q107_form10q.htm


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, 2007 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 each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 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, an 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 May 8, 2007:

PG&E Corporation				351,498,908 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, 2007

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		7
		Condensed Consolidated Balance Sheets		8
		Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	11
	NOTE 2:		New and Significant Accounting Policies	11
	NOTE 3:		Regulatory Assets, Liabilities and Balancing Accounts	14
	NOTE 4:		Debt	17
	NOTE 5:		Shareholders' Equity	19
	NOTE 6:		Earnings Per Common Share	20
	NOTE 7:		Derivatives and Hedging Activities	21
	NOTE 8:		Share-Based Compensation	21
	NOTE 9:		Related Party Agreements and Transactions	23
	NOTE 10:		The Utility's Emergence from Chapter 11	24
	NOTE 11:		Commitments and Contingencies	24

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			32
	Forward-Looking Statements			33
	Results of Operations			35
	Liquidity and Financial Resources			40
	Contractual Commitments			43
	Capital Expenditures			43
	Off-Balance Sheet Arrangements			44
	Contingencies			45
	Regulatory Matters			45
	Risk Management Activities			48
	Critical Accounting Policies			49
	New Accounting Policies			50
	Accounting Pronouncements Issued But Not Yet Adopted			50
	Environmental and Legal Matters			50

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			50
ITEM 4.	CONTROLS AND PROCEDURES			50

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			52
ITEM 1A.	RISK FACTORS			52
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			52
ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			52
ITEM 5.	OTHER INFORMATION			54
ITEM 6.	EXHIBITS			54

SIGNATURES				56

PART I. FINANCIAL INFORMATION

ITEM 1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
(in millions, except per share amounts)	Three Months Ended
	March 31,
	2007			2006
Operating Revenues
Electric	$	2,175		$	1,863
Natural gas		1,181			1,285
Total operating revenues		3,356			3,148
Operating Expenses
Cost of electricity		723			530
Cost of natural gas		754			873
Operating and maintenance		920			862
Depreciation, amortization, and decommissioning		430			414
Total operating expenses		2,827			2,679
Operating Income		529			469
Interest income		52			23
Interest expense		(190	)		(154	)
Other income, net		4			-
Income Before Income Taxes		395			338
Income tax provision		139			124
Net Income	$	256		$	214
Weighted Average Common Shares Outstanding, Basic		349			344
Net Earnings Per Common Share, Basic	$	0.71		$	0.61
Net Earnings Per Common Share, Diluted	$	0.71		$	0.60
Dividends Declared Per Common Share	$	0.36		$	0.33

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	March 31,
	2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	470		$	456
Restricted cash		1,426			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $55 million in 2007 and $50 million in 2006)		2,108			2,343
Regulatory balancing accounts		895			607
Inventories:
Gas stored underground and fuel oil		95			181
Materials and supplies		160			149
Income taxes receivable		50			-
Prepaid expenses and other		427			716
Total current assets		5,631			5,867
Property, Plant, and Equipment
Electric		24,281			24,036
Gas		9,176			9,115
Construction work in progress		1,203			1,047
Other		16			16
Total property, plant, and equipment		34,676			34,214
Accumulated depreciation		(12,531	)		(12,429	)
Net property, plant, and equipment		22,145			21,785
Other Noncurrent Assets
Regulatory assets		4,726			4,902
Nuclear decommissioning funds		1,894			1,876
Other		389			373
Total other noncurrent assets		7,009			7,151
TOTAL ASSETS	$	34,785		$	34,803

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,
	2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	39		$	759
Long-term debt, classified as current		280			281
Rate reduction bonds, classified as current		215			290
Energy recovery bonds, classified as current		341			340
Accounts payable:
Trade creditors		805			1,075
Disputed claims and customer refunds		1,709			1,709
Regulatory balancing accounts		978			1,030
Other		531			420
Interest payable		550			583
Income taxes payable		-			102
Deferred income taxes		188			148
Other		1,320			1,513
Total current liabilities		6,956			8,250
Noncurrent Liabilities
Long-term debt		7,393			6,697
Energy recovery bonds		1,852			1,936
Regulatory liabilities		3,590			3,392
Asset retirement obligations		1,484			1,466
Income taxes payable		228			-
Deferred income taxes		2,945			2,840
Deferred tax credits		104			106
Other		2,004			2,053
Total noncurrent liabilities		19,600			18,490
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 374,502,682 common and 1,274,842 restricted shares in 2007 and 372,803,521 common and 1,377,538 restricted shares in 2006		5,926			5,877
Common stock held by subsidiary, at cost, 24,665,500 shares		(718	)		(718	)
Reinvested earnings		2,783			2,671
Accumulated other comprehensive loss		(14	)		(19	)
Total common shareholders' equity		7,977			7,811
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,785		$	34,803

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended
(in millions)	March 31,
	2007			2006
Cash Flows From Operating Activities
Net income	$	256		$	214
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction		454			402
Deferred income taxes and tax credits, net		142			(30	)
Other deferred charges and noncurrent liabilities		68			58
Net effect of changes in operating assets and liabilities:
Accounts receivable		235			303
Inventories		75			146
Accounts payable		(86	)		(124	)
Accrued taxes/income taxes receivable		58			250
Regulatory balancing accounts, net		(275	)		(55	)
Other current assets		173			(80	)
Other current liabilities		(117	)		16
Other		(7	)		29
Net cash provided by operating activities		976			1,129
Cash Flows From Investing Activities
Capital expenditures		(673	)		(576	)
Net proceeds from sale of assets		4			3
Decrease (increase) in restricted cash		(11	)		52
Proceeds from nuclear decommissioning trust sales		181			435
Purchases of nuclear decommissioning trust investments		(199	)		(477	)
Other		-			11
Net cash used in investing activities		(698	)		(552	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility		-			50
Repayments under accounts receivable facility and working capital facility		(300	)		(310	)
Net repayment of commercial paper, net of $4 million discount on borrowings		(425	)		-
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(75	)		(74	)
Energy recovery bonds matured		(83	)		(56	)
Common stock issued		26			66
Common stock repurchased		-			(58	)
Common stock dividends paid		(123	)		(114	)
Other		26			109
Net cash used in financing activities		(264	)		(387	)
Net change in cash and cash equivalents		14			190
Cash and cash equivalents at January 1		456			713
Cash and cash equivalents at March 31	$	470		$	903
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	128		$	167
Income taxes paid (refunded), net		57			(103	)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	126		$	114

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,
	2007			2006
Operating Revenues
Electric	$	2,175		$	1,863
Natural gas		1,181			1,285
Total operating revenues		3,356			3,148
Operating Expenses
Cost of electricity		723			530
Cost of natural gas		754			873
Operating and maintenance		919			862
Depreciation, amortization, and decommissioning		429			413
Total operating expenses		2,825			2,678
Operating Income		531			470
Interest income		48			19
Interest expense		(182	)		(146	)
Other income, net		9			6
Income Before Income Taxes		406			349
Income tax provision		145			132
Net Income		261			217
Preferred stock dividend requirement		3			3
Income Available for Common Stock	$	258		$	214

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	March 31,
	2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	37		$	70
Restricted cash		1,426			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $55 million in 2007 and $50 million in 2006)		2,108			2,343
Related parties		4			6
Regulatory balancing accounts		895			607
Inventories:
Gas stored underground and fuel oil		95			181
Materials and supplies		160			149
Income taxes receivable		25			20
Prepaid expenses and other		422			714
Total current assets		5,172			5,505
Property, Plant and Equipment
Electric		24,281			24,036
Gas		9,176			9,115
Construction work in progress		1,203			1,047
Total property, plant and equipment		34,660			34,198
Accumulated depreciation		(12,516	)		(12,415	)
Net property, plant and equipment		22,144			21,783
Other Noncurrent Assets
Regulatory assets		4,726			4,902
Nuclear decommissioning funds		1,894			1,876
Related parties receivable		26			25
Other		293			280
Total other noncurrent assets		6,939			7,083
TOTAL ASSETS	$	34,255		$	34,371

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,
	2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	39		$	759
Long-term debt, classified as current		-			1
Rate reduction bonds, classified as current		215			290
Energy recovery bonds, classified as current		341			340
Accounts payable:
Trade creditors		805			1,075
Disputed claims and customer refunds		1,709			1,709
Related parties		27			40
Regulatory balancing accounts		978			1,030
Other		513			402
Interest payable		543			570
Deferred income taxes		193			118
Other		1,153			1,346
Total current liabilities		6,516			7,680
Noncurrent Liabilities
Long-term debt		7,393			6,697
Energy recovery bonds		1,852			1,936
Regulatory liabilities		3,590			3,392
Asset retirement obligations		1,484			1,466
Income taxes payable		99			-
Deferred income taxes		3,010			2,972
Deferred tax credits		104			106
Other		1,882			1,922
Total noncurrent liabilities		19,414			18,491
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		1,832			1,822
Reinvested earnings		5,323			5,213
Accumulated other comprehensive loss		(11	)		(16	)
Total shareholders' equity		8,325			8,200
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,255		$	34,371

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended
(in millions)	March 31,
	2007			2006
Cash Flows From Operating Activities
Net income	$	261		$	217
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction		454			401
Deferred income taxes and tax credits, net		143			(27	)
Other deferred charges and noncurrent liabilities		68			55
Net effect of changes in operating assets and liabilities:
Accounts receivable		237			303
Inventories		75			146
Accounts payable		(99	)		(124	)
Accrued taxes/income taxes receivable		41			202
Regulatory balancing accounts, net		(275	)		(55	)
Other current assets		174			(80	)
Other current liabilities		(98	)		41
Other		(7	)		15
Net cash provided by operating activities		974			1,094
Cash Flows From Investing Activities
Capital expenditures		(673	)		(576	)
Net proceeds from sale of assets		4			3
Decrease (increase) in restricted cash		(11	)		52
Proceeds from nuclear decommissioning trust sales		181			435
Purchases of nuclear decommissioning trust investments		(199	)		(477	)
Other		-			11
Net cash used in investing activities		(698	)		(552	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility		-			50
Repayments under accounts receivable facility and working capital facility		(300	)		(310	)
Net repayment of commercial paper, net of $4 million discount on borrowings		(425	)		-
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(75	)		(74	)
Energy recovery bonds matured		(83	)		(56	)
Common stock dividends paid		(127	)		(115	)
Preferred stock dividends paid		(3	)		(3	)
Other		14			107
Net cash used in financing activities		(309	)		(401	)
Net change in cash and cash equivalents		(33	)		141
Cash and cash equivalents at January 1		70			463
Cash and cash equivalents at March 31	$	37		$	604
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	115		$	154
Income taxes paid (refunded), net		(30	)		(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. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (the “Utility”), a public utility operating in northern and central California. The Utility engages 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 (“CPUC”) and the Federal Energy Regulatory Commission (“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 variable interest entities for which it is subject to a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying interim unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“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 (“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, 2006 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, 2006. (PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2006, together with the information incorporated by reference into such report, is referred to in this Quarterly Report on Form 10-Q as the “2006 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 2006 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 and other employee benefit plan liabilities, severance costs, mark-to-market accounting, income tax related liabilities, and litigation. The Utility also reviews for impairment of long-lived assets and certain identifiable intangibles to be held and used in operations whenever events or changes in circumstances indicate that the carrying amount of these 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.

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 2006 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

Accounting for Uncertainty in Income Taxes

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (“FIN 48”). FIN 48 is effective prospectively for fiscal years beginning after December 15, 2006. FIN 48 clarifies the accounting for uncertainty in income taxes. FIN 48 prescribes a two-step process in the recognition and measurement of a tax position taken or expected to be taken in a tax return. The first step is to determine if it is more-likely-than-not that a tax position will be sustained upon examination by taxing authorities. If this threshold is met, the second step is to measure the tax position on the balance sheet by using the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The difference between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to FIN 48 represents an unrecognized tax benefit. An unrecognized tax benefit is a liability that represents a potential future obligation to the taxing authority.

