UNITED STATES SECURITIES AND EXCHANGE COMMISSION

10-Q 1 pge10q_q1.htm CORP Q1 2006 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION





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 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.")

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 interim 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 those 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 recognition 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 Notes 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 Liabilities - 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 terminated share forward agreement were treated as outstanding for purposes of calculating diluted EPS for the quarter ended March 31, 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 31, 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 date and a payout percentage, ranging from 0% to 200%, as measured by PG&E Corporation's TSR relative to its comparator 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 agreed 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 Utility 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 in 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 Agreement, 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 these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately $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 included 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 federal 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 plaintiffs' 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.

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 shareholders.

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 million 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, cannot 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 targets 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 schedules 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 the 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 required 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 recorded 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 transmission 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 Annual 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. This 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 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 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 distribution 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, indemnity 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 attributable 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 previous 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 compared 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 financial 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 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.

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 million 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.

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.

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 Pipeline 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 approximately $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 and $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 consolidated 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

^{(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

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.

	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

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

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

	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