Price: For each Transaction, as set forth in the Supplemental Confirmation.

Prepayment: Not Applicable

Variable Obligation: Not Applicable

Exchange: New York Stock Exchange

Related Exchange(s): All Exchanges

Market Disruption Event: The definition of "Market Disruption Event" in Section 6.3(a) of the Equity Definitions is hereby amended by inserting the words "at any time on any Scheduled Trading Day during the Valuation Period or" after the word "material," in the third line thereof.

Valuation:

Valuation Period: Each Scheduled Trading Day during the period commencing on and including the Valuation Period Start Date to and including the Valuation Date (but excluding any day(s) on which the Valuation Period is suspended in accordance with Section 5 herein and including any day(s) by which the Valuation Period is extended pursuant to the provision below).

Notwithstanding anything to the contrary in the Equity Definitions, to the extent that any Scheduled Trading Day in the Valuation Period is a Disrupted Day, the Valuation Date shall be postponed and the Calculation Agent in its sole discretion shall extend the Valuation Period and make adjustments to the weighting of each Relevant Price for purposes of determining the Settlement Price, with such adjustments based on, among other factors, the duration of any Market Disruption Event and the volume, historical trading patterns and price of the Shares. To the extent that there are 9 consecutive Disrupted Days during the Valuation Period, then notwithstanding the occurrence of a Disrupted Day, the Calculation Agent shall have the option in its sole discretion to either determine the Relevant Price using its good faith estimate of the value for the Share on such 9^th consecutive Disrupted Day or elect to further extend the Valuation Period as it deems necessa ry or appropriate.

Valuation Period Start Date: For each Transaction, as set forth in the Supplemental Confirmation.

Valuation Date: For each Transaction, as set forth in the Supplemental Confirmation (as the same may be postponed in accordance with the provisions of "Valuation Period" and Section 5 herein).

Settlement Terms:

Settlement Currency: USD (all amounts shall be converted to the Settlement Currency in good faith and in a commercially reasonable manner by the Calculation Agent).

Settlement Method Election: Applicable; provided that Section 7.1 of the Equity Definitions is hereby amended by deleting the word "Physical" in the sixth line thereof and replacing it with the words "Net Share" and deleting the word "Physical" in the last line thereof and replacing it with the word "Cash".

Electing Party: Counterparty

Settlement Method Election Date: 10 Scheduled Trading Days prior to the originally scheduled Valuation Date.

Default Settlement Method: Cash Settlement

Forward Cash Settlement Amount: An amount in the Settlement Currency equal to the product of (a) the Number of Shares multiplied by (b) an amount equal to (i) the Settlement Price minus (ii) the Forward Price.

Settlement Price: The arithmetic mean of the Relevant Prices of the Shares for each Exchange Business Day in the Valuation Period.

Relevant Price: The New York 10b-18 Volume Weighted Average Price per share of the Shares for the regular trading session (including any extensions thereof) of the Exchange on the related Exchange Business Day (without regard to pre-open or after hours trading outside of such regular trading session) as published by Bloomberg at 4:15 p.m. New York time on such date.

Cash Settlement Payment Date: 3 Currency Business Days after the Valuation Date.

Counterparty's Contact Details

for Purpose of Giving Notice: Nicholas Bijur

Assistant Treasurer

PG&E Corporation

One Market Street, Spear Tower

Suite 2400

San Francisco, CA 94105

Telephone No.: (415) 817-8199

Facsimile No.: (415) 267-7265

With a copy to:

Gary Encinas

Chief Counsel-Corporate

PG&E Corporation

One Market Street, Spear Tower

Suite 2400

San Francisco, CA 94105

Telephone No.: (415) 817-8201

Facsimile No.: (415) 817-8225

GS&Co.'s Contact Details for

Purpose of Giving Notice: Telephone No.: (212) 902-8996

Facsimile No.: (212) 902-0112

Attention: Equity Operations: Options and Derivatives

With a copy to:

Kelly Coffey

Equity Capital Markets

One New York Plaza

New York, NY 10004

Telephone No.: (212) 902-1037

Facsimile No.: (212) 346-2126

Net Share Settlement:

Net Share Settlement Procedures: Net Share Settlement shall be made in accordance with the procedures attached hereto as Annex B.

Net Share Settlement Price: The Net Share Settlement Price shall be the price per Share as of the Valuation Time on the Net Share Valuation Date as reported in the official real-time price dissemination mechanism for the Exchange. In the event Counterparty owes GS&Co. any amount, the Net Share Settlement Price shall be reduced by the per Share amount of the underwriting discount and/or commissions agreed to pursuant to the registration agreement contemplated by Annex B.

Valuation Time: As provided in Section 6.1 of the Equity Definitions; provided that Section 6.1 of the Equity Definitions is hereby amended by inserting the words "Net Share," before the words "Valuation Date" in the first and third lines thereof.

Net Share Valuation Date: The Exchange Business Day immediately following the Valuation Date.

Net Share Settlement Date: The third Exchange Business Day immediately following the Valuation Date.

Reserved Shares: For each Transaction, as set forth in the Supplemental Confirmation.

Fixed, Floating and Counterparty

Additional Payment Amounts Payable:

Floating Amount Payable by GS&Co.:

Floating Amount Payment Date: The Cash Settlement Payment Date

Floating Amount: For each Transaction, an amount equal to the sum of the applicable Federal Funds Rate multiplied by (i) the Daily Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to and including the Valuation Date.

Floating Amount Accrual Date: Trade Date

Federal Funds Rate: For any date of determination, the "Fed Funds Open Rate," which shall be the interest rate reported on Bloomberg under the symbol "FEDSOPEN <index>" on such date. For the avoidance of doubt, for any day which is not a Currency Business Day the "Federal Funds Open Rate" for the immediately preceding Currency Business Day shall apply.

Daily Notional Amount: Commencing with the Floating Amount Accrual Date, for any date of determination, the Daily Notional Amount shall be an amount equal to the product of the Initial Notional Amount (as set forth in the Supplemental Confirmation) multiplied by a fraction with a numerator equal to the Originally Scheduled Number of Scheduled Trading Days in the Valuation Period minus the number of Exchange Business Days in the Valuation Period that have elapsed (other than any days during which the Valuation Period is suspended pursuant to Section 5 herein) as of such date of determination and a denominator equal to the Originally Scheduled Number of Scheduled Trading Days in the Valuation Period (such fraction, the "Remaining Percentage").

To the extent that the Valuation Period is extended pursuant to the terms of this Master Confirmation, the Calculation Agent shall adjust the Daily Notional Amount commencing with the first Exchange Business Day after such extension (the "Valuation Period Extension Date"). The notional amount deemed to be remaining at the end of the Exchange Business Day before the Valuation Period Extension Date (the "Remaining Notional Value") shall be the Initial Notional Value multiplied by the Remaining Percentage at the end of such day. Commencing with the Valuation Period Extension Date, for any date of determination, the Daily Notional Amount shall be equal to the product of the Remaining Notional Value multiplied by a fraction with (a) a numerator equal to (i) the number of Scheduled Trading Days remaining from and including the Valuation Period Extension Date to the Valuation Date after extension (the "Remaining Scheduled Trading Days") minus (ii) the number of Exchan ge Business Days in the Valuation Period after extension from and including the Valuation Period Extension Date that have elapsed (other than any days during which the Valuation Period after extension is suspended pursuant to Section 5 herein) as of such date of determination and (b) a denominator equal to the Remaining Scheduled Trading Days.

Fixed Amount Payable by Counterparty:

Fixed Amount Payment Date: The Cash Settlement Payment Date

Fixed Amount: For each Transaction, an amount equal to the sum of (I) the applicable Daily Additional Spread multiplied by (i) the Daily Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to and including the Valuation Date plus (II) the applicable Fixed Rate multiplied by (i)  the Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to and including the Valuation Date.

Fixed Rate: For each Transaction, as set forth in the Supplemental Confirmation.

Daily Additional Spread: The Daily Additional Spread shall be 25 basis points.

Notional Amount: For any date of determination, 105% of the Daily Notional Amount.

Counterparty Additional Amount

Payable by Company:

Counterparty Additional For each Transaction, as set forth in the Supplemental

Payment Amount: Confirmation.

Counterparty Additional

Payment Date: The Cash Settlement Payment Date.

Settlement Terms for Fixed Amount, Floating

Amount and Counterparty Additional

Payment Amount:

Settlement Currency: USD (all amounts shall be converted to the Settlement Currency in good faith and in a commercially reasonable manner by the Calculation Agent).

Settlement Method Election: Applicable; provided that Section 7.1 of the Equity Definitions is hereby amended by deleting the word "Physical" in the sixth line thereof and replacing it with the words "Net Share" and deleting the word "Physical" in the last line thereof and replacing it with the word "Cash".

Electing Party: Counterparty

Settlement Method Election Date: 10 Scheduled Trading Days prior to the originally scheduled Valuation Date.

Default Settlement Method: Cash Settlement

Share Adjustments:

Method of Adjustment: Calculation Agent Adjustment

Extraordinary Events:

Consequences of Merger Events: Subject to Section 7(b) of the Master Confirmation:

(a) Share-for-Share: Modified Calculation Agent Adjustment

(b) Share-for-Other: Cancellation and Payment on that portion of the Other Consideration that consists of cash; Modified Calculation Agent Adjustment on the remainder of the Other Consideration.

(c) Share-for-Combined: Component Adjustment

Determining Party: GS&Co.

Tender Offer: Applicable

Consequences of Tender Offers: Subject to Section 7(b) of the Master Confirmation:

(a) Share-for-Share: Modified Calculation Agent Adjustment

(b) Share-for-Other: Cancellation and Payment on that portion of the Other Consideration that consists of cash; Modified Calculation Agent Adjustment on the remainder of the Other Consideration.

(c) Share-for-Combined: Component Adjustment

Determining Party: GS&Co.

Nationalization, Insolvency or Delisting: Subject to Section 7(a) of this Master Confirmation, Negotiated Close-out; provided that in addition to the provisions of Section 12.6(a)(iii) of the Equity Definitions, it shall also constitute a Delisting if the Exchange is located in the United States and the Shares are not immediately re-listed, re-traded or re-quoted on any of the New York Stock Exchange, the American Stock Exchange or The NASDAQ National Market (or their respective successors); if the Shares are immediately re-listed, re-traded or re-quoted on any such exchange or quotation system, such exchange or quotation system shall be deemed to be the Exchange.

Additional Disruption Events:

(a) Change in Law: Applicable; provided that Section 12.9(a)(ii)(Y) of the Equity Definitions is hereby deleted.

(b) Failure to Deliver: Not Applicable

(c) Insolvency Filing: Applicable

(d) Loss of Stock Borrow: Applicable; provided that Loss of Stock Borrow shall not constitute an Additional Disruption Event so long as Counterparty agrees to pay the Hedging Party the amount by which the stock loan rate necessary to maintain a borrowing of Shares by GS&Co. ("Hedge Position") in connection with the Transaction exceeds the Maximum Stock Loan Rate.

Maximum Stock Loan Rate: 30 basis points

(e) Hedging Disruption: Not Applicable

(f) Increased Cost of Hedging: Not Applicable

(g) Increased Cost of Stock Borrow: Not Applicable

Hedging Party: GS&Co.

Determining Party: GS&Co.

Non-Reliance: Applicable

Agreements and Acknowledgements

Regarding Hedging Activities: Applicable

Additional Acknowledgements: Applicable

Net Share Settlement following

Extraordinary Event: Counterparty shall have the right, in its sole discretion, to elect that any payment required to be made pursuant to Sections 12.7 or 12.9 of the Equity Definitions (except with respect to any portion of the consideration for the Shares consisting of cash in the event of a Merger Event or Tender Offer) following the occurrence of an Extraordinary Event by Net Share Settlement of the Transactions under this Master Confirmation in accordance with the terms, and subject to the conditions, for Net Share Settlement herein by giving written notice to GS&Co. of such election on the day that the notice fixing the date that the Transactions are terminated or cancelled, as the case may be (the "Cancellation Date"), pursuant to the applicable provisions of Section 12 of the Equity Definitions is effective. If Counterparty elects Net Share Settlement: (a) the Net Share Valuation Date shall be the date specified in the notice fixing the date that the Transactions are terminated or cancelled, as the case may be; provided that the Net Share Valuation Date shall be either the Exchange Business Day that such notice is effective or the first Exchange Business Day immediately following the Exchange Business Day that such notice is effective, (b) the Net Share Settlement Date shall be deemed to be the Exchange Business Day immediately following the Cancellation Date and (c) all references to the Forward Cash Settlement Amount, the Fixed Amount, the Floating Rate Amount and the Counterparty Additional Payment Amount, as the case may be, in Annex B hereto shall be deemed to be references to the Cancellation Amount. The definition of "Cancellation Amount" in Section 12.8 of the Equity Definitions is hereby amended by inserting the following paragraph: "(h) The Determining Party shall show the other party in reasonable detail its calculation of the Cancellation Amount, including withou t limitation providing all relevant quotations and assumptions and specifying the methodologies used in sufficient detail so as to enable the other party to replicate the calculation".

Net Share Settlement Upon Early Termination: Counterparty shall have the right, in its sole discretion, to elect that any payment required to be made (the "Early Termination Amount") pursuant to Sections 6(d) and 6(e) of the Agreement following the occurrence of an Early Termination Date in respect of the Agreement by Net Share Settlement of all the Transactions under this Master Confirmation in accordance with the terms, and subject to the conditions, for Net Share Settlement herein by giving written notice to GS&Co. of such election on the day that the notice fixing an Early Termination Date is effective. If Counterparty elects Net Share Settlement: (a) the Net Share Valuation Date shall be the datespecified in the notice fixing an Early Termination Date; provided that the Net Share Valuation Date shall be either the Exchange Business Day that such notice is effective or the first Exchange Business Day immediately following the Exchange Business Day that such notice is effective, (b) the Net Share Settlement Date shall be deemed to be the Exchange Business Day immediately following the Early

Termination Date (except for an Early Termination as a result of Section 7(d), in which event the Net Share Settlement Date shall be deemed to be the tenth Exchange Business Day following the Early Termination Date) and (c) all references to Forward Cash Settlement Amount, the Fixed Amount, the Floating Rate Amount and the Counterparty Additional Payment Amount, as the case may be, in Annex B hereto shall be deemed references to the Early Termination Amount.