On January 1, 2007, PG&E Corporation and the Utility adopted FIN 48. The effects of adopting FIN 48 are as follows:

	PG&E Corporation		Utility
(in millions)
At January 1, 2007
Cumulative effect of adoption – decrease to Beginning Reinvested Earnings	$	18	$	21
Unrecognized tax benefits		212		90
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate		107		61
Interest expense accrued on unrecognized tax benefits (net of federal and state tax benefit) through January 1, 2007		29		12

Interest expense and penalties, if any, related to unrecognized tax benefits are classified as Income Tax Expense in the Condensed Consolidated Statements of Income.

	PG&E Corporation		Utility
(in millions)
For The Three Months Ended March 31, 2007
Interest expense accrued on unrecognized tax benefits (net of federal and state tax benefit)	$	3	$	1

PG&E Corporation and the Utility do not anticipate that there will be any material net changes to unrecognized tax benefits within the next twelve months. For a description of tax years that remain subject to examination, see “Taxation Matters” in Note 11 below.

Comprehensive Income

Comprehensive income reports a measure of changes in equity of PG&E Corporation and the Utility that result from transactions and other economic events, other than transactions with shareholders. For the three months ended March 31, 2007, PG&E Corporation's and the Utility's comprehensive income changes consisted of recognition of components of net periodic benefit costs. 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
	2007		2006		2007		2006
Three months ended March 31
Net income available for common stock	$	256	$	214	$	258	$	214
Recognition of components of net periodic benefit costs (net of income tax of $3 million in 2007)		5		-		5		-
Comprehensive income	$	261	$	214	$	263	$	214

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)	Minimum Pension Liability Adjustment			Adoption of SFAS No. 158			Recognition of Components of Net Periodic Benefit Costs		Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2005	$	(8	)	$	-		$	-	$	(8	)
Balance at March 31, 2006		(8	)		-			-		(8	)
Balance at December 31, 2006		-			(19	)		-		(19	)
Period change in:
Recognition of components of net periodic benefit costs		-			-			5		5
Balance at March 31, 2007	$	-		$	(19	)	$	5	$	(14	)

There was no material difference between PG&E Corporation’s and the Utility’s recognition of components of net periodic benefit costs for the three months ended March 31, 2007.

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 months ended March 31, 2007 and 2006 are as follows:

(in millions)	Pension Benefits Three Months Ended March 31,						Other Benefits Three Months Ended March 31,
	2007			2006			2007			2006

Service cost for benefits earned	$	59		$	59		$	7		$	8
Interest cost		135			130			20			19
Expected return on plan assets		(177	)		(157	)		(24	)		(23	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		12			14			4			4
Amortization of unrecognized (gain) loss		-			8			(3	)		-
Net periodic benefit cost	$	29		$	54		$	10		$	14

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

Under Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“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. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery is based on the lesser of the amounts collected in rates or the annual contribution on a tax-deductible basis to the appropriate trusts.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS No. 157”). SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 also establishes a framework for measuring fair value and provides for expanded disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 157.

Fair Value Option

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” (“SFAS No. 159”). SFAS No. 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 159.

Amendment of FASB Interpretation No. 39

In April 2007, the FASB issued FASB Staff Position on Interpretation 39, "Amendment of FASB Interpretation No. 39," ("FIN 39-1"). Under FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for a cash collateral paid or a cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. PG&E Corporation and the Utility are currently evaluating the impact of FIN 39-1.

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.

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 inclusion of costs in authorized customer rates. If costs that a regulated enterprise expects to incur in the future are being recovered through rates, SFAS No. 71 requires that the regulated enterprise record those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future must 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 or other reasons, the related regulatory assets and liabilities are written off.

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance At
	March 31,		December 31,
	2007		2006
(in millions)
Energy recovery bond regulatory asset	$	2,096	$	2,170
Utility retained generation regulatory assets		1,000		1,018
Regulatory assets for deferred income tax		632		599
Environmental compliance costs		297		303
Unamortized loss, net of gain, on reacquired debt		286		295
Regulatory assets associated with plan of reorganization		136		147
Post-transition period contract termination costs		118		120
Scheduling coordinator costs		123		136
Other		38		114
Total regulatory assets	$	4,726	$	4,902

The energy recovery bond (“ERB”) regulatory asset represents refinancing of the settlement regulatory asset established under the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to

resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (the “Chapter 11 Settlement Agreement”). During the three months ended March 31, 2007, the Utility recorded amortization of the ERB regulatory asset of approximately $74 million. The Utility expects to fully recover this asset by the end of 2012.

As a result of the Chapter 11 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’s 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. During the three months ended March 31, 2007, the Utility recorded amortization of the Utility’s retained generation regulatory assets of approximately $18 million.

The regulatory assets for deferred income tax represent deferred income tax benefits 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 certain tax 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 to regulatory assets over periods ranging from 1 to 40 years.

Environmental compliance costs represent the portion of estimated environmental remediation liabilities that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over periods ranging from 1 to 30 years.

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.

Regulatory assets associated with the Utility’s plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code include costs incurred in financing the Utility’s reorganization under Chapter 11 and costs to oversee the environmental enhancement projects 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 5 to 30 years.

Post-transition period contract termination costs represent amounts that 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.

The regulatory asset related to scheduling coordinator (“SC”) costs represent costs that the Utility incurred beginning in 1998 in its capacity as a SC for its then existing wholesale transmission customers. The Utility expects to fully recover the SC costs by 2009.

Finally, as of March 31, 2007, “Other” is primarily related to timing differences between the recognition of asset retirement obligations and the amounts recognized for ratemaking purposes in accordance with GAAP under SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations – An Interpretation of SFAS No. 143” (“FIN 47”), as applied to rate-regulated entities.

In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the Utility earns a return only on the Utility’s retained generation regulatory assets, unamortized loss, net of gain on reacquired debt, and regulatory assets associated with the plan of reorganization.

Current Regulatory Assets

As of March 31, 2007 and December 31, 2006, the Utility had current regulatory assets of approximately $205 million and $434 million, respectively, consisting primarily of the rate reduction bond (“RRB”) regulatory asset and price risk management regulatory assets. The RRB regulatory asset represents electric industry restructuring costs that the Utility expects to fully recover by the end of 2007. During the three months ended March 31, 2007, the Utility recorded amortization of the RRB regulatory asset of approximately $64 million. Price risk management contracts were 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, “Accounting for Derivatives Instruments and Hedging Activities” (“SFAS No. 133”). The costs and proceeds of these derivative instruments are recovered or refunded in regulated rates charged to customers. Current regulatory assets are included in Prepaid Expenses and Other on the Condensed Consolidated Balance Sheets.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance At
	March 31,		December 31,
	2007		2006
(in millions)
Cost of removal obligation	$	2,396	$	2,340
Asset retirement costs		592		608
Public purpose programs		282		169
Price risk management		60		37
Employee benefit plans		45		23
Other		215		215
Total regulatory liabilities	$	3,590	$	3,392

Cost of removal liabilities represent revenues collected for asset removal costs that the Utility expects to incur in the future. Asset retirement costs represent timing differences between the recognition of asset retirement obligations and the amounts recognized for ratemaking purposes in accordance with GAAP under SFAS No. 143 and FIN 47 as applied to rate-regulated entities.

Public purpose program liabilities represent revenues designated for public purpose program costs that are expected to be incurred in the future.

Price risk management liabilities represent contracts entered into by the Utility to procure electricity and natural gas that are accounted for as derivative instruments under SFAS No. 133. Additionally, the Utility hedges its natural gas in the electric and natural gas portfolios on behalf of its customers, in order to reduce commodity price risk. The costs and proceeds of these derivatives are recovered in regulated rates charged to customers.

Employee benefit plan expenses represent the cumulative differences between expenses recognized for financial accounting purposes and expenses recognized for ratemaking purposes. These balances will be charged against expense to the extent that future financial accounting expenses exceed amounts recoverable for regulatory purposes.

Finally, as of March 31, 2007, “Other” regulatory liabilities are primarily related to amounts received from insurance companies to pay for hazardous substance remediation costs and future customer benefits associated with the Gateway Generating Station (“Gateway”). The liability for hazardous substance insurance recoveries is refunded to ratepayers until they are fully reimbursed for total covered hazardous substance costs they have paid to date. Gateway was acquired as part of a settlement with Mirant Corporation and the associated liability will be amortized over 30 years beginning March 2009.

Current Regulatory Liabilities

As of March 31, 2007 and December 31, 2006, the Utility had current regulatory liabilities of approximately $337 million and $309 million, respectively, consisting primarily of the current portion of electric transmission wheeling revenue refunds and the RRB regulatory liability. Electric transmission wheeling revenue refunds represent revenue that will be refunded to retail transmission owner tariff customers. The RRB regulatory liability represents over-collections associated with the RRB financing that the Utility will return to customers in the future. Current regulatory liabilities are included in Current Liabilities -Other on the Condensed Consolidated Balance Sheets.

Regulatory Balancing Accounts

The Utility uses regulatory balancing accounts as a mechanism 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 eliminates the earnings impact from any 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 until they are refunded to or received from

the Utility's customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in Other Noncurrent Assets - Regulatory Assets and Noncurrent Liabilities - Regulatory Liabilities. The CPUC does not allow the Utility to offset regulatory balancing account assets against balancing account liabilities.

Regulatory Balancing Account Assets

	Balance At
	March 31,			December 31,
	2007			2006
(in millions)
Electricity revenue and cost balancing accounts		$	775		$	501
Natural gas revenue and cost balancing accounts			120			106
Total		$	895		$	607

Regulatory Balancing Account Liabilities

	Balance At
	March 31,			December 31,
	2007			2006
(in millions)
Electricity revenue and cost balancing accounts		$	804		$	951
Natural gas revenue and cost balancing accounts			174			79
Total		$	978		$	1,030

During the three months ended March 31, 2007, the under-collection in the Utility's electricity revenue and cost balancing account assets increased from December 31, 2006 mainly because actual revenues were lower than the authorized revenue requirement. This is consistent with seasonal demand changes, and the under-collection is expected to decrease during the summer months when usage rises. During the three months ended March 31, 2007, the decrease in the over-collected position of the Utility's electricity revenue and cost balancing account liabilities from December 31, 2006 was attributable to a reduction in rates as authorized in the 2007 Annual Electric True-Up proceeding in order to reduce the over-collected position of the electric revenue and cost balancing account liabilities.

During the three months ended March 31, 2007, the over-collection in the Utility’s natural gas revenue and cost balancing account liabilities increased from December 31, 2006 mainly due to an increase in consumer demand for natural gas during the winter months.

NOTE 4: DEBT

PG&E Corporation

Senior Credit Facility

PG&E Corporation has a $200 million revolving unsecured credit facility (“senior credit facility”) with a syndicate of lenders that, as amended in February 2007, extends to February 26, 2012. There were no material changes to the terms, fees, interest rates, or covenants related to the senior credit facility as a result of the February 2007 amendment.

The senior credit facility allows both loan drawdowns and issuance of letters of credit, although at March 31, 2007, neither were outstanding.

Convertible Subordinated Notes

At March 31, 2007, PG&E Corporation had outstanding $280 million of 9.5% 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 $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's shares of common stock outstanding. In addition, holders of the Convertible Subordinated Notes are entitled to receive "pass-through dividends" determined by multiplying 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 common stock dividends paid on January 15 and April 15, 2007, PG&E Corporation paid

approximately $6 million and $7 million, respectively, 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). Accordingly, PG&E Corporation has classified the Convertible Subordinated Notes as a current liability (in Current Liabilities - Long-Term Debt) in the accompanying Condensed Consolidated Balance Sheets as of March 31, 2007.