Transfer: Notwithstanding anything to the contrary in the Agreement, GS&Co. may assign, transfer and set over all rights, title and interest, powers, privileges and remedies of GS&Co. under any Transaction, in whole or in part, to an affiliate of GS&Co. that is fully and unconditionally guaranteed by The Goldman Sachs Group, Inc. without the consent of Counterparty, provided that Counterparty is not required to make a payment to GS&Co. in respect of an Indemnifiable Tax as a result of such transfer.

GS&Co. Payment Instructions: Chase Manhattan Bank New York
For A/C Goldman, Sachs & Co.
A/C # 930-1-011483
ABA: 021-000021

Counterparty Payment Instructions: PG&E Corporation Master Account No. 099023
Mellon Trust of New England, N.A.

Boston, MA
ABA Routing No: 011001234

2. Calculation Agent: GS&Co.
3. Representations, Warranties and Covenants of GS&Co. and Counterparty.

1. Each party represents and warrants that it (i) is an "eligible contract participant", as defined in the U.S. Commodity Exchange Act, as amended and (ii) is entering into each Transaction hereunder as principal (and not as agent or in any other capacity, fiduciary or otherwise) and not for the benefit of any third party.
2. Each party acknowledges that the offer and sale of each Share Forward Transaction to it is intended to be exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), by virtue of Section 4(2) thereof and the provisions of Regulation D promulgated thereunder ("Regulation D"); and this acknowledgement shall not be deemed to extend to Settlement Shares or Early Settlement Shares. Accordingly, each party represents and warrants to the other that (i) it has the financial ability to bear the economic risk of its investment in each Share Forward Transaction and is able to bear a total loss of its investment, (ii) it is an "accredited investor" as that term is defined under Regulation D, (iii) it will purchase each Share Forward Transaction for investment and not with a view to the distribution o r resale thereof, and (iv) the disposition of each Share Forward Transaction is
3. restricted under this Master Confirmation and each Supplemental Confirmation, the Securities Act and state securities laws.

1. Additional Representations, Warranties and Covenants of Counterparty.

As of the date hereof and the date of each Supplemental Confirmation, Counterparty represents, warrants and covenants to GS&Co. that:

2. the purchase or writing of each Transaction will not violate Rule 13e-1 or Rule 13e-4 under the Securities Exchange Act of 1934, as amended (the "Exchange Act");
3. it is not entering into any Transaction on the basis of, and is not aware of, any material non-public information with respect to the Shares or in anticipation of, in connection with, or to facilitate, a distribution of its securities, a self tender offer or a third-party tender offer;
4. it is not entering into any Transaction to create, and will not engage in any other securities or derivative transaction to create, a false or misleading appearance of active trading or market activity in the Shares (or any security convertible into or exchangeable for the Shares), or which would otherwise violate the Exchange Act;
5. Counterparty is in compliance with its reporting obligations under the Exchange Act and its most recent Annual Report on Form 10-K, together with all reports subsequently filed by it pursuant to the Exchange Act, taken together and as amended and supplemented to the date of this representation, do not, as of their respective filing dates, contain any untrue statement of a material fact or omit any material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances in which they were made, not misleading;
6. each Transaction is being entered into pursuant to a publicly disclosed Share buy-back program and its Board of Directors has approved the use of the Transaction to effect the Share buy-back program;
7. notwithstanding the generality of Section 13.1 of the Equity Definitions, GS&Co. is not making any representations or warranties with respect to the treatment of any Transaction under FASB Statements 149 or 150, EITF 00-19 (or any successor issue statements) or under FASB's Liabilities & Equity Project;
8. it has not, and during any Valuation Period (as extended pursuant to the provisions of Section  5 and "Valuation Period" herein) it will not, enter into agreements similar to the Transactions described herein except with GS&Co. or an entity affiliated with GS&Co. where the valuation period in such other transaction will overlap at any time (including as a result of extensions in such valuation period as provided in the relevant agreements) with any Valuation Period (as extended pursuant to the provisions of Section 5 and "Valuation Period" herein) under this Master Confirmation. In the event that the valuation period in any other similar transaction with an entity other than GS&Co. or an entity affiliated with GS&Co. overlaps with any Valuation Period under this Master Confirmation as a result of any extension made pursuant to t he provisions of Section 5 and "Valuation Period" herein, Counterparty shall promptly amend such transaction to avoid any such overlap; and
9. it shall report each Transaction as required under the Exchange Act and the regulations promulgated thereunder.

1. Suspension of Valuation Period; Extension of Valuation Period.

1. If Counterparty concludes that it will be engaged in a distribution of the Shares for purposes of Regulation M promulgated under the Exchange Act ("Regulation M"), Counterparty agrees that it will, on one Scheduled Trading Day's written notice, direct GS&Co. not to purchase Shares in connection with hedging any Transaction during the "restricted period" (as defined in Regulation M). If on any Scheduled Trading Day Counterparty delivers written notice (and confirms by telephone) by 8:30 a.m. New York Time (the "Notification Time"), then such notice shall be effective to suspend the Valuation Period as of such Notification Time. In the event that Counterparty delivers notice and/or confirms by telephone after the Notification Time, then the Valuation Period shall be suspended effective as of 8:30 a.m. New York Time on the following Scheduled Trading Day or as otherwise required by law or agreed between Counterparty and GS&Co. The Valuation Period sha ll be suspended and the Valuation Date extended for each Scheduled Trading Day in such restricted period.
3. In the event that GS&Co. concludes, in its reasonable discretion, that it is appropriate with respect to any legal, regulatory or self-regulatory requirements or related policies and procedures (whether or not such requirements, policies or procedures are imposed by law or have been voluntarily adopted by GS&Co.) for it to refrain from purchasing Shares on any Scheduled Trading Day during the Valuation Period, GS&Co. may by written notice to Counterparty elect to suspend the Valuation Period for such number of Scheduled Trading Days as is specified in the notice. The notice shall not specify, and GS&Co. shall not otherwise communicate to Counterparty, the reason for GS&Co.'s election to suspend the Valuation Period. The Valuation Period shall be suspended and the Valuation Date extended for each Scheduled Trading Day occurring during any such suspension.
4. In the event that the Valuation Period is suspended pursuant to Sections 5(a) or (b) above during the regular trading session on the Exchange then the Calculation Agent in its sole discretion shall, in calculating the Forward Cash Settlement Amount, extend the Valuation Period and make adjustments to the weighting of each Relevant Price for purposes of determining the Settlement Price, with such adjustments based on, among other factors, the duration of any such suspension and the volume, historical trading patterns and price of the Shares.
5. On the first Exchange Business Day of each calendar week during the Valuation Period, to the extent that the Number of Daily Reference Shares exceeds 25% of the ADTV (as defined in Rule 10b-18 under the Exchange Act ("Rule 10b-18")) for the Shares on such day, the Calculation Agent will (i) adjust the Number of Daily Reference Shares to equal an amount equal to 15% of ADTV for the Shares determined and effective on such Exchange Business Day and (ii) deem the remaining Scheduled Trading Days in the Valuation Period to be equal to the Remaining Number of Shares divided by the Number of Daily Reference Shares (after giving effect to any adjustments pursuant to (i) above), rounded up to the nearest whole number.

"Number of Daily Reference Shares" means, for each Transaction, initially the Initial Number of Daily Reference Shares (as set forth in the Supplemental Confirmation) and thereafter as may be adjusted in accordance with this Section 5(d); provided that on the first Exchange Business Day of the fifth calendar week following any such adjustment the Number of Daily Reference Shares shall equal the lesser of (i) the Initial Number of Daily Reference Shares and (ii) 15% of the ADTV of the Shares determined on such Exchange Business Day.

"Remaining Number of Shares" means, for each Transaction and as of any date of determination, a number of Shares equal to (i) the Number of Shares minus (ii) the sum of, for each Exchange Business Day in the Valuation Period up to and including such date, the Number of Shares divided by the total number of Exchange Business Days in the Valuation Period (the "Daily Amount"). The Daily Amount will be deemed to be zero for each day on which the Valuation Period is suspended in accordance with Sections 5(a) and (b) hereof. In the event that the Valuation Period is extended pursuant to the terms of this Master Confirmation, the Calculation Agent may make corresponding adjustments to the amount of the Remaining Number of Shares.

1. Counterparty Purchases. Counterparty represents, warrants and covenants to GS&Co. that for each Transaction:

1. Counterparty (or any "affiliated purchaser" as defined in Rule 10b-18) shall not, purchase any Shares, listed contracts on the Shares or securities that are convertible into, or exchangeable or exercisable for Shares (including, without limitation, any Rule 10b-18 purchases of blocks (as defined in Rule 10b-18)) during any Valuation Period (as extended pursuant to the provisions of Section 5 and "Valuation Period" herein) except for purchases through GS&Co. or an entity affiliated with GS&Co., or if not through GS&Co., with the prior written consent of GS&Co., and in compliance with Rule 10b-18 or otherwise in a manner that Counterparty and GS&Co. believe is in compliance with applicable requirements and except for purchases in connection with management compensation plans or other employee benefit arrangements and except for purchases of Counterparty's 9.50% Convertible Subordinated Notes due 2010, provided such purchases are made in compliance with any applicable legal regulatory or self-regulatory requirements or related policies and procedures (whether such requirements, policies or procedures are imposed by law or have been voluntarily adopted by GS&Co. for uniform

application to all such purchases). Any such purchase by Counterparty shall be disregarded for purposes of determining the Forward Cash Settlement Amount. To the extent that Counterparty makes any such purchase other than through GS&Co., or other than in connection with any Transaction, Counterparty hereby represents and warrants to GS&Co. that (a) it will not take other action that would or could cause GS&Co.'s purchases of the Shares during the Valuation Period not to comply with Rule 10b-18 and (b) any such purchases will not otherwise constitute a violation of Section 9(a) or Rule 10(b) of the Exchange Act. This subparagraph (a) shall not restrict any purchases by Counterparty of Shares effected during any suspension of any Valuation Period in accordance with Section 5 herein and any purchases during such suspension shall be disregarded in calculating the Forward Cash Settlement Amount; and for the avoidance of doubt, this subparagraph (a) shall not restrict an y holders of outstanding securities of Counterparty from exercising or converting such securities to Shares; and

2. Counterparty is entering into this Master Confirmation and each Transaction hereunder in good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b5-1 under the Exchange Act ("Rule 10b5-1"). It is the intent of the parties that each Transaction entered into under this Master Confirmation comply with the requirements of Rule 10b5-1(c)(1)(i)(A) and (B) and each Transaction entered into under this Master Confirmation shall be interpreted to comply with the requirements of Rule 10b5-1(c). Counterparty will not seek to control or influence GS&Co. to make "purchases or sales" (within the meaning of Rule 10b5-1(c)(1)(i)(B)(3)) under any Transaction entered into under this Master Confirmation, including, without limitation, GS&Co.'s decision to enter into any hedging transactions. Counterparty represents and warrants that it has consulted with its own advisors as to the legal aspects of its adoption and implementation of this Master C onfirmation and each Supplemental Confirmation under Rule 10b5-1.

1. Additional Termination Events. Additional Termination Events will apply under Section 5(b)(v) of the Agreement. The following will constitute Additional Termination Events, in each case with Counterparty as the sole Affected Party:

(a) Notwithstanding anything to the contrary in the Equity Definitions, the occurrence of a Nationalization, Insolvency or a Delisting (in each case effective on the Announcement Date as determined by the Calculation Agent);

(b) Notwithstanding anything to the contrary in the Equity Definitions, the occurrence of a Merger Event (effective on the Merger Date) or a Tender Offer (effective on the Tender Offer Date) in respect of which any Other Consideration received for the Shares does not consist of cash. For the avoidance of doubt, in the event that any portion of the consideration received for the Shares consists of cash or New Shares, this Additional Termination Event shall only apply with respect to all or any Transaction(s) (or portions thereof) remaining after giving effect to the provisions in "Consequences of Merger Events" or "Consequences of Tender Offers", as the case may be, above;

(c) [reserved]; or

(d) Notwithstanding anything to the contrary in the Equity Definitions, one day prior to the ex-dividend date in respect of any Extraordinary Dividend (as specified in the Supplemental Confirmation) by the Issuer; provided that in the event that GS&Co. and Counterparty enter into a mutually acceptable new transaction (using their good faith and commercially reasonable efforts) on or prior to one day prior to the ex-dividend date in respect of the Extraordinary Dividend, the amounts determined pursuant to Section 6(e) of the Agreement or otherwise to be owed by Counterparty and GS&Co. with respect to the Affected Transaction(s) shall be deemed to be only t he amounts that would otherwise be owed hereunder in respect of the Forward Cash Settlement Amount (the "Termination Forward Settlement Amount"), the Floating Amount (the "Termination Floating Amount"), the Fixed Amount (the "Termination Fixed Amount") and the Counterparty Additional Payment Amount if the Early Termination Date were the Cash Settlement Payment Date, and shall be payable in cash or (in the case of Counterparty) by Net Share Settlement or a combination of the two. In the event that an Early Termination Date would otherwise occur pursuant to this clause 7(d) while Counterparty is in possession of, or is aware of, material, non-public information, the Early Termination Date shall not be deemed to occur until the day after the day on which Counterparty is not in possession of, and is not aware of, material non-public information so long as, if, at Counterparty's option, on or prior to one day prior to the ex-dividend date for su ch Extraordinary Dividend, Counterparty agrees to pay GS&Co. no later than the earlier of the entry into the new transaction or the dividend payment date for such Extraordinary Dividend, a fixed amount in cash or by Net Share Settlement or a combination of the two, that shall be determined in good faith by GS&Co. as having a value equal to (i) the amount per share of such Extraordinary Dividend multiplied by (ii) the actual number of Shares that will remain borrowed by GS&Co. in connection with any Hedge Positions related to the Transaction as of such ex-dividend date. If Counterparty does not so agree on or prior to one day prior to the ex-dividend date for such Extraordinary Dividend, the Early Termination Date shall occur at the close of business on the Exchange Business Day that is one day prior to the ex-dividend date. For purposes of this Section 7(d): the Termination Forward Settlement Amount shall mean an amount in Settlement Currency equal to the product of (a) the Termination Trading Days multiplied by the Initial Number of Daily Reference Shares multiplied by (b) an amount equal to (i) the Termination Settlement Price minus (ii) the Forward Price; the Termination Floating Amount shall mean an amount equal to the sum of the applicable Federal Funds Rate multiplied by (i) the Daily Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to but excluding the Early Termination Date; and the Termination Fixed Amount shall mean an amount equal to the sum of (I) the applicable Daily Additional Spread multiplied by (i) the Daily Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to but excluding the Early Termination Date plus (II) an amount equal to the sum of the applicable Fixed Rate multiplied by (i)  the Notional Amount multiplied by (ii) 1/360 for each day from and including the Floating Amount Accrual Date to but excluding the Early Termination Date. Also for purposes of this Section 7(d): "Termination Trading Days" shall mean the number of Exchange Business Days (excluding any day(s) on which the Valuation Period was suspended in accordance with Section 5 herein or as a result of any Scheduled Trading Day being a Disrupted Day) from and including the Valuation Period Start Date to and including the Early Termination Date; "Termination Valuation Period" shall mean the Exchange Business Days during the period commencing on and including the Valuation Period Start Date to and including the Early Termination Date (but excluding any day(s) on which the Valuation Period was suspended in accordance with Section 5 herein or as a result of any Scheduled Trading Day being a Disrupted Day and including any day(s) by which the Valuation Period was extended pursuant to the provision below); and the "Termination Settlement Price" shall mean the arithmetic mean of the Relevant Prices of t he Shares for each Exchange Business Day in the Termination Valuation Period.

2. Automatic Termination Provisions. Notwithstanding anything to the contrary in Section 6 of the Agreement:

1. An Additional Termination Event with Counterparty as the sole Affected Party will automatically occur without any notice or action by GS&Co. or Counterparty if the price of the Shares on the Exchange at any time falls below the Termination Price (as specified in the related Supplemental Confirmation) provided that (for the avoidance of doubt only) such Additional Termination Event shall be an Additional Termination Event only with respect to the Transaction documented in such related Supplemental Confirmation. The Exchange Business Day that the price of the Shares on the Exchange at any time falls below the Termination Price will be the "Early Termination Date" for purposes of the Agreement.
3. Notwithstanding anything to the contrary in Section 6(d) of the Agreement, following the occurrence of such an Additional Termination Event, GS&Co. will notify Counterparty of the amount owing under Section 6(e) of the Agreement within a commercially reasonable time period (with such period based upon the amount of time, determined by GS&Co. (or any of its Affiliates) in its reasonable discretion, that it would take to unwind any of its Hedge Position(s) related to the Transaction in a commercially reasonable manner based on relevant market indicia). For purposes of the "Net Share Settlement Upon Early Termination" provisions herein, (i) the date that such notice is effective (the "Notice Date") shall constitute the "Net Share Valuation Date", (ii) the Exchange Business Day immediately following the Notice Date shall be the Net Share Settlement Date and (iii) all references to the Forward Cash Amount or the Fixed Amount in Annex B hereto shall be deemed to be the Early Termination Amount. For the avoidance of doubt, Hedge Position shall only mean any purchase, sale, entry into or maintenance of one or more stock borrowing transactions by GS&Co. or its Affiliates in respect of the Shares in connection with this Transaction and, notwithstanding the forgoing portions of this paragraph and Sections 6(d) and (e) of the Agreement, Counterparty shall be entitled to satisfy the Hedge Position by delivery of the Number of Early Settlement Shares as defined in and pursuant to the provisions of Section 10.

1. Special Provisions for Merger Events. Notwithstanding anything to the contrary herein or in the Equity Definitions, to the extent that an Announcement Date for a potential Merger Transaction occurs during any Valuation Period:

1. Promptly after request from GS&Co., Counterparty shall provide GS&Co. with written notice specifying (i) Counterparty's average daily Rule 10b-18 Purchases (as defined in Rule 10b-18) during the three full calendar months immediately preceding the Announcement Date that were not effected through GS&Co. or its affiliates and (ii) the number of Shares purchased pursuant to the proviso in Rule 10b-18(b)(4) under the Exchange Act for the three full calendar months preceding the Announcement Date. Such written notice shall be deemed to be a certification by Counterparty to GS&Co. that such information is true and correct. Counterparty understands that GS&Co. will use this information in calculating the trading volume for purposes of Rule 10b-18; and
2. GS&Co. in its sole discretion may (i) make adjustments to the terms of any Transaction, including, without limitation, the Valuation Date and the Number of Shares to account for the number of Shares that could be purchased on each day during the Valuation Period in compliance with Rule 10b-18 following the Announcement Date or (ii) treat the occurrence of the Announcement Date as an Additional Termination Event with Counterparty as the sole Affected Party.

"Merger Transaction" means any merger, acquisition or similar transaction involving a recapitalization as contemplated by Rule 10b-18(a)(13)(iv) under the Exchange Act.

1. Special Settlement Following Early Termination and Extraordinary Events. Notwithstanding anything to the contrary in this Master Confirmation or any Supplemental Confirmation hereunder, in the event that an Extraordinary Event under Article 12 of the Equity Definitions occurs or an Early Termination Date under Section 6 of the Agreement occurs or is designated with respect to any Transaction (each an "Affected Transaction"), then either party may elect, by notice to the other party, to have Counterparty deliver the Number of Early Settlement Shares to GS&Co. on the date that such notice is effective (provided that GS&Co. determines in its good faith sole discretion that such delivery is in compliance with any legal, regulatory or self-regulatory requirements or related policies and procedures), except for a term ination as a result of Section 7(d), in which event the date of delivery shall be the tenth Business Day thereafter. To the extent that Counterparty elects to deliver Shares to GS&Co. accompanied by an effective Registration Statement (satisfactory to GS&Co. in its reasonable discretion) covering such Early Settlement Shares, Counterparty must be in compliance with the conditions specified in (iii) though (ix) in Annex B hereto at the time of such delivery. If Counterparty elects to deliver Unregistered Shares (as defined in Annex B) to GS&Co., Counterparty and GS&Co. will negotiate in good faith on acceptable procedures and documentation relating to the sale of such Unregistered Shares.

"Number of Early Settlement Shares" means a number of Shares based on the Hedge Positions of GS&Co. or any of its Affiliates with respect to each Affected Transaction under this Master Confirmation at the time of the Extraordinary Event or Early Termination Date, as applicable.

In determining the amount of Loss under Section 6(e) of the Agreement or the Cancellation Amount under Article 12, the parties shall take into account the Floating Rate Amount that would have otherwise been due to Counterparty and the Fixed Amount that would have otherwise been due to GS&Co., and the difference between the New York 10b-18 Volume Weighted Average Price per share of the Shares over the Valuation Period as compared to the Forward Price. Further, if Counterparty delivers Early Settlement Shares, an amount equal to the product of (i)  the Number of Early Settlement Shares multiplied by (ii) the Forward Price (or if Counterparty delivers Unregistered Shares, as reduced by a discount determined by GS&Co. in a good faith commercially reasonable manner based on the discount to the New York 10b-18 Volume Weighted Average Price at which it could sell the Shares and whether GS&Co. and Counterparty have agreed on acceptable procedures and documentation relating to such Unregistered Shares as described above) shall be credited against any amount owing under Section 6(e) of the Agreement or pursuant to Article 12 of the Equity Definitions or otherwise under this Master Confirmation.

2. Acknowledgments. The parties hereto intend for:

1. Each Transaction to be a "securities contract" as defined in Section 741(7) of the U.S. Bankruptcy Code (Title 11 of the United States Code) (the "Bankruptcy Code"), a "swap agreement" as defined in Section 101(53B) of the Bankruptcy Code, or a "forward contract" as defined in Section 101(25) of the Bankruptcy Code, and the parties hereto to be entitled to the protections afforded by, among other sections, Sections 362(b)(6), 362(b)(17), 555, 556 and 560 of the Bankruptcy Code;
2. A party's right to liquidate or terminate any Transaction, net out or offset termination values of payment amounts, and to exercise any other remedies upon the occurrence of any Event of Default under the Agreement with respect to the other party to constitute a "contractual right" (as defined in the Bankruptcy Code);
3. All payments for, under or in connection with each Transaction, all payments for the Shares and the transfer of such Shares to constitute "settlement payments" and "transfers" (as defined in the Bankruptcy Code).

1. Set-Off. The parties agree to amend Section 6 of the Agreement by adding a new Section 6(f) thereto as follows:

"(f) Upon the occurrence of an Event of Default or Termination Event with respect to a party who is the Defaulting Party or the Affected Party ("X"), the other party ("Y") will have the right (but not be obliged) without prior notice to X or any other person to set-off or apply any obligation of X owed to Y (whether or not matured or contingent and whether or not arising under the Agreement, and regardless of the currency, place of payment or booking office of the obligation) against any obligation of Y owed to X (whether or not matured or contingent and whether or not arising under the Agreement, and regardless of the currency, place of payment or booking office of the obligation). Y will give notice to X of any set-off effected under this Section 6(f).

Amounts (or the relevant portion of such amounts) subject to set-off may be converted by Y into the Termination Currency at the rate of exchange at which such party would be able, acting in a reasonable manner and in good faith, to purchase the relevant amount of such currency. If any obligation is unascertained, Y may in good faith estimate that obligation and set-off in respect of the estimate, subject to the relevant party accounting to the other when the obligation is ascertained. Nothing in this Section 6(f) shall be effective to create a charge or other security interest. This Section 6(f) shall be without prejudice and in addition to any right of set-off, combination of accounts, lien or other right to which any party is at any time otherwise entitled (whether by operation of law, contract or otherwise)."

2. Payment Date Upon Early Termination. Notwithstanding anything to the contrary in Section 6(d)(ii) of the Agreement, all amounts calculated as being due in respect of an Early Termination Date under Section 6(e) of the Agreement will be payable on the day that notice of the amount payable is effective, except as otherwise provided in this Master Confirmation or any Supplemental Confirmation.
3. Share Settlement; Maximum Shares. Notwithstanding anything contained in this Master Confirmation, the Agreement or the Equity Definitions, Counterparty or GS&Co. at the election by Counterparty may satisfy all amounts it may owe to the other party hereunder and under each Supplemental Confirmation by delivery of Shares in accordance with Annex B and/or Section 10 hereof, and Counterparty is solely vested with the right to determine whether such obligations may be satisfied in Shares, in cash or in a combination of the two. Notwithstanding anything contained in this Master Confirmation, the Agreement or the Equity Definitions, Counterparty and GS&Co. agree that in the event Counterparty owes an amount to GS&Co. and Counterparty elects to satisfy its obligations to GS&Co. by delivery of Shares, the delivery of a number of Shares equal to the Reserved Shares will satisfy in full the obligation of Counterparty to make any payments pursuant to Section 6(e) of the Agreement, Article 12 of the Equity Definitions or otherwise in respect of the Transaction.
4. Governing Law. The Agreement, this Master Confirmation and each Supplemental Confirmation and all matters arising in connection with the Agreement, this Master Confirmation and each Supplemental Confirmation shall be governed by, and construed and enforced in accordance with, the laws of the State of New York without reference to its choice of law doctrine.
5. Offices.

1. The Office of GS&Co. for each Transaction is: One New York Plaza, New York, New York 10004.
2. The Office of Counterparty for each Transaction is: One Market Street, Spear Tower, Suite 2400, San Francisco, CA 94105.

1. Arbitration.

1. Arbitration is final and binding on Counterparty and GS&Co.
2. Counterparty and GS&Co. are waiving their right to seek remedies in court, including the right to a jury trial.
3. Pre-arbitration discovery is generally more limited than and different from court proceedings.
5. The arbitrators' award is not required to include factual findings or legal reasoning and any party's right to appeal or to seek modification of rulings by the arbitrators is strictly limited.
6. The panel of arbitrators will typically include a minority of arbitrators who were or are affiliated with the securities industry.

Any controversy between or among GS&Co. or its affiliates, or any of its or their partners, directors, agents or employees, on the one hand, and Counterparty or its agents and affiliates, on the other hand, arising out of or relating to the Agreement or any Transaction entered into hereunder, shall be settled by arbitration, in accordance with the then current rules of the American Arbitration Association ("AAA"), except that the provisions of this Section 17 shall supersede any conflicting or inconsistent provisions of such rules. Each party shall appoint a qualified arbitrator within 5 days after the giving of notice by either party. If either party shall fail timely to appoint a qualified arbitrator, the appointed, qualified arbitrator shall select the second qualified arbitrator within 5 days after such party's failure to appoint. The qualified arbitrators so appointed shall meet and shall, if possible, determine such matter within 10 days after the second qualified arbitrator is appointed, and their determination shall be binding on the parties. If for any reason such two qualified arbitrators fail to agree on such matter within such period of 10 days, then either party may request the AAA to appoint a qualified arbitrator who shall be impartial within 7 days of such request and both parties shall be bound by any appointment so made by the AAA. Within 7 days after the third qualified arbitrator has been appointed, each of the first two qualified arbitrators shall submit their respective determinations to the third qualified arbitrator who must select one or the other of such determinations (whichever the third qualified arbitrator believes to be correct or closest to a correct determination) within 7 days after the first two qualified arbitrators shall have submitted their respective determinations to the third qualified arbitrator, and the selection so made shall in all cases be binding upon the parties, and judgment upon such deci sion may be entered into any court having jurisdiction. In the event of the failure, refusal or inability of a qualified arbitrator to act, a successor shall be appointed within 10 days as hereinbefore provided. The costs of the arbitration shall be funded 50% by each party, and the parties shall bear their own attorneys' fees, during the arbitration. The prevailing party shall be repaid all of such expenses by the non-prevailing party within 10 days after the final determination of the qualified arbitrator(s). The award of the arbitrators shall be final, and judgment upon the award rendered may be entered in any court, state or Federal, having jurisdiction.

Neither party shall bring a putative or certified class action to arbitration, nor seek to enforce any pre-dispute arbitration agreement against any person who has initiated in court a putative class action; who is a member of a putative class who has not opted out of the class with respect to any claims encompassed by the putative class action until:

1. the class certification is denied;
2. the class is decertified; or
3. the party is excluded from the class by the court.

Such forbearance to enforce an agreement to arbitrate shall not constitute a waiver of any rights under the Agreement except to the extent stated herein.

[SIGNATURE PAGE FOLLOWS]

1. Counterparty hereby agrees (a) to check this Master Confirmation carefully and immediately upon receipt so that errors or discrepancies can be promptly identified and rectified and (b) to confirm that the foregoing (in the exact form provided by GS&Co.) correctly sets forth the terms of the agreement between GS&Co. and Counterparty with respect to any Transaction, by manually signing this Master Confirmation or this page hereof as evidence of agreement to such terms and providing the other information requested herein and immediately returning an executed copy to Equity Derivatives Documentation Department, facsimile No. 212-428-1980/83.

Yours sincerely,

GOLDMAN, SACHS & CO.