In accordance with SFAS No. 133, the dividend participation rights component of the Convertible Subordinated Notes 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 Income Statement as a non-operating expense or income (included in Other Income, Net). At March 31, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $76 million and $79 million, respectively, of which $24 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $52 million and $56 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabilities - Other).

Utility

In the ordinary course of the Utility’s construction activities, contractors who work on the projects and materialmen who provide materials to them may have certain statutory liens on such projects, which are released as construction progresses and payments are made for their work or materials.

See Note 11 below for a discussion of capital lease obligations related to certain contracts to purchase power from qualifying co-generation facilities (“QFs”).

Senior Notes

On March 13, 2007, the Utility issued $700 million principal amount of 5.80% Senior Notes due March 1, 2037. The Utility received proceeds of $690 million from the offering, net of a $4 million discount and $6 million in issuance costs. Interest is payable semi-annually in arrears on March 1 and September 1. The proceeds from the sale of the Senior Notes were used to repay outstanding commercial paper and for working capital purposes.

The Senior Notes are unsecured and rank equally with the Utility’s other senior unsecured and unsubordinated debt. Under the indenture for the Senior Notes, the Utility has agreed that it will not incur secured debt or engage in sale leaseback transactions (except for (1) debt secured by specified liens, and (2) aggregate other secured debt and sales and leaseback transactions not exceeding 10% of the Utility’s net tangible assets, as defined in the indenture) unless the Utility provides that the Senior Notes will be equally and ratably secured.

At March 31, 2007, there were $5.8 billion of Senior Notes outstanding.

Working Capital Facility

On February 26, 2007, the Utility increased its revolving credit facility (“working capital facility”) with a syndicate of lenders by $650 million to $2.0 billion and extended the facility to February 26, 2012. The working capital facility is used primarily as liquidity support for commercial paper described below. Letters of credit under the working capital facility are used primarily to provide credit enhancements to counterparties for natural gas and energy procurement transactions. There were no material changes to the terms, fees, interest rates, or covenants related to the working capital facility as a result of the February 2007 amendment.

At March 31, 2007, there were no loans outstanding and approximately $177 million of letters of credit outstanding under the working capital facility.

Accounts Receivable Financing

On February 26, 2007, in connection with the amendment of the working capital facility described above, the Utility terminated its $650 million accounts receivable facility that was scheduled to expire on March 5, 2007. There were no loans outstanding under the Utility’s accounts receivable facility at the time of termination.

Commercial Paper Program

The Utility has a program that currently includes the issuance of up to $1.0 billion of commercial paper notes. Commercial paper borrowings are used primarily to cover operating expenses and seasonal fluctuations in cash flows and are supported by available capacity under the working capital facility. The commercial paper may have maturities up to 365 days and ranks equally with the Utility’s other unsubordinated and unsecured indebtedness. At March 31, 2007, the Utility had $39 million of commercial paper outstanding at an average yield of approximately 5.51%.

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 non-bypassable charge levied on residential and small commercial customers. The total principal amount of RRBs outstanding at March 31, 2007 was approximately $215 million. The RRBs are scheduled to mature on December 26, 2007.

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, PG&E Energy Recovery Funding LLC (“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 dedicated rate component. The total principal amount of ERBs outstanding at March 31, 2007 was approximately $2.2 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, 2007 were as follows:

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

Balance at December 31, 2006	$	7,811		$	8,200
Effects of adoption of FIN 48 at January 1, 2007		(18	)		(21	)
Net income		256			261
Common stock issued		26			-
Common restricted stock amortization		8			-
Common stock dividends declared and paid		-			(127	)
Common stock dividends declared but not yet paid		(126	)		-
Preferred stock dividends		-			(3	)
Tax benefit from share-based payment awards		15			10
Other comprehensive income		5			5
Balance at March 31, 2007	$	7,977		$	8,325

On April 19, 2007, PG&E Corporation made an equity infusion of $200 million to the Utility to maintain the 52% common equity target authorized by the CPUC and ensure that the Utility has adequate capital to fund its capital expenditures.

Dividends

On March 19, 2007, the Utility paid common stock dividends totaling $137 million, including $127 million of common stock dividends paid to PG&E Corporation and $10 million of common stock dividends paid to PG&E Holdings LLC, a wholly owned subsidiary of the Utility.

On January 15 and April 15, 2007, PG&E Corporation paid common stock dividends of $0.33 and $0.36 per share, respectively, totaling $258 million, including $17 million of common stock dividends paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

PG&E Corporation and the Utility record common stock dividends declared to Reinvested Earnings.

On February 15, 2007, the Utility paid a cash dividend on various series of its preferred stock outstanding in the aggregate amount of $3 million. On February 21, 2007, the Board of Directors of the Utility declared a cash dividend on various series of its preferred stock payable on May 15, 2007 to shareholders of record on April 30, 2007.

NOTE 6: EARNINGS PER COMMON SHARE

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” 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 in dividends on a 1:1 basis with common shares.

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,” (“SFAS No. 128”). SFAS No. 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 (i.e., 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 net income per share:

	Three Months Ended
	March 31,
(in millions, except share amounts)	2007		2006

Net income	$	256	$	214
Less: distributed earnings to common shareholders		126		114
Undistributed earnings	$	130	$	100
Common shareholders earnings
*Basic*
Distributed earnings to common shareholders	$	126	$	114
Undistributed earnings allocated to common shareholders		123		95
Total common shareholders earnings, basic	$	249	$	209
*Diluted*
Distributed earnings to common shareholders	$	126	$	114
Undistributed earnings allocated to common shareholders		123		95
Total common shareholders earnings, diluted	$	249	$	209
Weighted average common shares outstanding, basic		349		344
9.50% Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, basic		368		363
Weighted average common shares outstanding, basic		349		344
Employee share-based compensation and accelerated share repurchase program⁽¹⁾		2		5
Weighted average common shares outstanding, diluted		351		349
9.50% Convertible Subordinated Notes		19		19

Weighted average common shares outstanding and participating securities, diluted		370		368
Net earnings per common share, basic
Distributed earnings, basic⁽²⁾	$	0.36	$	0.33
Undistributed earnings, basic		0.35		0.28
Total	$	0.71	$	0.61
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.36	$	0.33
Undistributed earnings, diluted		0.35		0.27
Total	$	0.71	$	0.60

⁽¹⁾ Includes approximately 2.8 million shares of PG&E Corporation common stock treated as outstanding in connection with accelerated share repurchases for the three months ended March 31, 2006. The remaining shares of approximately 2 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 10 of the 2006 Annual Report.
⁽²⁾“Distributed earnings, basic” may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual number of shares outstanding.

Options to purchase 7,285 and 16,600 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three months ended March 31, 2007 and 2006, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock over these periods.

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: DERIVATIVES AND HEDGING ACTIVITIES

The Utility enters into contracts to procure electricity, natural gas, nuclear fuel, and firm electricity transmission rights. Some of these contracts meet the definition of derivative instruments under SFAS No. 133. All derivative instruments, including instruments designated as cash flow hedges, are recorded at fair value and presented as price risk management assets and liabilities on the balance sheet. Derivative instruments may be designated as cash flow hedges when they are entered into to hedge variable price risk associated with the purchase of commodities. Changes in the fair value of derivative instruments are deferred and recorded in regulatory accounts because they are expected to be recovered or refunded through regulated rates. Under the same regulatory accounting treatment, changes in the fair value of cash flow hedges are also recorded in regulatory accounts, rather than being deferred in accumulated other comprehensive income.

On PG&E Corporation’s and the Utility's Condensed Consolidated Balance Sheets, price risk management activities appear as summarized below:

	Derivatives				Cash Flow Hedges
	March 31, 2007		December 31, 2006		March 31, 2007		December 31, 2006
(in millions)
Current Assets – Prepaid expenses and other	$	65	$	16	$	14	$	3
Other Noncurrent Assets – Other		60		37		10		8
Current Liabilities – Other		25		192		1		25
Noncurrent Liabilities – Other		3		50		-		-

The Utility also has derivative instruments for the physical delivery of commodities transacted in the normal course of business as well as non-financial assets that are not exchange-traded. These derivative instruments are eligible for the normal purchase and sales and non-exchange traded contract exceptions under SFAS No. 133, and are not reflected on the Condensed Consolidated Balance Sheet at fair value. They are recorded and recognized in income using accrual accounting. Therefore, expenses are recognized as incurred.

NOTE 8: SHARE-BASED COMPENSATION

On January 1, 2006, the PG&E Corporation 2006 Long-Term Incentive Plan (“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 10,846,839 shares were available for award at March 31, 2007.

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 still outstanding continue to be governed by the terms and conditions of the PG&E Corporation Long-Term Incentive Program.

On January 1, 2006, PG&E Corporation and the Utility adopted the provisions of SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”), using the modified prospective application 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. SFAS No. 123R requires that an estimate of future forfeitures be made and that compensation cost be recognized only for share-based payment awards that are expected to vest.

PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2%, based on historic forfeiture rates, for purposes of determining compensation expense for share-based incentive awards. The following table provides a summary of total compensation expense (reduction to compensation expense) for PG&E Corporation (consolidated) and the Utility (stand-alone) for share-based incentive awards for the three months ended March 31, 2007 and 2006:

	PG&E Corporation					Utility
	Three Months Ended March 31,					Three Months Ended March 31,
(in millions)	2007			2006		2007			2006

Stock options	$	2		$	3	$	1		$	2
Restricted stock		8			8		5			6
Performance shares		(6	)		15		(5	)		11
Total compensation expense (pre-tax)	$	4		$	26	$	1		$	19
Total compensation expense (after-tax)	$	2		$	15	$	1		$	11

Stock Options

Other than the grant of options to purchase 7,285 shares of PG&E Corporation common stock to non-employee directors of PG&E Corporation in accordance with the formula and nondiscretionary provisions of the 2006 LTIP, no other stock options were granted during the three months ended March 31, 2007. The exercise price of stock options granted under the 2006 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $7.81 and $6.98 per share in 2007 and 2006, respectively. The significant assumptions used for shares granted in 2007 and 2006 were:

	2007			2006
Expected stock price volatility		16.5	%		22.1	%
Expected annual dividend payment	$	1.44		$	1.32
Risk-free interest rate		4.73	%		4.46	%
Expected life	5.4 years			5.6 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.

As of March 31, 2007, there was approximately $8 million of total unrecognized compensation cost related to outstanding stock options, of which $5 million was allocated to the Utility. That cost is expected to be recognized over a weighted average period of 1.4 years for PG&E Corporation and the Utility.

Restricted Stock

During the three months ended March 31, 2007, PG&E Corporation awarded 559,129 shares of PG&E Corporation restricted common stock under the 2006 LTIP to eligible participants of PG&E Corporation and its subsidiaries, of which 388,050 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 restricted stock awarded in 2004 and 2005, 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 total shareholder return (“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 for 2006 grants and the first business day of 2010 for 2007 grants. 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 for 2006 grants and the first business day of 2012 for 2007 grants. Compensation expense related to the portion of the 2006 restricted stock award that is subject to conditions based on TSR is recognized over the shorter of the requisite service period and three years.

As of March 31, 2007, there was approximately $30 million of total unrecognized compensation cost relating to restricted stock, of which $20 million related to the Utility. PG&E Corporation and the Utility expect to recognize this cost over a weighted average period of 2.9 years.

Performance Shares and Performance Units

During the three months ended March 31, 2007, PG&E Corporation awarded 421,895 performance shares under the 2006 LTIP to eligible participants of PG&E Corporation and its subsidiaries, of which 279,585 shares were awarded to the Utility’s eligible participants. 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 that recipients are entitled to receive is based on the average closing price of PG&E Corporation stock for the last 30 calendar days of the year preceding the vesting dateand a payout percentage, ranging from 0% to 200%, as measured by PG&E Corporation’s TSR relative to its comparator group for the applicable three-year period.

Outstanding performance shares are classified as liabilities (Current Liabilities - Other and Noncurrent Liabilities - Other 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 the end of each reporting period 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 fluctuates 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 at the higher of fully loaded cost (i.e., direct costs and allocations of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are priced 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,
	2007		2006			2007			2006
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1		$	(1	)	$	2
Utility employee benefit assets due from PG&E Corporation		-		(1	)		30			25
Utility expenses from:
Administrative services received from PG&E Corporation	$	24	$	39		$	(27	)	$	(40	)
Utility employee benefit payments due to PG&E Corporation		1		-			-			-

NOTE 10: THE UTILITY'S EMERGENCE FROM CHAPTER 11

The U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of (1) the Chapter 11 Settlement Agreement, (2) the Utility’s plan of reorganization under Chapter 11, and (3) the Bankruptcy Court's order confirming the plan of reorganization. In addition, the Bankruptcy Court retains jurisdiction to resolve remaining disputed claims.

At December 31, 2004, the Utility had accrued approximately $2.1 billion for remaining disputed claims. Since December 31, 2004, the Utility has reached settlements and made payments on various claims. As of March 31, 2007, the amount of the accrual for remaining net disputed claims was approximately $1.2 billion, consisting of approximately $1.7 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator (“CAISO”) and the Power Exchange (“PX”), offset by an accounts receivable from the CAISO and the PX of approximately $0.5 billion. The Utility held $1.2 billion in escrow for the payment of the remaining disputed claims as of March 31, 2007. The Utility has been collecting amounts from customers each year for the difference between the interest earned on the escrow amounts and the FERC-ordered interest rate that is accrued on the claims. As of March 31, 2007, the Utility has accrued interest of approximately $507 million (classified as Interest Payable in the Condensed Consolidated Balance Sheets) on the disputed claims balance at the FERC-ordered interest rate. Upon resolution of these claims and under the terms of the Chapter 11 Settlement Agreement, any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers will be returned to customers, along with any excess interest accrued. With the approval of the Bankruptcy Court, the Utility has withdrawn certain amounts from escrow in connection with settlements with certain CAISO and PX sellers.

NOTE 11: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility's operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, power purchases made during the 2000-2001 California energy crisis, regulatory proceedings, nuclear operations, employee matters, environmental compliance and remediation, and legal matters.

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase electricity and makes payments under existing power purchase agreements. At March 31, 2007, the undiscounted future expected power purchase agreement payments based on March 31, 2007 forward prices were as follows:

(in millions)
2007	$	1,916
2008		2,404
2009		2,210
2010		2,010
2011		1,872
Thereafter		12,881
Total	$	23,293

Payments made by the Utility under power purchase agreements amounted to approximately $655 million for the three months ended March 31, 2007 and $439 million for the same period in 2006. The amounts described above do not

include payments related to the California Department of Water Resources’ (“DWR”) purchases, since the Utility only acts as an agent for the DWR.

On April 24, 2007, a proposed decision was issued that, if adopted by the CPUC, would modify the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. If adopted, the proposed decision would affect those QFs who did not enter into a 2006 settlement agreement between the Utility and the Independent Energy Producers (on behalf of the settling QFs) to resolve these pricing issues. Among other proposed changes, the proposed decision would modify the current formula for determining the utilities’ short-run avoided costs (“SRAC”) (i.e., the cost of energy, which, in the absence of a QF’s generation, the utilities would otherwise generate or purchase from another source) that is used to calculate the amount of energy payments to QFs. The proposed new SRAC formula would use a market index formula based on a day-ahead market price. Assuming the proposed decision is adopted by the CPUC, the Utility anticipates its energy payments to the non-settling QFs would be reduced, depending on future market prices. (See “Regulatory Matters – Rulemaking Proceeding to Modify QF Pricing and Policies” below and the 2006 Annual Report.)

The following table shows the future fixed capacity payments due under QF contracts that are treated as capital leases. These amounts are also included in the table above. The fixed capacity payments are discounted to the present value shown in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.

(in millions)
2007	$	43
2008		50
2009		50
2010		50
2011		50
Thereafter		303
Total fixed capacity payments		546
Less: Amount representing interest		148
Present value of fixed capacity payments	$	398

Interest and amortization expense associated with the lease obligation is included in the Cost of Electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. In accordance with SFAS No. 71, the timing of the Utility’s recognition of the lease expense will conform to the ratemaking treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April 2014 and September 2021.

Capacity payments are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

Natural Gas Supply and Transportation Commitments

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

At March 31, 2007, the Utility's undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2007	$	1,041
2008		363
2009		38
2010		22
2011		14
Thereafter		-
Total	$	1,478

Payments for natural gas purchases and gas transportation services amounted to approximately $728 million for the three months ended March 31, 2007 and $821 million for the same period in 2006.

Nuclear Fuel Agreements

The Utility has entered several purchase agreements for nuclear fuel. These agreements have terms ranging from two to thirteen years and are intended to ensure long-term fuel supply. In most cases, the Utility's nuclear fuel contracts are requirements-based. These contracts for uranium, conversion, and enrichment services provide for 100% coverage of reactor requirements through 2009. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms also are diversified, ranging from fixed prices to market-based prices to base prices that are escalated using published indices.

At March 31, 2007, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2007	$	118
2008		88
2009		66
2010		77
2011		43
Thereafter		256
Total	$	648

Payments for nuclear fuel amounted to approximately $23 million for the three months ended March 31, 2007 and $4 million for the same period in 2006.

Reliability Must Run Agreements

The CAISO has entered into reliability must run (“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 CAISO'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 CAISO's costs paid under RMR agreements to power plant owners within or adjacent to the Utility's service territory. RMR agreements are established or extended on an annual basis. In 2006, the CPUC adopted rules to implement state law requirements for California investor-owned utilities to meet resource adequacy requirements, including rules to address local transmission system reliability issues. As the utilities fulfill their responsibility to meet these requirements, the number of RMR agreements with the CAISO and the associated costs will decline. At March 31, 2007, the Utility’s estimated RMR agreement payments to CAISO could be approximately $64 million during 2007. The Utility recovers these costs from customers.

In March 2007, the Utility received refunds of approximately $61 million for amounts paid under RMR agreements in 2006 as part of a settlement agreement entered into by the Utility, the California Electricity Oversight Board, and certain other owners of RMR plants. The refunds were credited to the Utility’s electricity customers.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain indemnity obligations of its former subsidiary National Energy & Gas Transmission, Inc. (“NEGT”) that were issued to the purchaser of an NEGT subsidiary company. 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, and is limited to $150 million. PG&E Corporation has never received any claims nor does it consider it probable any claims will be made under the guarantee. At March 31, 2007, PG&E Corporation’s potential exposure under this guarantee was immaterial and PG&E Corporation has not made any provision for this guarantee.

Utility

PX Block-Forward Contracts

During the energy crisis in 2001, 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.” In response, the Utility, the PX, and

some of the PX market participants filed competing claims in state court against the State of California to recover the value of the Utility’s contracts that were seized. In March 2007, the PX dismissed its complaint against the State of California with prejudice (i.e., it cannot be re-filed at a later time). In May 2007, the Utility dismissed its complaint against the State of California with prejudice and each side agreed to bear its own fees and costs. Accordingly, the Utility wrote off its receivable of $243 million and the corresponding reserve representing the estimated value of the contracts at the time of seizure. The only plaintiff remaining is the Los Angeles Department of Water and Power. PG&E Corporation and the Utility do not expect that the outcome, with respect to the remaining plaintiff, will have a material effect on their financial condition or results of operations.

California Energy Crisis Proceedings

Several parties, including the Utility and the State of California, are seeking refunds on behalf of California electricity purchasers from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and PX wholesale electricity markets between May 2000 and June 2001 through various FERC and judicial proceedings. Many issues raised in these proceedings, including the extent of the FERC's refund authority, and the amount of potential refunds after taking into account certain costs incurred by the electricity suppliers, have not been resolved. It is uncertain when these proceedings will be concluded.

The Utility has entered into settlements with various electricity suppliers resolving certain disputed claims and the Utility's refund claims against these electricity suppliers. The Utility has received consideration of approximately $1 billion under these settlements through cash proceeds, reductions to the Utility's PX liability, and the Gateway Generating Station, a partially constructed generating facility formerly owned by Mirant Corporation. With the approval of the Bankruptcy Court, the Utility has withdrawn certain amounts from escrow (classified as Restricted Cash in the Condensed Consolidated Balance Sheets) in connection with certain of these settlements (see further discussion in Note 10). These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various issues being considered by the FERC. In April 2007, the Utility received a refund settlement payment of approximately $19 million and expects to receive approximately $77 million (including interest) from three new settlements which are now awaiting FERC approval. Additional settlement discussions with other electricity suppliers are ongoing. Future amounts received under these settlements and any future settlements with electricity suppliers will be credited to customers after deductions for contingencies.

PG&E Corporation and the Utility are unable to predict when the FERC proceedings will ultimately be resolved and the amount of any potential refunds the Utility may receive.

Spent Nuclear Fuel Storage Proceedings

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (“DOE”) is responsible for the transportation and permanent storage and disposal of spent nuclear fuel and high-level radioactive waste. The Utility has contracted with the DOE to provide for the disposal of these materials from the Utility’s Diablo Canyon nuclear generating facilities (“Diablo Canyon”). Under the contract, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon's spent fuel would be accepted for storage or disposal is thought to be 2018. Under current operating procedures, the Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.

After receiving a permit from the Nuclear Regulatory Commission (“NRC”) in March 2004, the Utility began building an on-site dry cask storage facility to store spent fuel through at least 2024. The Utility estimates it could complete the dry cask storage project in 2008. The NRC’s March 2004 decision, however, was appealed by various parties, and the U.S. Court of Appeals for the Ninth Circuit issued a decision in 2006 that requires the NRC to consider the environmental consequences of a potential terrorist attack at Diablo Canyon as part of the NRC’s supplemental assessment of the dry cask storage permit. In accordance with the Ninth Circuit decision, the NRC currently is conducting its supplemental assessment. The Utility may incur significant additional expenditures if the NRC decides that the Utility must change the design and construction of the dry cask storage facility. If the Utility is unable to complete the dry cask storage facility, or if operation of the facility is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and until such time as additional spent fuel can be safely stored.

As a result of the DOE’s failure to develop a permanent storage facility, the Utility has been required to incur substantial costs for planning and developing the on-site storage options for spent nuclear fuel described above at Diablo Canyon, as well as at the Utility’s retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”). The Utility is seeking

to recover these costs from the DOE on the basis that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. Any amounts recovered from the DOE will be credited to customers. In October 2006, the U.S. Court of Federal Claims issued a decision awarding the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004. The Utility will seek recovery of costs incurred after 2004 in future lawsuits against the DOE. In January 2007, the Utility filed a notice of appeal of the U.S. Court of Federal Claims’ decision in the U.S. Court of Appeals for the Federal Circuit seeking to increase the amount of the award and challenging the U.S. Court of Federal Claim’s finding that the Utility would have incurred some of the costs for the on-site storage facilities even if the DOE had complied with the contract. The Utility filed its opening brief in April 2007. Absent any extensions of time, the government’s response will be due in May 2007.

If the U.S. Court of Federal Claim’s decision is not overturned or modified on appeal, it is likely that the Utility will be unable to recover all of its future costs for on-site storage facilities from the DOE. However, reasonably incurred costs related to the on-site storage facilities are, in the case of Diablo Canyon, recoverable through rates and, in the case of Humboldt Bay Unit 3, recoverable through its decommissioning trust fund.

PG&E Corporation and the Utility are unable to predict the outcome of this appeal or the amount of any additional awards the Utility may receive.