By /s/ Sharon Siebold            
Authorized Signatory

Agreed and Accepted By:

PG&E CORPORATION

By: /s/ Christopher P. Johns           
Name:
Title:

ANNEX A

SUPPLEMENTAL CONFIRMATION FOR FULLY UNCOLLARED TRANSACTIONS

To:	PG&E Corporation One Market Street, Spear Tower Suite 2400 San Francisco, CA 94105
From:	Goldman, Sachs & Co.
Subject:	Accelerated Share Repurchase Transaction - VWAP Pricing
Ref. No:	SDB1620840449
Date:	March 22, 2006

The purpose of this Supplemental Confirmation is to confirm the terms and conditions of the Transaction entered into between Goldman, Sachs & Co. ("GS&Co.") and PG&E Corporation ("Counterparty") (together, the "Contracting Parties") on the Trade Date specified below. This Supplemental Confirmation is a binding contract between GS&Co. and Counterparty as of the relevant Trade Date for the Transaction referenced below.

1. This Supplemental Confirmation supplements, forms part of, and is subject to the Master Confirmation dated as of November 16, 2005 (the "Master Confirmation") between the Contracting Parties, as amended and supplemented from time to time. The definitions and provisions contained in the Master Confirmation are incorporated into this Supplemental Confirmation, except as expressly modified below. In the event of any inconsistency between those definitions and provisions and this Supplemental Confirmation, this Supplemental Confirmation will govern.

2. The terms of the Transaction to which this Supplemental Confirmation relates are as follows:

Trade Date:	March 28, 2006
Forward Price:	USD 34.75 per Share
Number of Shares:	11,385,000 Shares
Valuation Period Start Date:	March 29, 2006
Valuation Date:	June 8, 2006
Termination Price:	$10.00 per Share
Fixed Rate:	25 basis points
Reserved Shares:	Two times the Number of Shares
Extraordinary Dividends:	Any cash dividend declared by the Issuer in excess of $0.00 per Share; provided that the cash dividend declared by the Counterparty in February 2006 shall not be an Extraordinary Dividend.
Initial Number of Daily Reference Shares:	227,700 Shares
Initial Notional Amount:	The Number of Shares multiplied by the Forward Price.
Counterparty Additional Payment Amount:	USD 3,757,050.00

[SIGNATURE PAGE FOLLOWS]

3. Counterparty represents and warrants to GS&Co. that neither it (nor any "affiliated purchaser" as defined in Rule 10b-18 under the Exchange Act) have made any purchases of blocks except through GS&Co. or an entity affiliated with GS&Co. pursuant to the proviso in Rule 10b-18(b)(4) under the Exchange Act during the four full calendar weeks immediately preceding the Trade Date.

Counterparty hereby agrees (a) to check this Supplemental Confirmation carefully and immediately upon receipt so that errors or discrepancies can be promptly identified and rectified and (b) to confirm that the foregoing (in the exact form provided by GS&Co.) correctly sets forth the terms of the agreement between GS&Co. and Counterparty with respect to this Transaction, by manually signing this Supplemental Confirmation or this page hereof as evidence of agreement to such terms and providing the other information requested herein and immediately returning an executed copy to Equity Derivatives Documentation Department, facsimile No. 212-428-1980/83.

Yours sincerely,
GOLDMAN, SACHS & CO.

By: /s/ Frank Hujber                          
Authorized Signatory

Agreed and Accepted
PG&E CORPORATION

By: /s/ G. Robert Powell                          

Name:     G. Robert Powell

Title:       Vice President and Controller

ANNEX B

NET SHARE SETTLEMENT PROCEDURES

In the event that the Counterparty has elected Net Share Settlement in accordance with the Master Confirmation, then the settlement procedure shall be as follows:

In the event that the sum of the Forward Cash Settlement Amount, the Fixed Amount, the Floating Rate Amount and the Counterparty Additional Payment Amount (the "Final Settlement Amount") is an amount GS&Co. owes Counterparty, settlement shall be made by delivery of the number of Shares equal in value to the Final Settlement Amount, with such Shares' value based on the Relevant Prices per Share further described below. In such event, on each succeeding Exchange Business Day after the Net Share Valuation Date, GS&Co. shall purchase one-half of the maximum amount of Shares Counterparty could purchase each day in accordance with the provisions of Rule 10b-18(2), (3) and (4), subject to any delays between the execution and reporting of a trade of the Shares on the Exchange and other circumstances beyond its reasonable control, until the sum of the products of the number of Shares purchased by GS&Co. multiplied by the Relevant Price for the regular trading session (including any extensions thereof) of the Exchange on the related Exchange Business Day equals the Final Settlement Amount. GS&Co. shall deliver all Shares purchased pursuant to this paragraph free of any contractual or other restriction, in good transferable form on the Third Exchange Business Day following the day on which GS&Co. completes all such purchases.

In the event that the Final Settlement Amount is an amount that Counterparty owes GS&Co., settlement shall be made by delivery of the number of Shares equal in value to the Final Settlement Amount (the "Settlement Shares"), with such Shares' value based on the Net Share Settlement Price. Delivery of such Settlement Shares shall be made free of any contractual or other restrictions in good transferable form (other than with respect to any Unregistered Shares (as defined below)) on the Net Share Settlement Date. Counterparty (i) shall represent and warrant to GS&Co. at the time of such delivery that it has good, valid and marketable title or right to sell and transfer all such Shares to GS&Co. under the terms of the related Transaction free of any lien charge, claim or other encumbrance and (ii) shall make the representations and agreements contained in Section 9.11(ii) through (iv) of the Equity Definitions to GS&Co. with respect to the Settlement Shares. GS&Co. or an y affiliate of GS&Co. designated by GS&Co. (GS&Co. or such affiliate, "GS") shall resell the Settlement Shares owed to GS&Co. during a period (the "Resale Period") commencing no earlier than the Exchange Business Day on which the Settlement Shares are delivered. GS shall use its good faith, commercially reasonable efforts to sell the Settlement Shares as promptly as possible at commercially reasonable prices based on prevailing market prices for the Shares. The Resale Period shall end on the Exchange Business Day on which GS completes the sale of all Settlement Shares or a sufficient number of Settlement Shares so that the realized net proceeds of such sales exceed the sum of Forward Cash Settlement Amount, the Fixed Amount and the Counterparty Additional Payment Amount. Notwithstanding the foregoing, if resale by GS of the Settlement Shares, as determined by GS in its sole discretion (i) occurs during a distribution for purposes of Regulation M, and if GS would be subject to the rest rictions of Rule 101 of Regulation M in connection with such distribution, the Resale Period will be postponed or tolled, as the case may be, until the Exchange Business Day immediately following the end of any "restricted period" as such term is defined in Regulation M with respect to such distribution under Regulation M or (ii) conflict with any legal, regulatory or self-regulatory requirements or related policies and procedures applicable to GS (whether or not such requirements, policies or procedures are imposed by law or have been voluntarily adopted by GS), the Resale Period will be postponed or tolled, as the case may be, until such conflict is no longer applicable. During the Resale Period, if the realized net proceeds from the resale of the Settlement Shares exceed the sum of the Forward Cash Settlement Amount, the Fixed Amount and the Counterparty Additional Payment Amount, GS shall refund such excess in cash to Counterparty by the close of business on the third Exchange Business Da y immediately following the last day of the Resale Period. If the sum of the Forward Cash Settlement Amount, the Fixed Amount and the Counterparty Additional Payment Amount exceeds the realized net proceeds from such resale, Counterparty shall transfer to GS by the open of the regular trading session on the Exchange on the third Scheduled Trading Day immediately following the last day of the Resale Period the amount of such excess (the "Additional Amount") in the number of Shares ("Make-whole Shares") in an amount that, based on the Net Share Settlement Price on the last day of the

Resale Period (as if such day was the "Net Share Valuation Date" for purposes of computing such Net Share Settlement Price), has a dollar value equal to the Additional Amount. The Resale Period shall continue to enable the sale of the Make-whole Shares. The requirements and provisions set forth below shall apply to Shares delivered to pay such Additional Amounts. This provision shall be applied successively until the Additional Amount is equal to zero.

Net Share Settlement of a Transaction by Counterparty is subject to the following conditions:

Counterparty at its sole expense shall:

(i) as promptly as practicable (but in no event more than five (5) Exchange Business Days immediately following the Settlement Method Election Date or, in the case of an election of Net Share Settlement upon the occurrence of an Extraordinary Event or an Early Termination Date, no more than one Exchange Business Day immediately following either the Cancellation Date or the Early Termination Date, as the case may be) file under the Securities Act and use its best efforts to make effective, as promptly as practicable, a registration statement or supplement or amend an outstanding registration statement, in any such case, in form and substance reasonably satisfactory to GS (the "Registration Statement") covering the offering and sale by GS of not less than 150% of the Shares necessary to fulfill the Net Share Settlement delivery obligation by Counterparty (determining the number of such Shares to be registered on the basis of the average of the Settlement Prices on t he five (5) Exchange Business Days prior to the date of such filing, amendment or supplement, as the case may be);

(ii) maintain the effectiveness of the Registration Statement until GS has sold all shares to be delivered by Counterparty necessary to satisfy its Net Share Settlement obligations;

(iii) have afforded GS and its counsel and other advisers a reasonable opportunity to conduct a due diligence investigation of Counterparty customary in scope for transactions in which GS acts as underwriter of equity securities, and GS shall have been satisfied (with the approval of its Commitments Committee in accordance with its customary review process) with the results of such investigation;

(iv) have negotiated and entered into a registration agreement with GS in substantially the form attached as Schedule 1, which such form the parties agree to amend by January 1, 2006 or anytime thereafter as mutually agreed by the parties in writing in order to reflect amendments to Rule 415 and Rule 462 and certain other rules set forth in Securities Act Release 33-8591 (the "Registration Agreement") covering the shares to be delivered by Counterparty in satisfaction of its Net Share Settlement obligations;

(v) have delivered to GS such number of prospectuses relating thereto as GS shall have reasonably requested and shall promptly update and provide GS with replacement prospectuses as necessary to ensure the prospectus does not contain any untrue statement of a material fact or any omission of a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances in which they were made, not misleading;

(vi) have retained for GS nationally-recognized underwriting counsel acceptable to GS (in its sole discretion) with broad experience in similar registered securities offerings and such counsel shall have agreed to act as such;

(vii) have taken all steps necessary for the shares sold by GS to be listed or quoted on the primary exchange or quotation system that the Shares are listed or quoted on;

(viii) have paid all reasonable and actual out-of-pocket costs and expenses of GS and all reasonable and actual fees and expenses of GS's outside counsel and other independent experts contemplated by the Registration Agreement; and

(ix) take such action as is required to ensure that GS's sale of the Shares does not violate, or result in a violation of, the federal or state securities laws.

In the event that the Registration Statement is not declared effective by the Securities Exchange Commission (the "SEC") or any of the conditions specified in (ii) through (ix) above are not satisfied on or prior to the Valuation Date (or, in the case of an election of Net Share Settlement upon the occurrence of an Extraordinary Event or an Early Termination Date, on or prior to the first Exchange Business Day following either the Cancellation Date or the Early Termination Date, as the case may be except for any Early Termination as result of Section 7(d) of the Master Confirmation, in which case, such date shall be the tenth Exchange Business Day following such Early Termination Date), then Counterparty may deliver Unregistered Shares to GS in accordance with the following conditions. If GS and Counterparty can agree on acceptable pricing, procedures and documentation relating to the sale of such Unregistered Shares (including, without limitation, applicable requirements in (iii) through (ix) above and insofar as pertaining to private offerings), then such Unregistered Shares shall be deemed to be the "Settlement Shares" for the purposes of the related Transaction and the settlement procedure specified in this Annex B shall be followed except that in the event that the Forward Cash Settlement Amount plus the Fixed Amount, exceeds the proceeds from the sale of such Unregistered Shares then for the purpose of calculating the number of "Make-whole Shares" to be delivered by Counterparty, GS shall determine the discount to the Net Share Settlement Price at which it can sell the Unregistered Shares. Notwithstanding the delivery of the Unregistered Shares, Counterparty shall endeavor in good faith to have a registration statement declared effective by the SEC as soon as practical. In the event that GS has not sold sufficient Unregistered Shares to satisfy Counterparty's obligations to GS contained herein at the time that a Registration Statement covering the offering and sale by GS of a number of Shares equal in value to not less than 150% of the amount then owed to GS is declared effective (based on the Net Share Settlement Price on the Exchange Business Day (as if such Exchange Business Day were the "Net Share Valuation Date" for purposes of computing such Net Share Settlement Price) that the Registration Statement was declared effective), GS shall return all unsold Unregistered Shares to Counterparty and Counterparty shall deliver such number of Shares covered by the effective Registration Statement equal to 100% of the amount then owed to GS based on such Net Share Settlement Price. Such delivered shares shall be deemed to be the "Settlement Shares" for the purposes of the related Transaction and the settlement procedure specified in this Master Confirmation, including, without limitation, this Annex B, (including the obligation to deliver any Make-whole Shares, if applicable) shall be followed. In all cases GS shall be entitled to take any and all required actions in the course of its sales of the Settleme nt Shares, including without limitation making sales of the Unregistered Shares only to "Qualified Institutional Buyers" (as such term is defined under the Securities Act), to ensure that the sales of the Unregistered Shares and the Settlement Shares covered by the Registration Statement are not integrated resulting in a violation of the securities laws and Counterparty agrees to take all actions requested by GS in furtherance thereof.

If GS and Counterparty cannot agree on acceptable pricing, procedures and documentation relating to the sales of such Unregistered Shares then the number of Unregistered Shares to be delivered to GS pursuant to the provisions above shall not be based on the Net Share Settlement Price but rather GS shall determine the value attributed to each Unregistered Share in a commercially reasonable manner and based on such value Counterparty shall deliver a number of Shares equal in value to the Forward Cash Settlement Amount plus the Fixed Amount. For the purposes hereof "Unregistered Shares" means Shares that have not been registered pursuant to an effective registration statement under the Securities Act or any state securities laws ("Blue Sky Laws") and that cannot be sold, transferred, pledged or otherwise disposed of without registration under the Securities Act or under applicable Blue Sky Laws unless such sale, transfer, pledge or other disposition is made in a transa ction exempt from registration thereunder.

In the event that Counterparty delivers Shares pursuant to an election of Net Share Settlement, then Counterparty and GS agree to indemnify and hold harmless each other to the extent provided in the Registration Agreement.