Catastrophic Event Memorandum Account Application

The CPUC allows utilities to recover the reasonable costs of responding to catastrophic events through a catastrophic event memorandum account (“CEMA”). The CEMA tariff authorizes the utilities to recover costs incurred in connection with a catastrophic event that has been declared a disaster or state of emergency by competent state or federal authorities. The Utility filed a CEMA application requesting that it be authorized to recover approximately $45 million in capital and expense costs incurred during the 2005-2006 winter storms and the July 2006 “heat storm.” The Utility has requested that these costs be recovered through rates in 2008. On April 24, 2007, a CPUC administrative law judge issued a proposed decision which would find that the July 2006 heat storm does not meet the CPUC’s definition of a catastrophic event and would disallow recovery of approximately $26 million in costs incurred in connection with the July 2006 heat storm. It is anticipated that the proposed decision will be considered by the CPUC at its meeting on May 24, 2007. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the proposed decision.

The April 24, 2007 proposed decision does not address recovery of costs incurred by the Utility in connection with the 2005-2006 winter storms. It is expected that a separate proposed decision will be issued to address those costs. PG&E Corporation and the Utility are unable to predict when a proposed decision will be issued.

Nuclear Insurance

The Utility has several types of nuclear insurance for Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident 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 $41.4 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, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion within a 12-month period 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 megawatt (“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. 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 Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC 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 purchased under the DWR contracts with various generators provided approximately 27% of the electricity delivered to the Utility's customers for the three months ended March 31, 2007. 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 has stated publicly in the past that it intends to transfer full legal title of, 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 Chapter 11 Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

·	After assumption, the Utility's issuer rating by Moody's Investors Service will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor’s Rating 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.

Severance in Connection with Efforts to Achieve Cost and Operating Efficiencies

In connection with the Utility’s continued efforts to streamline processes and achieve cost and operating efficiencies through implementation of various initiatives, jobs from numerous Utility locations around California are being consolidated. As a result, the Utility has eliminated a number of positions and expects to eliminate more.

Estimating severance costs requires the Utility to predict whether employees will elect severance or reassignment, and the number of available vacant positions for employees wishing to be reassigned. Depending on the employees’ elections, costs will further vary based on the employees’ years of service and annual salary. Given the uncertainty of each of these variables, the estimated range is relatively wide. In February 2007, the Utility announced planned reductions of certain clerical employees. At March 31, 2007, the Utility’s future severance expenses related to these initiatives, accounted for under SFAS No. 5, “Accounting for Contingencies,” were expected to range from $46 million to approximately $81 million, of which the Utility has recorded the low end as of March 31, 2007. The following table presents the changes in the liability from December 31, 2006:

(in millions)
Balance at December 31, 2006	$	34
Additional Severance Accrued		13
Less: Payments		(1	)
Balance at March 31, 2007	$	46

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 environmental laws. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances at former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling or disposal of potentially hazardous materials, 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. 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. The Utility estimates the upper end of this cost range using reasonably possible outcomes that are least favorable to the Utility. 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 had an undiscounted environmental remediation liability of approximately $518 million at March 31, 2007 and approximately $511 million at December 31, 2006. The $518 million accrued at March 31, 2007 includes:

·	approximately $238 million for remediation at the Hinkley and Topock natural gas compressor sites;

·	approximately $98 million related to remediation at divested generation facilities; and

·	approximately $182 million related to remediation costs for the Utility’s generation facilities and gas gathering sites, third-party disposal sites, and manufactured gas plant sites owned by the Utility or third parties (including those sites that 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 $518 million environmental remediation liability, approximately $143 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately $286 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

The Utility's undiscounted future costs could increase to as much as $808 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 $808 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites in the Utility's service territory that were previously owned by the Utility or a predecessor but that are now owned by others because the Utility either has not been able to determine if a liability exists with respect to these sites or the Utility has not been able to estimate the amount of any future potential remediation costs that may be incurred for these sites.

In July 2004, the U.S. Environmental Protection Agency (“EPA”) published regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The EPA regulations affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of "once-through" cooling. The Utility's Diablo Canyon power plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The EPA regulations establish a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards. The EPA regulations allow site-specific compliance determinations if a facility's cost of compliance is significantly greater than either the benefits achieved or the compliance costs considered by the EPA and also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties challenged the EPA's regulations, and the cases were consolidated in U.S. Court of Appeals for the Second Circuit (“Second Circuit”).

In June 2006, the California State Water Resources Control Board published a draft policy for California’s implementation of Section 316(b). If adopted, the policy would be substantially more stringent than the 2004 EPA regulations, as the state policy would eliminate the EPA’s site-specific compliance options based on cost-benefit assessments and require the installation of cooling towers at once-through cooled power facilities. The draft state policy provides that nuclear facilities may use environmental restoration as a compliance option only if the installation of technology would conflict with a nuclear safety requirement. It is uncertain when the state’s final policy will be adopted. If the final policy is adopted without change from the draft policy, the Utility could be required to incur significant capital costs to achieve compliance.

In January 2007, the Second Circuit issued its decision on the appeals of the EPA’s Clean Water Act regulations. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and held that a cost

benefit test cannot be used to establish performance standards or to grant variances from the standards. The Second Circuit also ruled that environmental restoration cannot be used to achieve compliance. The parties may seek further review by the Second Circuit or the U.S. Supreme Court, but regardless of that, the EPA will likely require significant time to review and revise its regulations. It is uncertain how the Second Circuit decision will affect development of the California State Water Resources Control Board’s proposed implementation policy. The regulatory uncertainty is likely to continue, and the Utility’s cost of compliance will remain uncertain as well.

Taxation Matters

The Internal Revenue Service (“IRS”) has indicated that it intends to close its audit of PG&E Corporation’s 1997 and 1998 consolidated federal income tax returns by the end of 2007. Although the IRS initially assessed additional federal income taxes of approximately $90 million (including interest), PG&E Corporation and the IRS Appeals Office tentatively resolved the IRS’ adjustments that PG&E Corporation had contested. PG&E Corporation believes that the ultimate outcome of the 1997-1998 audit will not have a material effect on its financial condition or results of operations.

The IRS currently is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. The IRS is proposing to disallow a number of deductions claimed by PG&E Corporation, including deductions for abandoned or worthless assets owned by NEGT. In addition, the IRS is proposing to disallow $104 million of synthetic fuel credits claimed by PG&E Corporation. If the IRS includes all of its proposed disallowances in its final Revenue Agent Report, the alleged tax deficiency would approximate $452 million. Of this deficiency, approximately $316 million is of a timing nature, which would be refunded to PG&E Corporation in the future. The IRS has indicated it will complete its final Revenue Agent Report in the second half of 2007. PG&E Corporation believes that it properly reported these transactions in its tax returns and will contest any IRS assessment.

The IRS is also auditing PG&E Corporation’s 2003 and 2004 consolidated federal income tax returns. No significant disallowances have been proposed.

In July 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes. On January 1, 2007, PG&E Corporation and the Utility adopted FIN 48. (See Note 2 above for a discussion of the impact of adoption.)

PG&E Corporation has $229 million of remaining capital loss carry-forwards from the disposition of its NEGT ownership interest in 2004, which, if not used by December 2009, will expire.

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.

In accordance with SFAS No. 5, 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 Noncurrent Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately $65 million at March 31, 2007 and approximately $74 million at December 31, 2006.

After considering the above accruals, PG&E Corporation and the Utility do not expect that losses associated with legal matters will have a material impact on their 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. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (the “Utility”), a public utility operating in northern and central California. The Utility engages 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.

The Utility served approximately 5.1 million electricity distribution customers and approximately 4.2 million natural gas distribution customers at March 31, 2007. The Utility had approximately $34.3 billion in assets at March 31, 2007 and generated revenues of approximately $3.4 billion in the three months ended March 31, 2007.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility generates revenues 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 PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2006, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2006 Annual Report.” Significant developments that have occurred since the 2006 Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed in this quarterly report.

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 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 (“MD&A”) of PG&E Corporation and the Utility should be read in conjunction with the Condensed Consolidated Financial Statements and Notes to the Condensed Consolidated Financial Statements included in this quarterly report, as well as the MD&A, Consolidated Financial Statements, and Notes to the Consolidated Financial Statements incorporated by reference in the 2006 Annual Report.

Summary of Changes in Earnings per Common Share and Net Income for the Three Months Ended March 31, 2007

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three months ended March 31, 2007 was $0.71 per share, compared to $0.60 per share for the same period in 2006. For the three months ended March 31, 2007, PG&E Corporation’s net income increased by approximately $42 million, or 20%, to $256 million, compared to $214 million in the same period in 2006. The increase in diluted EPS and net income for 2007 is primarily due to increased revenues in 2007 associated with the return on equity (“ROE”) on additional capital investments authorized by the CPUC and the FERC. The increase in net income includes approximately $23 million ($0.06 per share) as a result of the rate base increase authorized by the CPUC in the Utility’s General Rate Case (“GRC”) effective January 1, 2007 and approximately $3 million ($0.01 per share) as a result of the increase in electric transmission rates subject to refund, effective March 1, 2007. In addition, there was an approximately $7 million decrease in storm-related expenses in the first quarter of 2007 as compared to 2006, resulting in a $0.02 per share increase in diluted EPS in 2007 compared to 2006.

Key Factors Affecting Results of Operations and Financial Condition

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 which, in part, depend on management’s ability to accurately forecast future costs incurred in providing utility service, timely recover its authorized costs, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation's and the Utility's results of operations and financial condition, including:

·	The Outcome of Regulatory Proceedings. The amount of the Utility’s revenues and the amount of costs the Utility is authorized to recover from customers are primarily determined through regulatory proceedings. The timing of CPUC and FERC decisions affect when the Utility is able to record the authorized revenues. On March 15, 2007, the CPUC issued a decision in the Utility’s general rate case (“GRC”) establishing the Utility’s revenue requirements for its electric and natural gas distribution operations and its electric generation operations for 2007 through 2010. The CPUC approved an increase of $222 million in electric distribution revenues, an increase of $21 million in gas distribution revenues, and a decrease of $30 million in electric generation operation revenues, for an overall increase of $213 million, over the authorized 2006 amounts. The revenue requirement changes are effective January 1, 2007. On March 1, 2007, the Utility began collecting increased electric transmission rates, subject to refund, based on the Utility’s requested annual electric transmission retail revenue requirement of $719 million, an increase of approximately $113 million over the current authorized amount. The Utility’s offer of settlement, submitted to the FERC for approval, proposes to set the transmission retail revenue requirement at $674 million, an increase of approximately $68 million over the current authorized amount. The outcome of various other regulatory proceedings also will have a material effect. (See “Regulatory Matters” below and the 2006 Annual Report.)

·	Capital Structure. The Utility’s 2006 and 2007 authorized capital structure includes a 52% equity component. For 2006 and 2007, the Utility is authorized to earn a rate of ROE of 11.35% on its electricity and natural gas distribution and electricity generation rate base. The CPUC will conduct a new cost of capital proceeding to set the Utility’s authorized capital structure and rates of return for 2008. On May 8, 2007 the Utility filed its 2008 cost of capital application. (See “2008 Cost of Capital Proceeding” below.)

·	The Success of the Utility’s Strategy to Achieve Operational Excellence and Improved Customer Service. During 2007, the Utility is continuing to implement changes to its business processes and systems in an effort to provide better, faster, and more cost-effective service to its customers. It expects to continue to incur costs (excluding capital expenditures) of approximately $165 million in 2007 for further implementation of these initiatives. As of March 31, 2007, the Utility incurred costs (excluding capital expenditures) of approximately $28 million, including $13 million of severance costs for these initiatives. The increases in revenue requirements for 2008, 2009, and 2010 included in the GRC decision are expected to be adequate in light of the anticipated cost savings to be realized from these initiatives. If the actual cost savings are greater than anticipated, such benefits would accrue to shareholders. Conversely, if these cost savings are not realized, earnings available for shareholders would be reduced.

·	The Amount and Timing of Capital Expenditures. The CPUC authorized the Utility to make substantial capital expenditures in connection with the construction of new generation facilities estimated to become operational beginning in 2009 and 2010, and the installation of an advanced metering system. The Utility also received regulatory approval for various 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 already authorized growth). The amount and timing of the Utility’s capital expenditures will affect the amount of rate base on which the Utility may earn its authorized ROE. If the CPUC does not allow the Utility to recover any portion of its capital expenditures from customers, the Utility would be unable to earn a ROE on the disallowed amount. (See further discussion under “Capital Expenditures” below.)

·	Changes in Environmental Liabilities.The Utility's operations are subject to extensive federal, state, and local environmental laws and permits. Complying with these environmental laws has in the past required significant expenditures for environmental compliance, monitoring, and pollution control equipment, as well as for related fees and permits. In the three months ended March 31, 2007, the Utility increased its recorded liability for environmental remediation by approximately $7 million. (See discussion under “Environmental and Legal Matters” below.)

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. These statements are based on current estimates, expectations, and projections about future events, and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, the anticipated outcome of various regulatory and legal proceedings, future cash flows, and the level of future equity or debt issuances, and are also identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "aim, " "may," "might," "should," "would," "could," "goal," "potential," and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

·	the Utility’s ability to timely recover costs through rates;

·	the outcome of regulatory proceedings, including ratemaking proceedings pending at the CPUC and the FERC;

·	the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets;

·	the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and third parties on which the Utility relies;

·	the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

·	changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology including the development of alternative energy sources, or other reasons;

·	operating performance of the Utility’s Diablo Canyon nuclear generating facilities (“Diablo Canyon”), the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

·	the ability of the Utility to recognize benefits from its initiatives to improve its business processes and customer service;

·	the ability of the Utility to timely complete its planned capital investment projects;

·	the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

·	the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;

·	how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;

·	the extent to which PG&E Corporation or the Utility incur costs and liabilities in connection with pending litigation that are not recoverable through rates, from third parties, or through insurance recoveries;

·	the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit;

·	the impact of environmental laws and regulations and the costs of compliance and remediation; and

·	the effect of municipalization, direct access, community choice aggregation, or other forms of bypass.

For more information about 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, see the discussion under the heading “Risk Factors” in the 2006 Annual Report and Part II, Item 1A., Risk Factors below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events or otherwise.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006.

	Three Months Ended
	March 31,
	2007			2006
(in millions)
Utility
Electric operating revenues	$	2,175		$	1,863
Natural gas operating revenues		1,181			1,285
Total operating revenues		3,356			3,148
Cost of electricity		723			530
Cost of natural gas		754			873
Operating and maintenance		919			862
Depreciation, amortization and decommissioning		429			413
Total operating expenses		2,825			2,678
Operating income		531			470
Interest income		48			19
Interest expense		(182	)		(146	)
Other income, net⁽¹⁾		6			3
Income before income taxes		403			346
Income tax provision		145			132
Income available for common stock	$	258		$	214
PG&E Corporation, Eliminations and Other⁽²⁾
Operating revenues	$	-		$	-
Operating expenses		2			1
Operating loss		(2	)		(1	)
Interest income		4			4
Interest expense		(8	)		(8	)
Other expense, net⁽¹⁾		(2	)		(3	)
Loss before income taxes		(8	)		(8	)
Income tax benefit		(6	)		(8	)
Net income (loss)	$	(2	)	$	-
Consolidated Total
Operating revenues	$	3,356		$	3,148
Operating expenses		2,827			2,679
Operating income		529			469
Interest income		52			23
Interest expense		(190	)		(154	)
Other income, net⁽¹⁾		4			-
Income before income taxes		395			338
Income tax provision		139			124
Net income	$	256		$	214


⁽¹⁾Includes preferred stock dividend requirement as other expense.
⁽²⁾PG&E Corporation eliminates all intercompany transactions in consolidation.

Utility

The following presents the Utility's operating results for the three months ended March 31, 2007 and 2006.

Electric Operating Revenues

In addition to electricity provided by the Utility’s own generation facilities and by third parties under power purchase agreements, the Utility relies on electricity provided under long-term electricity contracts entered into by the California Department of Water Resources (“DWR”) to meet a material portion of the Utility’s customers' demand or “load.” 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 do not affect the Utility's revenues.

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

	Three Months Ended
	March 31,
(in millions)	2007			2006

Electric revenues	$	2,726		$	2,376
DWR pass-through revenues		(551	)		(513	)
Total electric operating revenues	$	2,175		$	1,863
Total electricity sales (in GWh)		14,778			15,118

The Utility’s electric operating revenues increased in the three months ended March 31, 2007 by approximately $312 million, or approximately 17%, compared to the same period in 2006, mainly due to the following factors:

·	Electricity procurement costs, which are passed through to customers, increased by approximately $232 million. (See “Cost of Electricity” below.)

·	The Utility recognized an increase to its authorized 2007 base revenue requirements, including pension revenues, of approximately $76 million as authorized in the 2007 GRC.

·	The Utility recovered approximately $20 million of net interest costs related to disputed generator claims as authorized by the CPUC. (See “Interest Income” and “Interest Expense” below and the 2006 Annual Report.)

·	Miscellaneous other electric operating revenues, including those associated with public purpose programs, and electric transmission revenues increased by approximately $47 million (see “Regulatory Matters - FERC Transmission Owner Rate Case” below.)

These increases were partially offset by a decrease of approximately $63 million in transmission revenues due to a decrease in the number of reliability must run agreements with the CAISO and the associated costs. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements.)

The Utility’s electric operating revenues for the period 2007 through 2010 will increase as authorized by the CPUC in the 2007 GRC. (For further discussion, see “Regulatory Matters” under “2007 General Rate Case” below.) In addition, the Utility expects to continue to collect revenue requirements related to CPUC-approved capital expenditure projects, including the new Utility-owned generation projects and advanced metering infrastructure. (See “Capital Expenditures” below.) Finally, future electric operating revenues will be impacted by changes in the cost of electricity.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs, hedging costs, and the cost of fuel used by its own generation facilities or supplied to other facilities under tolling agreements, but it excludes costs to operate the Utility’s own generation facilities, which are included in operating and maintenance expense. The Utility’s cost of purchased power and the cost of fuel used in Utility-owned generation are passed through 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 both the cost and volume of electricity provided by the DWR to the Utility's customers:

	Three Months Ended
	March 31,
(in millions)	2007			2006

Cost of purchased power	$	726		$	608
Proceeds from surplus sales allocated to the Utility		(40	)		(129	)
Fuel used in owned generation		37			51
Total cost of electricity		723			530
Average cost of purchased power per kWh	$	0.090		$	0.076
Total purchased power (in millions of kWh)		8,054			7,956

In the three months ended March 31, 2007, the Utility's cost of electricity increased by approximately $193 million, or 36%, compared to the same period in 2006, primarily driven by an 18% increase in the average cost of purchased power. The average cost of purchased power increased $0.014 per kilowatt-hour (“kWh”), compared to the same period in 2006, primarily due to higher energy payments made to qualifying facilities following the expiration of their five-year fixed price contracts during the summer of 2006.

The Utility's cost of electricity in 2007 will depend upon electricity prices, the duration of the Diablo Canyon refueling outage, and changes in customer demand which will directly impact the amount of power the Utility will be required to purchase. (See the "Risk Management Activities" section of this MD&A.) In addition, On April 24, 2007, a proposed decision was issued that, if adopted by the CPUC, would modify the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. (See “Regulatory Matters – Rulemaking Proceeding to Modify QF Pricing and Policies” below.)

The Utility’s future cost of electricity also may be affected by potential federal or state legislation or rules which may regulate the emissions of greenhouse gases from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures power. As directed by recent California legislation, the CPUC has adopted an interim greenhouse gas emissions performance standard that would apply to electricity procured or generated by the Utility. Additionally, California Assembly Bill 32 establishes a regulatory program and schedule for establishing a cap on greenhouse gas emissions in the state at 1990 levels effective by 2020, including a cap on the Utility’s emissions of greenhouse gases. The Utility’s existing and forecasted emissions of greenhouse gases are relatively low compared to average emissions by other electric utilities and generators in the country, and the Utility’s incremental costs of complying with greenhouse gas emissions regulations being promulgated by the CPUC and other California agencies are expected to be fully recovered in rates from the Utility’s customers under the CPUC’s ratemaking standards applicable to electricity procurement costs.

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services to its customers. The Utility's transportation system transports gas throughout California to the Utility's distribution system which, in turn, delivers natural gas to end-use customers. The Utility also delivers natural gas to off-system markets, primarily in southern California, in competition with interstate pipelines.

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

	Three Months Ended
	March 31,
(in millions)	2007		2006

Bundled natural gas revenues	$	1,103	$	1,217
Transportation service-only revenues		78		68
Total natural gas operating revenues	$	1,181	$	1,285
Average bundled revenue per Mcf of natural gas sold		9.83		11.75
Total bundled natural gas sales (in millions of Mcf)		112		104

In the three months ended March 31, 2007, the Utility's natural gas operating revenues decreased by approximately $104 million, or 8%, compared to the same period in 2006 primarily due to a decrease in the cost of natural gas, which is passed through to customers, as further discussed below under “Cost of Natural Gas.”

The Utility expects that its natural gas operating revenues for gas transmission will increase for 2007 due to an annual rate escalation as authorized in the Gas Accord III Settlement and, for the period 2008 through 2010, as may be authorized by the CPUC in the pending Gas Accord IV settlement agreement. (See “Regulatory Matters – Natural Gas Transmission and Storage Rate Case” below.) In addition, the Utility’s natural gas operating revenues for distribution will increase for the period 2007 through 2010 as authorized by the CPUC in the 2007 GRC. Finally, future natural gas operating revenues will be impacted by changes in the cost of natural gas.

Cost of Natural Gas

The Utility's cost of natural gas includes the purchase costs 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)	2007		2006

Cost of natural gas sold	$	706	$	837
Cost of natural gas transportation		48		36
Total cost of natural gas	$	754	$	873
Average cost per Mcf of natural gas sold		6.30		8.05
Total natural gas sold (in millions of Mcf)		112		104

In the three months ended March 31, 2007, the Utility's total cost of natural gas decreased by approximately $119 million, or 14%, compared to the same period in 2006, primarily due to a decrease in the average market price of natural gas purchased of approximately $1.75 per thousand cubic feet (“Mcf”), or 22%.

The Utility's cost of natural gas in 2007 will be primarily affected by the prevailing costs of natural gas, which are determined by North American regions that supply the Utility. The total 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 offset by corresponding annual revenues authorized by the CPUC and the FERC in various rate proceedings.

During the three months ended March 31, 2007, the Utility’s operating and maintenance expenses increased by approximately $57 million, or 7%, compared to the same period in 2006, mainly due to the following factors:

·	As a result of the 2007 GRC decision, the Utility recorded an additional $25 million in pension expense.

·	Accrual of severance costs associated with the Utility’s strategies to achieve operational excellence and improved customer service increased by approximately $13 million.

·	Payments made for low-income customer assistance programs increased by approximately $12 million.

Of the $50 million of increased expenses discussed above, approximately $35 million is recoverable in rates and did not affect net income in the three months ended March 31, 2007. Expenses not recoverable in rates are primarily related to severance in connection with initiatives to achieve operational excellence and improved customer service.

Operating and maintenance expenses are influenced by wage inflation, benefits, property taxes, the timing and length of Diablo Canyon refueling outages, environmental remediation costs, legal costs, and various other administrative and general expenses.