In no event shall the number of Settlement Shares (including, but without duplication or double counting, any Unregistered Shares) and any Make-whole Shares deliverable by Counterparty hereunder to GS&Co., be greater than the Reserved Shares minus the amount of any Shares actually delivered under any other Transaction(s) under this Master Confirmation (the result of such calculation, the "Capped Number"). Counterparty represents and warrants (which shall be deemed to be repeated on each day that a Transaction is outstanding) that the Capped Number is equal to or less than the number of Shares determined according to the following formula:

A - B

Where A = the number of authorized but unissued shares of the Issuer that are not reserved for future issuance on the date of the determination of the Capped Number; and

B = the maximum number of Shares required to be delivered to third parties if Counterparty elected Net Share Settlement of all transactions in the Shares (other than Transactions in the Shares under this Master Confirmation) with all third parties that are then currently outstanding and unexercised.

SCHEDULE 1

Form of Registration Agreement

PG&E Corporation

Common Stock

Registration Agreement

[ ] [  ], 2005

Goldman, Sachs & Co.
85 Broad Street
New York, New York 10004

Ladies and Gentlemen:

PG&E Corporation, a California corporation (the "Company"), proposes to deliver to Goldman, Sachs & Co. ("GS&Co.") pursuant to this Registration Agreement (this "Agreement") up to [_____] shares of common stock (no par value) ("Stock") of the Company (the "Shares") in satisfaction of the Company's obligations to GS&Co., as counterparty under an Accelerated Share Repurchase Transaction, Reference Number [_____], as documented pursuant to a Master Confirmation (the "Master Confirmation"), dated as of [ ] [ ], 2005 (the Master Confirmation, as may be amended, restated, supplemented or otherwise modified from time to time, the "ASB"), subject to the terms and conditions stated herein and in the ASB. The Company does not expect to receive any proceeds from the sale of the Shares.

1. The Company represents and warrants to, and agrees with, GS&Co. that:
1. A registration statement on Form S-3, as amended (File No. 333- 121518) (including all documents incorporated by reference in the prospectus contained therein, the "Initial Registration Statement"), in respect of the Shares and the offering thereof from time to time in accordance with Rule 415 under the Securities Act of 1933, as amended (the "Securities Act"), has been filed with the Securities and Exchange Commission (the "Commission"); the Initial Registration Statement and any post-effective amendment thereto, each in the form heretofore delivered to GS&Co. (excluding exhibits thereto), have been declared effective by the Commission in such form; no other document with respect to the Initial Registration Statement has heretofore been filed with the Commission; and no stop order suspending the effectiveness of the Initial Registration Statement or any post-effective amendment thereto has been issued and no proceeding for that purpose has been initiated or threatened by the Commission (any prelimin ary prospectus included in the Initial Registration Statement or filed with the Commission pursuant to Rule 424(a) of the rules and regulations of the Commission under the Securities Act is hereinafter called a "Preliminary Prospectus"; the various parts of the Initial Registration Statement, including all exhibits thereto and including the documents incorporated by reference in the prospectus contained in the Initial Registration Statement at the time such part of the Initial Registration Statement became effective, each as amended at the time such part of the Initial Registration Statement became effective are hereinafter collectively called the "Registration Statement"; such final prospectus, in the form first filed pursuant to Rule 424(b) under the Securities Act, is hereinafter called the "Prospectus"; any reference herein to any Preliminary Prospectus or the Prospectus shall be deemed to refer to and include the documents incorporated by reference therein pursuant to Item 12 of Form S-3 under the Secur ities Act, as of the date of such Preliminary Prospectus or Prospectus, as the case may be; and any reference to any amendment or supplement to any

Preliminary Prospectus or the Prospectus shall be deemed to refer to and include any documents filed after the date of such Preliminary Prospectus or Prospectus, as the case may be, under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and incorporated by reference in such Preliminary Prospectus or Prospectus, as the case may be; and any reference to any amendment to the Registration Statement shall be deemed to refer to and include any annual report of the Company filed pursuant to Section 13(a) or 15(d) of the Exchange Act after the effective date of the Initial Registration Statement that is incorporated by reference in the Registration Statement);

2. No order preventing or suspending the use of any Preliminary Prospectus has been issued by the Commission, and each Preliminary Prospectus, at the time of filing thereof, conformed in all material respects to the requirements of the Securities Act and the rules and regulations of the Commission thereunder, and did not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, however, that this representation and warranty shall not apply to any statements or omissions made in reliance upon and in conformity with information furnished in writing to the Company by GS&Co. expressly for use in any Preliminary Prospectus;
3. The documents incorporated by reference in the Prospectus, when they became effective or were filed with the Commission, as the case may be, conformed in all material respects to the requirements of the Securities Act or the Exchange Act, as applicable, and the rules and regulations of the Commission thereunder, and none of such documents contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading; and any further documents so filed and incorporated by reference in the Prospectus or any further amendment or supplement thereto, when such documents become effective or are filed with the Commission, as the case may be, will conform in all material respects to the requirements of the Securities Act or the Exchange Act, as applicable, and the rules and regulations of the Commission thereunder and will not contain an untrue statement of a material fact or omit to state a material fact required to b e stated therein or necessary to make the statements therein not misleading;
4. The Registration Statement conforms, and the Prospectus and any further amendments or supplements to the Registration Statement or the Prospectus will conform, in all material respects to the requirements of the Securities Act and the rules and regulations of the Commission thereunder and do not and will not, as of the applicable effective date as to the Registration Statement and any amendment thereto, and as of the applicable filing date as to the Prospectus and any amendment or supplement thereto, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that this representation and warranty shall not apply to any statements or omissions made in reliance upon and in conformity with information furnished in writing to the Company by GS&Co. expressly for use in the Registration Statement or the Prospectus;
5. Neither the Company nor any of its subsidiaries has sustained since the date of the latest audited financial statements included in the Prospectus any material loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, otherwise than as set forth or contemplated in the Prospectus; and, since the respective dates as of which information is given in the Registration Statement and the Prospectus, there has not been any material change in the capital stock (other than changes occurring in the

ordinary course of business and changes resulting from transactions relating to employee benefit plans or dividend reinvestment, stock option, stock award, retirement and stock purchase plans or repurchases of capital stock by the Company, including repurchases associated with the ASB) or any material increase in the long-term debt of the Company or any of its subsidiaries or any material adverse change, or any development which would reasonably be expected to result in a material adverse change, in or affecting the general affairs, management, financial position, shareholders' equity or results of operations of the Company and its subsidiaries, otherwise than as set forth or contemplated in the Prospectus;

6. The Company has been duly incorporated and is a validly existing corporation in good standing under the laws of the State of California, with corporate power and authority to own its properties and conduct its business as described in the Prospectus;
7. Each corporation, association, partnership or other business entity of which more than 50% of the total voting power or other interests entitled to vote in the election of directors, managers or trustees thereof that is deemed by the Company to be significant to its operations, as set forth on Schedule I hereto, and that is controlled, directly or indirectly, by (i) the Company, (ii) the Company and one or more subsidiaries or (iii) one or more subsidiaries of the Company (each, a "Subsidiary" and collectively, the "Subsidiaries"), has been duly incorporated or organized and is a validly existing corporation, partnership or limited liability company in good standing under the laws of the jurisdiction of its incorporation or organization with corporate, partnership or limited liability company power and authority, as applicable, to own its properties and conduct its business as described in the Prospectus; all of the issued and outstanding capital stock, partnership or membership interests of each Su bsidiary has been duly authorized and validly issued and is fully paid and nonassessable; and, except as disclosed in the Prospectus, the capital stock or membership interests of each Subsidiary are owned directly or indirectly by the Company, free and clear of all liens, encumbrances and defects;
8. The Company has an authorized capitalization as set forth in the Prospectus, and all of the issued shares of capital stock of the Company have been duly authorized and validly issued, are fully paid and non-assessable and conform in all material respects to the description of the Stock contained in the Prospectus;
9. The Shares have been duly and validly authorized and, when issued and delivered as provided herein, will be duly and validly issued and fully paid and non-assessable and will conform to the description of the Stock contained in the Prospectus; upon delivery of the Shares to GS&Co. pursuant to this Agreement, good and valid title to the Shares, free and clear of liens, encumbrances, equities or claims, will pass to GS&Co.; and, other than the delivery of (i) an opinion of counsel and (ii) the Prospectus and, if required, an amendment or supplement thereto, clauses (i) - (iv) of Section 9.11 of the Equity Definitions (as defined in the ASB) apply to the Shares and the delivery of the Shares to GS&Co.;
10. The issuance and delivery of Shares by the Company and the compliance by the Company with all of the provisions of this Agreement and the consummation of the transactions herein contemplated will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument to which the Company or any of its subsidiaries is a party or by which the Company or any of its subsidiaries is bound or to which any of the property or assets of the Company or any of its subsidiaries is subject, except any such conflict, breach, violation or default which has been consented to or waived by the appropriate counterparty thereto, prior to the execution and delivery of this Agreement, nor

will such action result in any violation of the provisions of the Certificate of Incorporation or By-laws of the Company or any statute or any order, rule or regulation of any court or governmental agency or body having jurisdiction over the Company or any of its subsidiaries or any of their properties, except for conflicts, breaches, violations or defaults (other than any relating to the Articles of Incorporation or By-Laws of the Company) that would not, individually or in the aggregate, impair the Company's ability to consummate the transactions herein contemplated; and no consent, approval, authorization, order, registration or qualification of or with any such court or governmental agency or body is required on the part of the Company for the sale of the Shares or the consummation by the Company of the transactions contemplated by this Agreement, except (i) the registration under the Securities Act of the Shares and such consents, approvals, authorizations, registrations or qualifications as may be r equired under state securities or Blue Sky laws in connection with the sale of the Shares by GS&Co. and (ii) where the failure to obtain such consent, approval, authorization, order, registration or qualification would not, individually or in the aggregate, impair the Company's ability to consummate the transactions herein contemplated;

11. None of the Company or its subsidiaries is (i) in violation of its Articles of Incorporation or By-Laws (or similar organizational document), or (ii) in default (nor has any event occurred which with notice or passage of time, or both, would constitute a default) in the performance or observance of any material obligation, agreement, covenant or condition contained in any indenture, mortgage, deed of trust, loan agreement or other material agreement or instrument to which it is a party or to which it is subject;
12. The statements set forth in the Prospectus under the caption "Description of Capital Stock," insofar as they purport to constitute a summary of the terms of the Stock, and the statements under the caption "Plan of Distribution", insofar as they purport to describe the provisions of the laws and documents referred to therein, are accurate, complete and fair in all material respects; and the statements in the Prospectus with respect to the ASB are accurate, complete and fair in all material respects; provided, however, that this representation and warranty shall not apply to any statements or omissions made in reliance upon and in conformity with information furnished in writing to the Company by GS&Co. expressly for use in the Registration Statement or Prospectus;
13. Other than with GS&Co. or as set forth in the Prospectus, there are no contracts, agreements or understandings between the Company and any person granting such person the right to require the Company to file a registration statement under the Securities Act with respect to any securities of the Company owned or to be owned by such person or to require the Company to include such securities in the securities registered pursuant to the Registration Statement or in any securities being registered pursuant to any other registration statement filed by the Company under the Securities Act;
14. Other than as set forth in the Prospectus, there are no legal or governmental proceedings pending to which the Company or any of its subsidiaries is a party or of which any property of the Company or any of its subsidiaries is the subject, which, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a material adverse effect on the current or future consolidated financial position, shareholders' equity or results of operations of the Company and its subsidiaries; and, to the Company's knowledge, no such proceedings are threatened or contemplated by governmental authorities or threatened by others;
16. The Company is not and, after giving effect to the offering and sale of the Shares, will not be an "investment company", as such term is defined in the Investment Company Act of 1940, as amended;
17. Neither the Company nor any of its affiliates does business with the government of Cuba or with any person or affiliate located in Cuba within the meaning of Section 517.075 of the Florida Statutes;
18. Deloitte & Touche LLP, who have certified certain financial statements of the Company and its subsidiaries and have audited the Company's internal control over financial reporting and management's assessment thereof, are an independent registered public accounting firm as required by the Securities Act and the rules and regulations of the Commission and the Public Company Accounting Oversight Board (United States) (the "PCAOB") thereunder;
19. The Company maintains a system of internal control over financial reporting (as such term is defined in Rule 13a-15(f) of the Exchange Act) that complies with the requirements of the Exchange Act and has been designed by the Company's principal executive officer and principal financial officer, or under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; except as disclosed in the Prospectus, the Company's internal control over financial reporting is effective and the Company is not aware of any material weaknesses in its internal control over financial reporting;
20. Except as disclosed in the Prospectus, since the date of the latest audited financial statements included in the Prospectus, there has been no change in the Company's internal control over financial reporting that has materially adversely affected, or is reasonably likely to materially adversely affect, the Company's internal control over financial reporting;
21. The Company maintains disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Exchange Act) that comply with the requirements of the Exchange Act; such disclosure controls and procedures have been designed to ensure that material information relating to the Company and its subsidiaries is made known to the Company's management, including its principal executive officer and principal financial officer, by others within those entities; except as disclosed in the Prospectus, such disclosure controls and procedures are effective;
22. Prior to the date hereof, neither the Company nor any of its subsidiaries has taken any action which is designed to or which has constituted or which might have been expected to cause or result in stabilization or manipulation of the price of any security of the Company or any of its subsidiaries in connection with the offering of securities of the Company contemplated hereby;
23. The financial statements of the Company included in the Prospectus present fairly in all material respects the financial position of the Company and its consolidated subsidiaries as of the dates shown and their results of operations and cash flows for the periods shown, and such financial statements have been prepared in conformity with generally accepted accounting principles in the United States applied on a consistent basis, subject, in the case of interim statements, to normal year-end adjustments;
25. The common stock of the Company is registered pursuant to Section 12(b) of the Exchange Act and the outstanding shares of common stock (including the Shares) are listed for quotation on the New York Stock Exchange (the "NYSE"), and the Company has taken no action designed to, or likely to have the effect of, terminating the registration of the common stock under the Exchange Act or de-listing the common stock from the NYSE, nor has the Company received any notification that the Commission or the NYSE is contemplating terminating such registration or listing;
26. The Company acknowledges and agrees that (i) in connection with the sale of Shares pursuant to this Agreement and with the process leading to such transaction GS&Co. is acting solely as a principal and not the agent or fiduciary of the Company, (ii) GS&Co. has not assumed an advisory or fiduciary responsibility in favor of the Company with respect to the offering contemplated hereby or the process leading thereto (irrespective of whether GS&Co. has advised or is currently advising the Company on other matters) or any other obligation to the Company except the obligations expressly set forth in this Agreement and (iv) the Company has consulted its own legal and financial advisors to the extent it deemed appropriate. The Company agrees that it will not claim that GS&Co. has rendered advisory services of any nature or respect, or owes a fiduciary or similar duty to the Company, in connection with such transaction or the process leading thereto; and
27. All of the representations and warranties of the Company in or made pursuant to the ASB are true and correct as of the time when made, when required to be made and when deemed to be repeated, in each case as specified therein.
2. Upon the delivery of the Shares to GS&Co. and the satisfaction or waiver of the conditions set forth in Section 6 of this Agreement, GS&Co. proposes to offer the Shares from time to time for sale upon the terms and conditions set forth in the Prospectus. GS&Co. intends to sell only such number of Shares so that the realized proceeds (net of customary expenses and commissions as set forth below) of such sales (the "Proceeds") are equal to the amount that the Company owes to GS&Co. under the ASB, and all of the Proceeds of such sales shall be retained by GS&Co. in satisfaction of the Company's obligations under the ASB. Once GS&Co. has sold such number of Shares so that the Proceeds of such sales are equal to the amount that the Company owes to GS&Co. under the ASB, and the Company's obligations to GS&Co. under the ASB shall have been satisfied in full, any Shares that have been delivered to but not sold by GS&Co. shall be promptly returned to the Company and any Proce eds in excess of the amount that was owed by the Company to GS&Co. under the ASB shall be promptly refunded to the Company. All commissions and customary expenses incurred by GS&Co. in connection with the sale of the Shares set forth in Section 5 of this Agreement shall be deemed to be incurred for the Company's account, and not for the account of GS&Co. and shall be paid by the Company. In no event shall commissions exceed 2.00% of the sales price of the shares.
3. The Shares to be delivered to GS&Co. hereunder, in definitive form, and in such authorized denominations and registered in such names as GS&Co. may request upon at least forty-eight hours' prior notice to the Company, shall be delivered by or on behalf of the Company to GS&Co., through the facilities of The Depository Trust Company ("DTC"), for the account of GS&Co. The Company will cause the certificates representing the Shares to be made available for checking and packaging at least twenty-four hours prior to the Time of Delivery (as defined below) at the office of DTC or its designated custodian (the "Designated Office"). The time and date of such delivery shall be 9:30 a.m., New York City time, on [ ___ ], 2005 or such other time and date as GS&Co. and the Company may agree upon in writing. Such time and date for delivery of the Shares is herein called the "Time of Delivery".