The Utility’s operating and maintenance expenses in the remainder of 2007 are expected to increase as a result of increased expenses primarily related to public purpose programs and the implementation of initiatives to achieve operational excellence and improved customer service. (See “Overview” section in this MD&A for further discussion.) As the Utility implements these initiatives, jobs from numerous locations around California are being consolidated and a number of positions are being eliminated. As discussed above, the Utility incurred approximately $13 million in severance costs for the three months ended March 31, 2007. The Utility expects that more positions will be eliminated and, as a result, expects to incur additional severance expenses in the future. Severance costs related to enhanced benefits outside of the standard severance package will also be incurred as specific individuals are identified for severance in future periods. (See further discussion in Note 11 of the Notes to the Condensed Consolidated Financial Statements.)

Depreciation, Amortization and Decommissioning

In the three months ended March 31, 2007, the Utility's depreciation, amortization and decommissioning expenses increased by approximately $16 million, or 4%, compared to the same period in 2006, mainly due to depreciation rate changes and plant additions authorized in the 2007 GRC decision.

The Utility’s depreciation and amortization expenses in 2007 are expected to increase as a result of an overall increase in capital expenditures and implementation of authorized 2007 GRC rates.

Interest Income

In the three months ended March 31, 2007, the Utility’s interest income increased by approximately $29 million, or 153%, compared to the same period in 2006, primarily due to an increase in interest earned on funds held in escrow for disputed generator claims which are passed through to customers. (See “Electric Operating Revenues” above for further discussion.) In addition, the Utility received interest income from a settlement with the Internal Revenue Service in February 2007 relating to years ranging from 1992-1996.

The Utility’s interest income in 2007 will be primarily affected by interest rate levels.

Interest Expense

In the three months ended March 31, 2007, the Utility’s interest expense increased by approximately $36 million, or 25%, compared to the same period in 2006, primarily due to an increase in interest expense related to disputed generator claims which are recovered from customers as an offset to interest income (net interest costs). (See “Electric Operating Revenues” above for further discussion.) This increase was partially offset by lower interest expense on the rate reduction bonds (“RRBs”) and ERBs due to their declining balances.

The Utility’s interest expense in 2007 and subsequent periods will be impacted by changes in interest rates as the Utility’s short-term debt and a portion of its long-term debt are interest rate-sensitive. In addition, future interest expense will increase due to interest payments on the additional $700 million principal amount of Senior Notes issued on March 13, 2007 and future debt expected to be issued in 2007 and later to finance an overall increase in capital investments.

Income Tax Expense

In the three months ended March 31, 2007, the Utility's income tax expense increased by approximately $13 million, or 10%, compared to the same period in 2006, primarily due to the increase in pre-tax income of $57 million. The effective tax rate for the three months ended March 31, 2007 and 2006 was 35.7% and 37.8%, respectively.

PG&E Corporation, Eliminations and Others

Operating Revenues and Expenses

PG&E Corporation's revenues consist mainly of billings to its 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

affiliates. These allocations are made without mark-up and are eliminated in consolidation.

There were no material changes to PG&E Corporation’s operating income and expense in the three months ended March 31, 2007 compared to the same period in 2006.

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, collateral requirements, 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 seek to maintain the Utility's 52% authorized common equity ratio.

At March 31, 2007, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $470 million and restricted cash of approximately $1.4 billion. At March 31, 2007, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $433 million; the Utility had cash and cash equivalents of approximately $37 million and restricted cash of approximately $1.4 billion. Restricted cash primarily consists of approximately $1.3 billion in cash held in escrow pending the resolution of the remaining disputed generator claims as well as deposits made by customers and other third parties under certain agreements. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in institutional money market funds.

As of March 31, 2007, PG&E Corporation and the Utility had credit facilities totaling $200 million and $2 billion, respectively, with remaining borrowing capacity on these credit facilities of $200 million and approximately $1.8 billion, respectively. As of March 31, 2007, the Utility had $177 million of letters of credit outstanding under its working capital facility and $39 million of outstanding commercial paper. During the quarter, the Utility terminated its $650 million accounts receivable facility when it increased its working capital facility to the current level. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.) Subject to obtaining commitments from existing or new lenders and satisfying other conditions, PG&E Corporation and the Utility also may increase the aggregate lender commitments under the credit facilities to $300 million and $3 billion, respectively. In addition, the Utility is considering increasing its borrowing capacity under the commercial paper program.

As stated at PG&E Corporation’s webcast analyst conference held on April 4, 2007, the Utility estimated that over the next five years it will issue approximately $4.4 billion to $4.8 billion in long-term debt to finance forecasted capital expenditures, including approximately $1.3 billion of long-term debt issuances in 2007. Of the estimated $1.3 billion in 2007 debt issuances, the Utility issued $700 million in Senior Notes in March 2007 and anticipates that it will issue an additional $600 million of long-term debt by the end of 2007. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.)

At the conference, the Utility also estimated that it will need to increase its common equity level to maintain the Utility’s 52% authorized common equity component of its capital structure and ensure that the Utility has adequate capital to fund its capital expenditures. The Utility estimated that over the next five years, its equity needs could range from approximately $750 million to $950 million. On April 19, 2007, PG&E Corporation made an equity infusion of $200 million to the Utility to partially meet the Utility’s forecasted equity needs. PG&E Corporation will continue to evaluate how to fund the Utility’s future equity needs, which could include a combination of internal equity sources, external equity issuances, and debt issuances.

The amount and timing of the Utility’s financing needs will depend on the timing and extent of forecasted capital expenditures and any new, incremental capital expenditures beyond those currently forecasted; the amount of cash internally generated through normal business operations; and the timing and extent of the settlement of the disputed generator claims (including the payment of all accrued interest on these claims and any related customer refunds).

Dividends

During the three months ended March 31, 2007, the Utility used cash in excess of amounts needed for operations, debt service, capital expenditures, and preferred stock requirements to pay quarterly common stock dividends of $137 million. Approximately $127 million in common stock dividends were paid to PG&E Corporation and the remaining amount

was paid to PG&E Holdings LLC, a wholly owned subsidiary of the Utility that held approximately 7% of the Utility's common stock as of May 8, 2007.

On January 15, 2007, PG&E Corporation paid common stock dividends of $0.33 per share, a total of $123 million, including approximately $8 million to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation that held approximately 7% of PG&E Corporation’s common stock as of May 8, 2007. On March 16, 2007, PG&E Corporation declared its first quarter 2007 dividend at $0.36 per share, an increase of $0.03 per share over the previous level of $0.33 per share. This action is consistent with PG&E Corporation’s targeted dividend payout ratio of between 50% to 70% of earnings. The first quarter dividend was paid on April 15, 2007 to shareholders of record on March 30, 2007, in an aggregate amount of $135 million, including approximately $9 million to Elm Power Corporation.

During the three months ended March 31, 2007, the Utility paid cash dividends to holders of its preferred stock totaling $3 million. On February 21, 2007, the Board of Directors of the Utility declared a cash dividend on various series of its preferred stock payable on May 15, 2007 to shareholders of record on April 30, 2007.

Utility

Operating Activities

The Utility's cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

The Utility's cash flows from operating activities for the three months ended March 31, 2007 and 2006 were as follows:

	Three Months Ended
(in millions)	March 31,
	2007		2006
Net income	$	261	$	217
Adjustments to reconcile net income to net cash provided by operating activities		665		429
Changes in operating assets and liabilities, and other		48		448
Net cash provided by operating activities	$	974	$	1,094

In the three months ended March 31, 2007, net cash provided by operating activities decreased by approximately $120 million from the same period in 2006, primarily due to an approximately $110 million decrease in cash settlements from energy suppliers.

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. Year-to-year variances in cash used in investing activities depend primarily 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, 2007 and 2006 were as follows:

	Three Months Ended
(in millions)	March 31,
	2007			2006
Capital expenditures	$	(673	)	$	(576	)
Net proceeds from sale of assets		4			3
Decrease (increase) in restricted cash		(11	)		52
Other investing activities		(18	)		(31	)
Net cash used in investing activities	$	(698	)	$	(552	)

Net cash used in investing activities increased by approximately $146 million in the three months ended March 31, 2007 compared to the same period in 2006, primarily due to an increase of approximately $97 million in capital expenditures. In addition, the Utility released $90 million more from escrow, net of escrow funding, in the three months ended March 31, 2006 upon settlement of disputed Chapter 11 generator claims, compared to the same period in 2007.

The Utility expects to maintain a high rate of infrastructure and information technology investment in its gas and electric system to keep pace with economic growth, to enhance the customer experience, and to mitigate the impacts of aging equipment on system performance. The Utility expects capital expenditures will total approximately $3.2 billion in 2007. The higher level of capital investment is mostly due to the advanced metering infrastructure installation project, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Financing Activities

The Utility’s cash flows from financing activities for the three months ended March 31, 2007 and 2006 were as follows:

	Three Months Ended
	March 31,
(in millions)	2007			2006

Borrowings under accounts receivable facility and working capital facility	$	-		$	50
Repayments under accounts receivable facility and working capital facility		(300	)		(310	)
Net repayment of commercial paper, net of $4 million discount on borrowings		(425	)		-
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million		690			-
Rate reduction bonds matured		(75	)		(74	)
Energy recovery bonds matured		(83	)		(56	)
Common stock dividends paid		(127	)		(115	)
Preferred dividends paid		(3	)		(3	)
Other		14			107
Net cash used in financing activities	$	(309	)	$	(401	)

In the three months ended March 31, 2007, net cash used in financing activities decreased by approximately $92 million compared to the same period in 2006. This was mainly due to the following factors:

·	The Utility made net payments of $425 million for commercial paper in the three months ended March 31, 2007, with no similar amount in the same period in 2006.

·	Net cash received for refundable deposits decreased by about $90 million from the three months ended March 31, 2006 to the same period in 2007.

·	In March 2007, the Utility received proceeds of $690 million for the issuance of Senior Notes, less approximately $10 million of discount and issuance costs, with no similar issuance in 2006.

Borrowings and repayments under the commercial paper program may fluctuate during the year based on working capital needs.

PG&E Corporation

Operating Activities

PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility 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 cash flow associated with operating activities for the three months ended March 31, 2007 and 2006.

Investing Activities

PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with investing activities for the three months ended March 31, 2007 and 2006.

Financing Activities

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

PG&E Corporation's cash flows from financing activities for the three months ended March 31, 2007 and 2006 were as follows:

	Three Months Ended
	March 31,
(in millions)	2007			2006

Borrowings under accounts receivable facility and working capital facility	$	-		$	50
Repayments under accounts receivable facility and working capital facility		(300	)		(310	)
Net repayment of commercial paper, net of $4 million discount on borrowings		(425	)		-
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million		690			-
Rate reduction bonds matured		(75	)		(74	)
Energy recovery bonds matured		(83	)		(56	)
Common stock issued		26			66
Common stock repurchased		-			(58	)
Common stock dividends paid		(123	)		(114	)
Other		26			109
Net cash used in financing activities	$	(264	)	$	(387	)

During the three months ended March 31, 2007, PG&E Corporation's consolidated net cash used in financing activities decreased by approximately $123 million, compared to the same period in 2006. The decrease in cash used after consideration of the Utility’s cash flows used in financing activities, was primarily due to $58 million paid for settlements related to the 2005 repurchase of common stock in the first three months of 2006, with no similar payments in 2007.

PG&E Corporation expects its $280 million of Convertible Subordinated Notes will remain outstanding until maturity in 2010.

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. In addition to those commitments disclosed in the 2006 Annual Report and those arising from normal business activities, PG&E Corporation and the Utility have commitments related to the Utility’s issuance of $700 million in Senior Notes due March 1, 2037. See Notes 4 and 11 in the Notes to the Condensed Consolidated Financial Statements and the 2006 Annual Report for further discussion.