The documents to be delivered at the Time of Delivery by or on behalf of the parties hereto pursuant to Section 6 hereof, including the cross receipt for the Shares and any additional documents requested by GS&Co. pursuant to Section 6(j) hereof, will be delivered at the offices of Cadwalader, Wickersham & Taft LLP, One

World Financial Center, New York, New York 10281 (the "Closing Location"), and the Shares will be delivered at the Designated Office, all at the Time of Delivery. A meeting will be held at the Closing Location at 4:00 p.m., New York City time, on the New York Business Day next preceding the Time of Delivery, at which meeting the final drafts of the documents to be delivered pursuant to the preceding sentence will be available for review by the parties hereto. For the purposes of this Section 3, "New York Business Day" shall mean each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in New York are generally authorized or obligated by law or executive order to close.

4. The Company agrees with GS&Co.:
1. To prepare the Prospectus in a form approved by GS&Co. and to file such Prospectus pursuant to Rule 424(b) under the Securities Act not later than the Commission's close of business on the second business day following the execution and delivery of this Agreement, or, if applicable, such earlier time as may be required by Rule 430A(a)(3) under the Securities Act; maintain the effectiveness of the Registration Statement until GS&Co. has sold all of the Shares to be sold as provided in Section 2 hereof; to make no further amendment or any supplement to the Registration Statement or Prospectus (other than by filing a document under the Exchange Act in the ordinary course of business, which will be incorporated by reference into the Registration Statement or the Prospectus) which shall be disapproved by GS&Co. after reasonable notice thereof; to advise GS&Co., promptly after the Company receives notice thereof, of the time when any amendment to the Registration Statement has been filed or bec omes effective or any supplement to the Prospectus or any amended Prospectus has been filed and to furnish GS&Co. with copies thereof; to file promptly all reports and any definitive proxy or information statements required to be filed by the Company with the Commission pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of the Prospectus and for so long as the delivery of a prospectus is required in connection with the offering or sale of the Shares; to advise GS&Co., promptly after the Company receives notice thereof, of the issuance by the Commission of any stop order or of any order preventing or suspending the use of any Preliminary Prospectus or prospectus, of the suspension of the qualification of the Shares for offering or sale in any jurisdiction, of the initiation or threatening of any proceeding for any such purpose, or of any request by the Commission for the amending or supplementing of the Registration Statement or Prospectus or for additional inform ation; and, in the event of the issuance of any stop order or of any order preventing or suspending the use of any Preliminary Prospectus or prospectus or suspending any such qualification, promptly to use its best efforts to obtain the withdrawal of such order;
2. Promptly from time to time to take such action as GS&Co. may reasonably request to qualify the Shares for offering and sale under the securities laws of such jurisdictions as GS&Co. may request and to comply with such laws so as to permit the continuance of sales and dealings therein in such jurisdictions for as long as may be necessary to complete the sale of all of the Shares to be sold as provided in Section 2, provided that in connection therewith the Company shall not be required to qualify as a foreign corporation or to file a general consent to service of process in any jurisdiction;
3. Prior to 10:00 a.m., New York City time, on the New York Business Day next succeeding the date of this Agreement and from time to time, to furnish GS&Co. with written and electronic copies of the Prospectus in New York City in such quantities as it may reasonably request, and, if the delivery of a prospectus is required at any time prior to the time of the completion of the offering or sale of the Shares to be sold as provided in Section 2 and if at such time any event shall have occurred as a result of which the Prospectus as then amended or supplemented would include an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made when such Prospectus is delivered, not misleading, or, if for any other reason it shall be necessary during such period to amend or supplement the Prospectus or to file under the Exchange Act any document incorporated by reference in the Prospectus in o rder to comply with the Securities Act or the Exchange Act, to notify GS&Co. and

upon its request to file such document and to prepare and furnish without charge to GS&Co. and to any dealer in securities as many written and electronic copies as GS&Co. may from time to time reasonably request of an amended Prospectus or a supplement to the Prospectus which will correct such statement or omission or effect such compliance, and in case GS&Co. is required to deliver a prospectus in connection with sales of any of the Shares at any time nine months or more after the time of issue of the Prospectus, upon your request but at the expense of GS&Co., to prepare and deliver to GS&Co. as many written and electronic copies as you may request of an amended or supplemented Prospectus complying with Section 10(a)(3) of the Securities Act;

4. To make generally available to its securityholders as soon as practicable, but in any event not later than eighteen months after the effective date of the Registration Statement (as defined in Rule 158(c) under the Securities Act), an earnings statement of the Company and its subsidiaries (which need not be audited) complying with Section 11(a) of the Securities Act and the rules and regulations thereunder (including, at the option of the Company, Rule 158);
5. If not otherwise available on EDGAR or a similar system during a period of five years from the effective date of the Registration Statement, to furnish to its shareholders as soon as practicable after the end of each fiscal year, but in any event within the time period after the end of each fiscal year of the Company that would have been required of the Company under Form 10-K, an annual report (including a balance sheet and statements of income, shareholders' equity and cash flows of the Company and its consolidated subsidiaries certified by independent public accountants) and, as soon as practicable after the end of each of the first three quarters of each fiscal year (beginning with the fiscal quarter ending after the effective date of the Registration Statement), but in any event within the time period after the end of each fiscal quarter of the Company that would have been required of the Company under Form 10-Q, to make available to its shareholders consolidated summary financial information of the Company and its subsidiaries for such quarter in reasonable detail;
6. If not otherwise available on EDGAR or a similar system during a period of five years from the effective date of the Registration Statement, to furnish to GS&Co. copies of all reports or other communications (financial or other) furnished to shareholders, and to deliver to GS&Co. (i) as soon as they are available, copies of any reports and financial statements furnished to or filed with the Commission or any national securities exchange on which any class of securities of the Company is listed; and (ii) such additional information concerning the business and financial condition of the Company as GS&Co. may from time to time reasonably request (such financial statements to be on a consolidated basis to the extent the accounts of the Company and its subsidiaries are consolidated in reports furnished to its shareholders generally or to the Commission); provided that the Company shall not be required to deliver any information that would cause the Company to make a public disclosure under Regulation FD as promulgated under the Exchange Act; and
7. Upon request of GS&Co., to furnish, or cause to be furnished, to GS&Co. an electronic version of the Company's trademarks, servicemarks and corporate logo for use on the website, if any, operated by GS&Co. for the purpose of facilitating the on-line offering of the Shares (the "License"). The License shall be granted without any fee.
5. The Company covenants and agrees with GS&Co. that the Company will pay or cause to be paid the following: (i) the fees, disbursements and expenses of the Company's counsel and accountants and of outside counsel to GS&Co. and other independent experts retained by GS&Co. in connection with the registration of the Shares under the Securities Act and all other expenses in connection with the preparation, printing and filing of the Registration Statement, any Preliminary Prospectus and the Prospectus and amendments and supplements thereto and the mailing and delivering of copies thereof to GS&Co. and dealers; (ii) the cost of printing or producing this Agreement, the Blue Sky Memorandum, closing documents (including any compilations thereof) and any other documents in connection with the offering, sale and delivery of the

Shares; (iii) all expenses in connection with the qualification of the Shares for offering and sale under state securities laws as provided in Section 4(b) hereof, including the fees and disbursements of counsel for GS&Co. in connection with such qualification and in connection with the Blue Sky survey; (iv) the cost of preparing stock certificates; (v) the cost and charges of any transfer agent or registrar; and (vi) all other reasonable and actual costs and expenses incident to the performance of its obligations hereunder. Except as provided in this Section 5 and Section 7 of this Agreement, GS&Co. shall pay all other expenses it incurs in connection with the registration, offering and sale of the Shares.

6. The obligations of GS&Co. to accept the Shares to be delivered at the Time of Delivery in satisfaction of the Company's obligations under the ASB, and the obligations of GS&Co. hereunder with respect to the Shares to be delivered at the Time of Delivery, shall be subject, in its discretion, to the condition that all representations and warranties and other statements of the Company herein and in the ASB are, at and as of the Time of Delivery, as of the time when made, (and when required to be made and deemed to be repeated with respect to the representations and warranties and other statements of the Company in the ASB, in each case as specified therein), true and correct, the condition that the Company shall have performed all of its obligations hereunder and under the ASB theretofore to be performed, and the following additional conditions:
1. The Prospectus (the form of which was previously approved by GS&Co.) shall have been filed with the Commission pursuant to Rule 424(b) within the applicable time period prescribed for such filing by the rules and regulations under the Securities Act and in accordance with Section 4(a) hereof; no stop order suspending the effectiveness of the Registration Statement or any part thereof shall have been issued and no proceeding for that purpose shall have been initiated or threatened by the Commission; and all requests for additional information on the part of the Commission shall have been complied with to GS&Co.'s reasonable satisfaction;
2. Cadwalader, Wickersham & Taft LLP, counsel for GS&Co., shall have furnished to GS&Co. their written opinion (a draft of such opinion is attached as Annex II(a) hereto), dated the Time of Delivery, and such counsel shall have received such papers and information as they may reasonably request to enable them to pass upon such matters;
3. Orrick, Herrington & Sutcliffe LLP, counsel for the Company, shall have furnished to GS&Co. their written opinion (a draft of such opinion is attached as Annex II(b) hereto), dated the Time of Delivery, in form and substance satisfactory to GS&Co., to the effect that:
1. The Company and Pacific Gas and Electric Company, a California corporation (the "Utility") have each been duly incorporated and are validly existing and in good standing under the laws of the State of California. The Company has all necessary corporate power and authority to execute, deliver and perform its obligations under this Agreement and to own and hold its properties and conduct its business as described in the Registration Statement.
2. This Agreement and the ASB have been duly authorized, executed and delivered by the Company.
3. The statements in the Prospectus under the caption "Description of Capital Stock," insofar as they purport to constitute a summary of the terms of the Shares, and under the caption "Plan of Distribution," only to the extent that they purport to constitute summaries of United States federal statutes, rules and regulations, or portions thereof, and agreements referred to therein are accurate and fair in all material respects.
4. The Registration Statement and the Prospectus and any further amendments and supplements thereto made by the Company prior to the date hereof appear on their face to

be appropriately responsive in all material respects to the requirements of the Securities Act and the rules and regulations of the Commission under the Securities Act except for the financial statements, financial statement schedules and other financial data included or incorporated by reference in or omitted from either of them, as to which we express no opinion; and each document filed under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and incorporated by reference in the Registration Statement and Prospectus (except for financial statements, financial statement schedules and other financial data included in either of them, as to which we express no opinion) appears on its face to be appropriately responsive in all material respects when so filed to the requirements of the Exchange Act and the rules and regulations under the Exchange Act.

5. The Company is not required to be registered as an investment company under the Investment Company Act of 1940, as amended, and the rules and regulations of the Commission promulgated thereunder.

Such counsel shall also state that they have participated in the preparation of the Registration Statement and the Prospectus and are familiar with the documents incorporated by reference therein and, although the limitations inherent in the independent verification of factual matters and in the role of outside counsel are such that they have not undertaken to investigate or verify independently, and do not assume responsibility for, the accuracy, completeness or fairness of the statements contained in either of them (other than as explicitly stated in paragraph (iv) above), based upon such participation (and relying as to certain factual matters in their evaluation of materiality to the extent they deemed reasonable on officers, employees and other representatives of the Company), no facts have come to their attention that led them to believe that (a) the Registration Statement or any amendment (except for the financial statements, financial statement schedules and other financial data included or in corporated by reference in or omitted from those documents, as to which such counsel may express no such belief), at the time it became effective, contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading or (b) the Prospectus or any amendment or supplement (except for the financial statements, financial statement schedules and other financial data included or incorporated by reference in or omitted from those documents, as to which such counsel may express no such belief), at the time the Prospectus was issued or on the date of such counsel's opinion, included or includes an untrue statement of a material fact or omitted or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading. Such counsel does not know of any amendment to the Registration Statement required to be filed or of any contract s or other documents of a character required to be filed as an exhibit to the Registration Statement or required to be incorporated by reference into the Prospectus or required to be described in the Registration Statement or the Prospectus which are not filed or incorporated by reference or described as required.

4. Bruce R. Worthington, Esq., Senior Vice President and General Counsel of the Company, shall have furnished to GS&Co. his written opinion (a draft of such opinion is attached as Annex II(c) hereto), dated the Time of Delivery, in form and substance satisfactory to GS&Co., to the effect that:
1. The Shares to be delivered at the Time of Delivery have been duly authorized and, when delivered and paid for in accordance with this Agreement, will be validly issued and outstanding, fully paid and non-assessable. All of the issued and outstanding shares of common stock of the Utility have been duly authorized and are validly issued and outstanding, fully paid and non-assessable, are owned of record directly or indirectly by the

Company and, to such counsel's knowledge, are owned free and clear of all liens, encumbrances, equities or claims, except as disclosed in the Prospectus.

2. The Registration Statement and the Prospectus and any further amendments and supplements thereto made by the Company prior to the date hereof appear on their face to be appropriately responsive in all material respects to the requirements of the Securities Act and the rules and regulations of the Commission under the Securities Act except for the financial statements, financial statement schedules and other financial data included or incorporated by reference in or omitted from either of them, as to which such counsel may express no opinion; and each document filed under the Exchange Act, and incorporated by reference in the Registration Statement and Prospectus (except for financial statements, financial statement schedules and other financial data included in either of them, as to which such counsel may express no opinion) appears on its face to be appropriately responsive in all material respects when so filed to the requirements of the Exchange Act and the rules and regulations under the Exchange Act .
3. The compliance by the Company with all of the provisions of this Agreement applicable to it and the performance by the Company of its obligations hereunder will not (i) result in a violation of Company's Articles of Incorporation, as amended, or By-Laws, as amended, (ii) breach or result in a default under any agreement, indenture or instrument listed as an Exhibit to the Registration Statement or (iii) violate any Applicable Law (other than any state securities laws, as to which such counsel may express no opinion) or any judgment, order or decree of any court or arbitrator known to such counsel, except in the case of clauses (ii) and (iii) where the breach or violation would not have a material adverse effect on the Company and its subsidiaries taken as a whole. For purposes of this opinion, the term "Applicable Law" means the federal laws of the United States and the laws of the State of California, in each case which, in such counsel's experience, are normally applicable to the transactions of the t ype contemplated by this Agreement.
4. Based on such counsel's review of Applicable Law, but without any investigation concerning any other laws, rules or regulations, no consent, approval, authorization or order of, or filing, registration or qualification with, any Governmental Authority, which has not been obtained, taken or made (other than as required by any state securities laws, as to which we express no opinion) is required under any Applicable Law for the performance by the Company of its obligations under this Agreement. For purposes of this opinion, the term "Governmental Authority" means any executive, legislative, judicial, administrative or regulatory body of the State of New York, the State of California or the United States of America.
5. To such counsel's knowledge (without making any docket search or similar investigation) and other than as set forth in the Prospectus, there are no legal proceedings pending or threatened against the Company or the Subsidiaries that could reasonably be expected to have a material adverse effect on the Company and the Subsidiaries, taken as a whole, or could reasonably be expected to materially impair the Company's ability to perform its obligations under this Agreement. To such counsel's knowledge, there are no legal or governmental actions, suits or proceedings pending or threatened which are required to be disclosed in the Registration Statement, other than those disclosed therein.

Such counsel shall also state that he has participated in the preparation of the Registration Statement and the Prospectus and is familiar with the documents incorporated by reference therein and, although he has not undertaken to investigate or verify independently, and does not assume responsibility for, the accuracy, completeness or fairness of the statements contained in either of them, based upon such participation (and relying as to certain factual matters in his evaluation of materiality to the extent they deemed reasonable on officers, employees and other representatives of the Company), no facts have come to his attention that led him to believe that (a) the Registration Statement or any amendment (except for the financial statements, financial statement schedules and other financial data included or incorporated by reference in or omitted from those documents, as to which such counsel may express no such belief), at the time it became effective, contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading or (b) the Prospectus or any amendment or supplement (except for the financial statements, financial statement schedules and other financial data included or incorporated by reference in or omitted from those documents, as to which such counsel may express no such belief), at the time the Prospectus was issued or on the date of such counsel's opinion, included or includes an untrue statement of a material fact or omitted or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading. Such counsel does not know of any amendment to the Registration Statement required to be filed or of any contracts or other documents of a character required to be filed as an exhibit to the Registration Statement or required to be incorporated by reference into the Prospectus or required to be described in the Registration Statement or the Prospectus which are not filed or incorporated by reference or described as required.

5. On the date of the Prospectus at a time prior to the execution of this Agreement, at 9:30 a.m., New York City time, on the effective date of any post-effective amendment to the Registration Statement filed subsequent to the date of this Agreement and also at the Time of Delivery, Deloitte & Touche LLP shall have furnished to you a letter or letters, dated the respective dates of delivery thereof, in form and substance satisfactory to you, to the effect set forth in Annex I hereto (the executed copy of the letter delivered prior to the execution of this Agreement is attached as Annex I(a) hereto and a draft of the form of letter to be delivered on the effective date of any post-effective amendment to the Registration Statement and as of the Time of Delivery is attached as Annex I(b) hereto);
6. (i) Neither the Company nor any of its subsidiaries shall have sustained since the date of the latest audited financial statements included in the Prospectus any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, otherwise than as set forth or contemplated in the Prospectus, and (ii) since the respective dates as of which information is given in the Prospectus there shall not have been any material change in the capital stock (other than changes occurring in the ordinary course of business and changes resulting from transactions relating to employee benefit plans or dividend reinvestment, stock option, stock award, retirement and stock purchase plans or repurchases of capital stock by the Company, including repurchases associated with the ASB or long-term debt of the Company or any of its subsidiaries or any change, or any development which would reasonably be expected to result in a change, in or affecting the general affairs, management, financial position, shareholders' equity or results of operations of the Company and its subsidiaries, otherwise than as set forth or contemplated in the Prospectus, the effect of which, in any such case described in clause (i) or (ii), is in the judgment of GS&Co. so material and adverse as to make it impracticable or inadvisable to proceed with the public offering or the delivery of the Shares being delivered at the Time of Delivery on the terms and in the manner contemplated in the Prospectus;
8. On or after the date hereof (i) no downgrading shall have occurred in the rating accorded the Company's debt securities by any "nationally recognized statistical rating organization", as that term is defined by the Commission for purposes of Rule 436(g)(2) under the Securities Act, and (ii) no such organization shall have publicly announced that it has under surveillance or review, with possible negative implications, its rating of any of the Company's debt securities;
9. On or after the date hereof there shall not have occurred any of the following: (i) a suspension or material limitation in trading in securities generally on the New York Stock Exchange; (ii) a suspension or material limitation in trading in the Company's securities on the New York Stock Exchange; (iii) a general moratorium on commercial banking activities declared by either Federal or New York State authorities or a material disruption in commercial banking or securities settlement or clearance services in the United States; (iv) the outbreak or escalation of hostilities involving the United States or the declaration by the United States of a national emergency or war or (v) the occurrence of any other calamity or crisis or any change in financial, political or economic conditions in the United States or elsewhere, if the effect of any such event specified in clause (iv) or (v) in the judgment of GS&Co. makes it impracticable or inadvisable to proceed with the public offering or the delivery of the Shares being delivered at the Time of Delivery on the terms and in the manner contemplated in the Prospectus;
10. The Shares to be delivered at the Time of Delivery shall have been duly listed on the New York Stock Exchange;
11. The Company shall have complied with the provisions of Section 4(c) hereof with respect to the furnishing of prospectuses on the New York Business Day next succeeding the date of this Agreement; and
12. The Company shall have furnished or caused to be furnished to GS&Co. at the Time of Delivery certificates of officers of the Company satisfactory to GS&Co. as to the accuracy of the representations and warranties of the Company herein at and as of the Time of Delivery, as to the performance by the Company of all of its obligations hereunder to be performed at or prior to the Time of Delivery, and as to the other matters as GS&Co. may reasonably request, and the Company shall have furnished certificates as to the matters set forth in subsections (a) and (e) of this Section, and as to such other matters as GS&Co. may reasonably request.
7. The Company shall indemnify and hold harmless GS&Co., and any such person who may be deemed to be an "Underwriter" within the meaning of the Securities Act, each person, if any, who controls GS&Co. within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act, and each partner, principal, member, officer, director, employee and agent of GS&Co. from and against any and all losses, claims, damages or liabilities to which GS&Co. may become subject, under the Securities Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in any Preliminary Prospectus, the Registration Statement or the Prospectus, or any amendment or supplement thereto, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be state d therein or necessary to make the statements therein not misleading, and will reimburse GS&Co. for any legal or other expenses reasonably incurred by GS&Co. in connection with investigating or defending any such action or claim as such expenses are incurred; provided, however, that the Company shall not be liable in any such case to the extent that any such loss, claim, damage or liability arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission made in any Preliminary Prospectus, the Registration Statement or the Prospectus or any such amendment or supplement in reliance upon and in conformity with written information furnished to the Company by GS&Co. expressly for use therein.
2. GS&Co. will indemnify and hold harmless the Company against any losses, claims, damages or liabilities to which the Company may become subject, under the Act or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in any Preliminary Prospectus, the Registration Statement, the Prospectus, the Prospectus as amended or supplemented or any other prospectus relating to the Shares, or any amendment or supplement thereto, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, in each case to the extent, but only to the extent, that such untrue statement or alleged untrue statement or omission or alleged omission was made in any Preliminary Prospectus, the Registration Statement, the Prospectus, the Prospectus as amended or supplemented or any other prospectus relating to the Shares, or any such amendment or supplement, in reliance upon and in conformity with written information furnished to the Company by GS&Co. expressly for use therein; and will reimburse the Company for any legal or other expenses reasonably incurred by the Company in connection with investigating or defending any such action or claim as such expenses are incurred.
3. Promptly after receipt by an indemnified party under subsection (a) or (b) above of notice of the commencement of any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party under such subsection, notify the indemnifying party in writing of the commencement thereof; but the omission so to notify the indemnifying party shall not relieve it from any liability which it may have to any indemnified party otherwise than under such subsection. In case any such action shall be brought against any indemnified party and it shall notify the indemnifying party of the commencement thereof, the indemnifying party shall be entitled to participate therein and, to the extent that it shall wish, jointly with any other indemnifying party similarly notified, to assume the defense thereof, with counsel satisfactory to such indemnified party (who shall not, except with the consent of the indemnified party, be counsel to the indemnifying party), and, after notice from t he indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party shall not be liable to such indemnified party under such subsection for any legal expenses of other counsel or any other expenses, in each case subsequently incurred by such indemnified party, in connection with the defense thereof other than reasonable costs of investigation. No indemnifying party shall, without the written consent of the indemnified party, effect the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim in respect of which indemnification or contribution may be sought hereunder (whether or not the indemnified party is an actual or potential party to such action or claim) unless such settlement, compromise or judgment (i) includes an unconditional release of the indemnified party from all liability arising out of such action or claim and (ii) does not include any statement as to or an admission of fault, culpability or a failure to act, by or on behalf of any indemnified party.
4. If the indemnification provided for in this Section 7 is unavailable to or insufficient to hold harmless an indemnified party under subsection (a) or (b) above in respect of any losses, claims, damages or liabilities (or actions in respect thereof) referred to therein, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (or actions in respect thereof) in such proportion as is appropriate to reflect the relative benefits received by the Company on the one hand and GS&Co. on the other from the offering of the Shares to which such loss, claim, damage or liability (or action in respect thereof) relates. If, however, the allocation provided by the immediately preceding sentence is not permitted by applicable law or if the indemnified party failed to give the notice required under subsection (c) above, then each indemnifying party shall contribute to such amount paid or payable by such indemnified party in such proportion as is appropriate to reflect not only such relative benefits but also the relative fault of the Company on the one hand and GS&Co. on the other in connection with the statements or omissions which resulted in such losses, claims, damages or liabilities (or actions in respect thereof), as well as any other relevant equitable considerations. The relative benefits received by the Company on the one hand and GS&Co. on the other shall be deemed to be in the same proportion as the total net proceeds from such offering (before deducting expenses) received by the Company bear to the total commissions received by GS&Co. The relative fault shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Company on the one hand or GS&Co. on the other and the parties' relative intent, knowledge, access to information and o pportunity to correct or prevent such statement or omission. The

Company and GS&Co. agree that it would not be just and equitable if contributions pursuant to this subsection (d) were determined by pro rata allocation (even if GS&Co. were treated as one entity for such purpose) or by any other method of allocation which does not take account of the equitable considerations referred to above in this subsection (d). The amount paid or payable by an indemnified party as a result of the losses, claims, damages or liabilities (or actions in respect thereof) referred to above in this subsection (d) shall be deemed to include any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this subsection (d), GS&Co. shall not be required to contribute any amount in excess of the amount by which the total price at which the applicable Shares distributed to the public were offered to the public exceeds the amount of any damages which GS&Co. has ot herwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation.

5. The obligations of, and the indemnification provided by, the Company and GS&Co. under this Section 7 shall be in addition to any liability which the Company and GS&Co. may otherwise have, and, for the avoidance of doubt, shall be in addition to any other indemnification provided by the Company and GS&Co. or any other party, including the indemnification provided under the ASB, and shall extend, upon the same terms and conditions, to each Indemnified Party (as defined in the ASB); provided, however, that only this Section 7 and not clause (ii) of paragraph 8 of Annex B to the ASB shall apply in respect of the Shares.
8. The respective indemnities, agreements, representations, warranties and other statements of the Company and GS&Co., as set forth in this Agreement or made by or on behalf of them, respectively, pursuant to this Agreement, shall remain in full force and effect, regardless of any investigation (or any statement as to the results thereof) made by or on behalf of GS&Co. or any controlling person of GS&Co. or the Company or any officer or director or controlling person of the Company and shall survive delivery of and payment for the Shares.
9. All statements, requests, notices and agreements hereunder shall be in writing, and if to GS&Co. shall be delivered or sent by mail, telex or facsimile transmission to Goldman, Sachs & Co., 85 Broad Street, New York, New York 10004, Attention: [Registration Department] and if to the Company shall be delivered or sent by mail to the address of the Company set forth in the Registration Statement, Attention: General Counsel. Any such statements, requests, notices or agreements shall take effect upon receipt thereof.
10. This Agreement shall be binding upon, and inure solely to the benefit of, GS&Co. and the Company and, to the extent provided in Sections 7 and 8 hereof, each Indemnified Party (as defined in the ASB), and their respective heirs, executors, administrators, successors and assigns, and no other person shall acquire or have any right under or by virtue of this Agreement. No purchaser of any of the Shares from GS&Co. shall be deemed a successor or assign by reason merely of such purchase.
11. Time shall be of the essence of this Agreement. As used herein, the term "business day" shall mean any day when the Commission's office in Washington, D.C. is open for business.
12. This Agreement shall be governed by and construed in accordance with the laws of the State of New York.
13. Each of the Company and GS&Co. hereby irrevocably waives, to the fullest extent permitted by applicable law, any and all right to trial by jury in any legal proceeding arising out of or relating to this Agreement or the transactions contemplated hereby.
15. This Agreement may be executed by any one or more of the parties hereto in any number of counterparts, each of which shall be deemed to be an original, but all such counterparts shall together constitute one and the same instrument.
16. The Company is authorized, subject to applicable law, to disclose any and all aspects of this potential transaction that are necessary to support any U.S. federal income tax benefits expected to be claimed with respect to such transaction, and all materials of any kind (including tax opinions and other tax analyses) related to those benefits, without GS&Co. imposing any limitation of any kind. However, any information relating to the tax treatment and tax structure shall remain confidential (and the foregoing sentence shall not apply) to the extent necessary to enable any person to comply with securities laws. For this purpose, "tax structure" is limited to any facts that may be relevant to that treatment.

If the foregoing is in accordance with your understanding, please sign and return to us five counterparts hereof, and upon the acceptance hereof by GS&Co., this letter and such acceptance hereof shall constitute a binding agreement between GS&Co. and the Company.

Very truly yours,

PG&E Corporation

By:

Name:

Title:

Accepted as of the date hereof:

Goldman, Sachs & Co.

By:

(Goldman, Sachs & Co.)

SCHEDULE I

Name State of Incorporation

Pacific Gas and Electric Company California

ANNEX I

Pursuant to Section 6(e) of the Agreement, the accountants shall furnish letters to GS&Co. to the effect that:

(i) They are an independent registered public accounting firm with respect to the Company and its subsidiaries within the meaning of the Securities Act and the applicable published rules and regulations thereunder adopted by the Commission and the PCAOB;

(ii) In their opinion, the financial statements and any supplementary financial information and schedules (and, if applicable, financial forecasts and/or pro forma financial information) audited by them and included or incorporated by reference in the Prospectus or the Registration Statement comply as to form in all material respects with the applicable accounting requirements of the Securities Act or the Exchange Act, as applicable, and the related published rules and regulations thereunder; and, if applicable, they have made a review in accordance with standards established by the PCAOB of the unaudited consolidated interim financial statements, selected financial data, pro forma financial information, financial forecasts and/or condensed financial statements derived from audited financial statements of the Company for the periods specified in such letter, as indicated in their reports thereon, copies of which have been separately furnished to GS&Co.;

(iii) They have made a review in accordance with standards established by the PCAOB of the unaudited condensed consolidated statements of income, consolidated balance sheets and consolidated statements of cash flows included in the Prospectus and/or included in the Company's quarterly report on Form 10-Q incorporated by reference into the Prospectus as indicated in their reports thereon copies of which have been separately furnished to GS&Co.; and on the basis of specified procedures including inquiries of officials of the Company who have responsibility for financial and accounting matters regarding whether the unaudited condensed consolidated financial statements referred to in paragraph (vi)(A)(i) below comply as to form in all material respects with the applicable accounting requirements of the Securities Act and the Exchange Act and the related published rules and regulations, nothing came to their attention that caused them to believe that the unaudited condensed consolidated financial statem ents do not comply as to form in all material respects with the applicable accounting requirements of the Securities Act and the Exchange Act and the related published rules and regulations;

(iv) The unaudited selected financial information with respect to the consolidated results of operations and financial position of the Company for the five most recent fiscal years included in the Prospectus and included or incorporated by reference in Item 6 of the Company's Annual Report on Form 10-K for the most recent fiscal year agrees with the corresponding amounts (after restatements where applicable) in the audited consolidated financial statements for such five fiscal years which were included or incorporated by reference in the Company's Annual Reports on Form 10-K for such fiscal years;

(v) On the basis of limited procedures, not constituting an examination in accordance with the standards of the PCAOB, consisting of a reading of the unaudited financial statements and other information referred to below, a reading of the latest available interim financial statements of the Company and its subsidiaries, inspection of the minute books of the Company and its subsidiaries since the date of the latest audited financial statements included in the Prospectus, inquiries of officials of the Company and its subsidiaries responsible for financial and accounting matters and such other inquiries and procedures as may be specified in such letter, nothing came to their attention that caused them to believe that:

(A) (i) the unaudited consolidated statements of income, consolidated balance sheets and consolidated statements of cash flows included in the Prospectus and/or included or incorporated by reference in the Company's Quarterly Reports on Form 10-Q incorporated by reference in the Prospectus do not comply as to form in all material respects with the applicable accounting requirements of the Securities Act and the Exchange Act and the related published rules and regulations, or (ii) any material modifications should be made to the unaudited condensed consolidated statements of income, consolidated balance sheets and consolidated statements of cash flows included in the Prospectus or included in the Company's Quarterly Reports on Form 10-Q incorporated by reference in the Prospectus for them to be in conformity with generally accepted accounting principles;

(B) any other unaudited income statement data and balance sheet items included or incorporated by reference in the Prospectus do not agree with the corresponding items in the unaudited consolidated financial statements from which such data and items were derived, and any such unaudited data and items were not determined on a basis substantially consistent with the basis for the corresponding amounts in the audited consolidated financial statements included or incorporated by reference in the Company's Annual Report on Form 10-K for the most recent fiscal year incorporated by reference in the Prospectus;

(C) the unaudited financial statements which were not included in the Prospectus but from which were derived any unaudited condensed financial statements referred to in clause (A) and any unaudited income statement data and balance sheet items included or incorporated by reference in the Prospectus and referred to in clause (B) were not determined on a basis substantially consistent with the basis for the audited consolidated financial statements included or incorporated by reference in the Company's Annual Report on Form 10-K for the most recent fiscal year incorporated by reference in the Prospectus;

(D) any unaudited pro forma consolidated condensed financial statements included or incorporated by reference in the Prospectus do not comply as to form in all material respects with the applicable accounting requirements of the Securities Act and the Exchange Act and the published rules and regulations thereunder or the pro forma adjustments have not been properly applied to the historical amounts in the compilation of those statements;

(E) as of a specified date not more than five days prior to the date of such letter, there have been any changes in the consolidated capital stock (other than issuances of capital stock upon exercise of options and stock appreciation rights, upon earn-outs of performance shares and upon conversions of convertible securities, in each case which were outstanding on the date of the latest financial statements included or incorporated by reference in the Prospectus) or any increase in the consolidated long-term debt of the Company and its subsidiaries, or any decreases in consolidated net current assets or shareholders' equity or other items specified by GS&Co., or any increases in any items specified by GS&Co., in each case as compared with amounts shown in the latest balance sheet included or incorporated by reference in the Prospectus, except in each case for changes, increases or decreases which the Prospectus discloses have occurred or may occur or which are described in such letter; and

(F) for the period from the date of the latest financial statements included or incorporated by reference in the Prospectus to the specified date referred to in clause (E) there were any decreases in consolidated net revenues or operating profit or the total or per share amounts of consolidated net income or other items specified by GS&Co., or any increases in any items specified by GS&Co., in each case as compared with the comparable period of the preceding year and with any other period of corresponding length specified by GS&Co., except in each case for decreases or increases which the Prospectus discloses have occurred or may occur or which are described in such letter; and

(vi) In addition to the examination referred to in their report(s) included or incorporated by reference in the Prospectus and the limited procedures, inspection of minute books, inquiries and other procedures referred to in paragraphs (iii) and (vi) above, they have carried out certain specified procedures, not constituting an examination in accordance with generally accepted auditing standards, with respect to certain amounts, percentages and financial information specified by GS&Co., which are derived from the general accounting records of the Company and its subsidiaries, which appear in the Prospectus (excluding documents incorporated by reference) or in Part II of, or in exhibits and schedules to, the Registration Statement specified by GS&Co. or in documents incorporated by reference in the Prospectus specified by GS&Co., and have compared certain of such amounts, percentages and financial information with the accounting records of the Company and its subsidiaries and have found them to be in agreement.

ANNEX II(a)

FORM OF OPINION

OF Cadwalader, Wickersham & Taft LLP

ANNEX II(b)

FORM OF OPINION

OF Orrick, Herrington & Sutcliffe LLP

ANNEX II(c)

FORM OF OPINION

OF BRUCE R. WORTHINGTON, ESQ.

EX-11

EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE

	Three Months Ended
	March 31,
(in millions, except share amounts)		2006		2005
Net income	$	214	$	218
Less: distributed earnings to common shareholders		114		111
Undistributed earnings		100		107
Common shareholders earnings
Basic
Distributed earnings to common shareholders	$	114	$	111
Undistributed earnings allocated to common shareholders		95		102
Total common shareholders earnings, basic	$	209	$	213
Diluted
Distributed earnings to common shareholders	$	114	$	111
Undistributed earnings allocated to common shareholders		95		102
Total common shareholders earnings, diluted	$	209	$	213
Weighted average common shares outstanding, basic		344		388
9.50% Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, basic		363		407
Weighted average common shares outstanding, basic		344		388
Employee share-based compensation and accelerated share repurchase program (1)		5		4
Weighted average common shares outstanding, diluted		349		392
9.50% Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, diluted		368		411
Net earnings per common share, basic
Distributed earnings, basic	$	0.33	$	0.29
Undistributed earnings, basic		0.28		0.26
Total	$	0.61	$	0.55
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.33	$	0.28
Undistributed earnings, diluted		0.27		0.26
Total	$	0.60	$	0.54
(1) Includes approximately 1.3 million PG&E Corporation common shares potentially issuable in settlement of an approximately $49.6 million obligation under an ASR at March 31, 2006 and approximately 1.5 million shares in relation to the settlement of the share forward agreement of the ASR on March 28, 2006. The remaining approximately 3 million shares at March 31, 2006 are deemed to be outstanding per SFAS No. 128 for the purpose of calculating EPS.

EX-12.1

EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Three Months Ended March 31,	Year Ended December 31,
	2006	2005	2004	2003	2002	2001
Earnings:
Net income	$217	$934	$3,982	$923	$1,819	$1,015
Adjustments for minority interest in losses of less than 100% owned affiliates and the Company's equity in undistributed income (losses) of less than 50% owned affiliates	-	-	-	- -	- -	- -
Income taxes provision	132	574	2,561	528	1,178	596
Net fixed charges	163	589	671	964	1,029	1,019
Total Earnings	$512	$2,097	$7,214	$2,415	$4,026	$2,630
Fixed Charges:
Interest on short-term borrowings and long-term debt, net	$158	$573	$682	$947	$996	$981
Interest on capital leases	-	1	1	1	2	2
AFUDC debt	5	15	(12)	16	21	12
Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust	-	-	-	- -	10	24
Total Fixed Charges	$163	$589	$671	$964	$1,029	$1,019
Ratios of Earnings to Fixed Charges	3.14	3.56	10.75	2.51	3.91	2.58

Note:

For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements and preferred security distribution requirements of majority-owned trust.

EX-12.2

EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Three Months Ended March 31,	Year Ended December 31,
Earnings:	2006	2005	2004	2003	2002	2001
Net income	$217	$934	$3,982	$923	$1,819	$1,015
Adjustments for minority interest in losses of   less than 100% owned affiliates and the   Company's equity in undistributed income   (losses) of less than 50% owned affiliates	-	-	-	-	-	-
Income taxes provision	132	574	2,561	528	1,178	596
Net fixed charges	163	589	671	964	1,029	1,019
Total Earnings	$512	$2,097	$7,214	$2,415	$4,026	$2,630
Fixed Charges:
Interest on short-term borrowings and long   term debt, net	$158	$573	$682	$947	$996	$981
Interest on capital leases	-	1	1	1	2	2
AFUDC debt	5	15	(12)	16	21	12
Earnings required to cover the preferred stock   dividend and preferred security distribution   requirements of majority owned trust	-	-	-	-	10	24
Total Fixed Charges	163	589	671	964	1,029	1,019
Preferred Stock Dividends:
Tax deductible dividends	3	12	9	9	9	9
Pre-tax earnings required to cover   non-tax deductible preferred stock   dividend requirements	-	13	34	27	28	27
Total Preferred Stock Dividends	3	25	43	36	37	36
Total Combined Fixed Charges   and Preferred Stock Dividends	$166	$614	$714	$1,000	$1,066	$1,055
Ratios of Earnings to Combined Fixed   Charges and Preferred Stock Dividends	3.08	3.42	10.10	2.42	3.78	2.49

Note:

For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements and preferred security distribution requirements of majority-owned trust. "Preferred stock dividends" represent tax deductible dividends and pre-tax earnings that are required to pay the dividends on outstanding preferred securities.

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Peter A. Darbee, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 of PG&E Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
3. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
4. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 3, 2006

/s/ Peter A. Darbee

Peter A. Darbee
Chairman, Chief Executive Officer and President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Christopher P. Johns, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 of PG&E Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
3. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
4. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

1. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 3, 2006

/s/ Christopher P. Johns

Christopher P. Johns
Senior Vice President, Chief Financial Officer and Treasurer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Thomas B. King, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 of Pacific Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
3. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
4. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 3, 2006

/s/ Thomas B. King
Thomas B. King
President and Chief Executive Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Christopher P. Johns, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the year ended March 31, 2006 of Pacific Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
3. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
4. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

1. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 3, 2006

/s/ Christopher P. Johns
Christopher P. Johns
Senior Vice President, Chief Financial Officer and
Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, I, Peter A. Darbee, Chairman, Chief Executive Officer and President of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/s/ Peter A. Darbee

PETER A. DARBEE

Chairman, Chief Executive Officer and President

May 3, 2006

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, I, Christopher P. Johns, Senior Vice President, Chief Financial Officer and Treasurer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2006, fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/s/ Christopher P. Johns

CHRISTOPHER P. JOHNS

Senior Vice President,

Chief Financial Officer and Treasurer

May 3, 2006

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, I, Thomas B. King, President and Chief Executive Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ Thomas B. King

THOMAS B. KING

President and Chief Executive Officer

May 3, 2006

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, I, Christopher P. Johns, Senior Vice President, Chief Financial Officer and Treasurer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2006, fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ Christopher P. Johns

CHRISTOPHER P. JOHNS

Senior Vice President, Chief Financial Officer

and Treasurer

May 3, 2006