CAPITAL EXPENDITURES

The Utility's investment in plant and equipment totaled approximately $2.4 billion in 2006, and the Utility expects capital expenditures will total approximately $3.2 billion in 2007. The Utility’s weighted average rate base in 2006 was $15.9 billion. Based on the estimated capital expenditures for 2007, the Utility projects a weighted average rate base for 2007 of approximately $17.0 billion. During the quarter ended March 31, 2007, the Utility spent capital costs of $40 million to install its SmartMeter^TMadvanced metering system, $22 million to replace the steam generators at the two nuclear

operating units at Diablo Canyon, and $5 million to invest in new generation facilities at the Gateway Generating Station, Colusa, and Humboldt Bay power plants. Over the next five years, the Utility estimates capital expenditures to average approximately $2.8 billion a year, reflecting the Utility’s expectation to replace aging infrastructure and otherwise invest in plant and equipment to accommodate anticipated electricity and natural gas load growth.

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 enable PG&E Corporation and the Utility to obtain financing or execute commercial transactions on more favorable terms. For further information related to letter of credit agreements, the credit facilities, and PG&E Corporation's guarantee related to certain National Energy & Gas Transmission indemnity obligations, see the 2006 Annual Report and Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements.

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 is exposed to a 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. This 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 the regional concentration of retail receivables is not considered likely.

Additionally, the Utility has a concentration of credit risk associated with its wholesale customers and 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 their contractual obligation to deliver electricity, then the Utility may find it necessary to procure electricity at current market prices, which may be higher than those prices contained in the contract. Credit losses attributable to receivables and electrical and gas procurement activities from wholesale customers and counterparties are expected to be recoverable from customers through rates and are not expected to have a material impact on earnings.

The Utility manages credit risk associated with its wholesale customers and counterparties, who have energy contracts containing appropriate credit and collateral provision, by assigning credit limits based on evaluations of their financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically 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 contractually specified limits.

The schedule below summarizes the Utility's net credit risk exposure to its wholesale customers and counterparties, 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, 2007 and December 31, 2006:

	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%
(in millions)
March 31, 2007	$	403	$	90	$	313		3	$	170
December 31, 2006	$	255	$	87	$	168		2	$	113


⁽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.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies that are discussed in Note 11 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

This section of MD&A discusses developments that have occurred in significant regulatory proceedings discussed in the 2006 Annual Report and significant new regulatory proceedings that have been initiated since the 2006 Annual Report was filed with the SEC.

2007 General Rate Case

On March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC. The decision sets the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010. Effective January 1, 2007, the Utility is authorized to collect revenue requirements of approximately $2.9 billion for electricity distribution (an increase of $222 million over the 2006 authorized amount), approximately $1 billion for natural gas distribution (an increase of $21 million over the 2006 authorized amount), and approximately $1 billion for electricity generation operations (a decrease of $30 million from the 2006 authorized amount). The total authorized amount of approximately $4.9 billion reflects an overall increase of $213 million, or 4.5%, over the total 2006 authorized amount.

The decision also authorizes annual increases, known as “attrition adjustments,” to the authorized revenue requirements in order to avoid a reduction in earnings due to, among other things, inflation and increases in invested capital. The decision authorizes attrition adjustments to authorized revenues of $125 million in each of 2008, 2009, and 2010. The decision also authorizes a one-time additional adjustment of $35 million in 2009 for the cost of a second refueling outage at the Utility’s Diablo Canyon nuclear power plant. The adjustment to authorized revenues for 2010 would be $125 million, less the one-time additional amount of $35 million from 2009, for a net increase of $90 million in 2010.

Additionally, the decision authorizes the Utility to recover the annual pension related revenue requirement attributable to the GRC lines of business through 2010. For 2007, 2008, 2009, and 2010 the Utility will make an annual net pension contribution of $153 million funded by the authorized revenue requirement attributable to the Utility’s GRC lines of business of $98 million, $102 million, $106 million, and $111 million, respectively.

Under the decision, the Utility’s next GRC will be effective January 1, 2011.

On April 20, 2007, The Utility Reform Network (“TURN”) and Aglet Consumer Alliance filed applications for rehearing of the CPUC’s decision. In its application, TURN asserts that the decision is unlawful because a number of findings in the decision are not supported by substantial evidence in light of the whole record, and specific outcomes represent an abuse of the CPUC’s discretion. In its application, Aglet Consumer Alliance argues that the evidentiary record does not justify the inclusion of approximately $36 million for certain capital expenditures. The Utility has filed a response to oppose the applications. The applications for rehearing do not stay the effectiveness of, or the Utility’s compliance with, the decision. It is uncertain when the CPUC will act on the applications.

2008 Cost of Capital Proceeding

On May 8, 2007, the Utility filed an application with the CPUC requesting the CPUC 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 rate base for 2008. In the cost of capital proceeding, the CPUC (1) establishes the proportions of common equity, preferred equity, and debt that will comprise the Utility's total authorized capital structure, (2) establishes the rate of return that the Utility is authorized to earn on the common equity, and (3) establishes the costs of preferred equity and debt components of its capital structure that the Utility will be authorized to earn. The following table compares the currently authorized amounts for 2007 and the requested amounts for 2008:

	2007 Authorized									2008 Requested
	Cost			Capital Structure			Weighted Cost			Cost			Capital Structure			Weighted Cost
Long-term debt		6.02	%		46.00	%		2.77	%		6.05	%		46.00	%		2.78	%
Preferred stock		5.87	%		2.00	%		0.12	%		5.68	%		2.00	%		0.11	%

Common equity			11.35	%			52.00	%			5.90	%			11.70	%			52.00	%			6.08	%
Return on rate base											8.79	%											8.97	%

The Utility's proposed cost of capital would increase the 2008 cost of capital revenue requirement by approximately $41 million over the currently authorized revenue requirement for electricity and natural gas distribution and electricity generation operations, based on the Utility's currently authorized rate base. The Utility has proposed that any changes to its revenue requirement resulting from adjustments to its authorized 2008 cost of capital be effective January 1, 2008. The Utility expects that the CPUC will issue a final decision on this proceeding by the end of 2007.

The Utility did not include a request for a 2008 rate of return for its electric transmission operations in this application to the CPUC because the FERC regulates electric transmission rates. Also, because the revenue requirements for the Utility’s gas transmission and storage operations will be determined in a separate CPUC proceeding, the Utility did not include a request for a 2008 rate of return for its gas transmission and storage operations. (See “Regulatory Matters - Natural Gas Transmission and Storage Rate Case” below.)

The Utility has proposed to replace the annual cost of capital proceedings with an annual cost of capital adjustment mechanism for the five year period 2009 to 2013. The mechanism would utilize an interest rate benchmark to trigger changes in the authorized rate of ROE, if the change in the benchmark interest rate is more than 75 basis points. If the change is more than 75 basis points, the rate of ROE would be adjusted by one-half the change in the benchmark interest rate. The costs of debt and preferred stock would be trued up to their recorded values in each year.

The December 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (the “Chapter 11 Settlement Agreement”) requires the CPUC to authorize a minimum ROE for the Utility of 11.22% until the Utility receives a credit rating of “A3” from Moody’s Investors Service or “A-” from Standard & Poor’s Ratings Service.

Rulemaking Proceeding to Modify QF Pricing and Policies

On April 24, 2007, a proposed decision was issued that, if adopted by the CPUC, would modify the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. If adopted, the proposed decision would affect those QFs who did not enter into a 2006 settlement agreement between the Utility and the Independent Energy Producers (on behalf of the settling QFs) to resolve these pricing issues (see 2006 Annual Report for discussion of the settlement agreement). Among other proposed changes, the proposed decision would modify the current formula for determining the utilities’ short-run avoided costs (“SRAC”) (i.e., the cost of energy, which, in the absence of a QF’s generation, the utilities would otherwise generate or purchase from another source) that is used to calculate the amount of energy payments to QFs. The proposed new SRAC formula would use a market index formula based on a day-ahead market price. Assuming this formula is adopted by the CPUC, the Utility anticipates its energy payments to the non-settling QFs would be reduced, depending on future market prices.

The proposed decision also would establish a “Prospective QF Program” for new QFs and QFs whose existing contracts will expire. Under this proposed program, there would be three alternative standard power purchase contract options available to QFs. A utility would execute a contract depending on whether it is consistent with the utility’s CPUC-approved long-term procurement plan. QFs also would continue to have the option to participate in the utilities’ generation resource solicitations or negotiate a bilateral agreement with a utility.

Comments on the proposed decision are due on May 14, 2007. The Utility expects that the CPUC will issue a final decision by the end of the second quarter of 2007.

PG&E Corporation and the Utility are unable to predict whether the CPUC will adopt the proposed decision. Any adjustments to QF prices would be reflected in customers’ rates.

Natural Gas Transmission and Storage Rate Case

On March 15, 2007, the Utility filed an application with the CPUC to request approval of a multi-party settlement agreement, known as the Gas Accord IV, to establish the Utility’s natural gas transmission and storage rates and associated revenue requirements and to retain the Gas Accord market structure for the period 2008-2010. The parties in support of the Gas Accord IV include the Utility and more than 30 other parties representing all segments of the natural gas industry in California, including the CPUC’s Division of Ratepayer Advocates.

The Gas Accord IV proposes a 2008 natural gas transmission and storage revenue requirement of $446 million (about 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (about 2.8% above the proposed 2008 revenue requirement), and a 2010 revenue requirement of $471 million (about 2.7% above the proposed 2009 revenue requirement). Under the Gas Accord IV, the Utility’s ability to fully recover authorized revenue requirements for its natural gas transmission and storage services would continue to depend on throughput volume and other factors.

The Gas Accord IV also proposes to continue the terms and conditions of natural gas transmission and storage services established under the original CPUC-approved Gas Accord settlement agreement implemented in 1998. The original Gas Accord separated the Utility’s natural gas transmission and storage services from the Utility's distribution services for ratemaking purposes. The original Gas Accord changed the terms of service and rate structure for natural gas transmission, allowing the Utility's core customers (i.e., residential and small commercial customers) greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers (i.e., industrial, larger commercial, and electric generation customers) purchase their natural gas from producers, marketers, and brokers, and purchase their preferred mix of transmission, storage, and distribution services from the Utility. Although they can select the gas suppliers of their choice, most core customers buy natural gas, as well as transmission and distribution services, from the Utility as a bundled service.

It is expected that the CPUC will issue a final decision with respect to the Gas Accord IV by the end of 2007. If the CPUC does not issue a final decision by the end of the year to approve new rates effective January 1, 2008, the rates and terms and conditions of service in effect as of December 31, 2007 will remain in effect, with an automatic 2% escalation in the rates as of January 1, 2008. PG&E Corporation and the Utility are unable to predict whether or when the CPUC will approve the proposed Gas Accord IV.

Energy Efficiency Rulemaking

In May 2007, the Utility filed testimony with the CPUC in the energy efficiency rulemaking proceeding in response to the assigned commissioner’s March 26, 2007 order to re-open the record and hold evidentiary hearings on limited issues. The evidentiary hearings will primarily address the appropriate benchmark and methodologies to be used in establishing mechanisms to reward or penalize the investor-owned utilities depending on the extent to which the utilities successfully implement their 2006-2008 energy efficiency programs and meet the CPUC’s targets for reducing customers’ demand for electricity and natural gas. In a new development, a new party, the California Large Energy Consumers Association representing industrial customers, filed testimony supporting TURN’s proposed mechanism.

Under the mechanisms proposed by the utilities, the benchmark to establish the level of potential incentive earnings would be supply-side comparability, i.e., a level of incentives based on the earnings that could be expected from investment in new power and transmission projects. Under the Utility’s proposed incentive mechanism, if the Utility achieved 80% to 100% of the CPUC’s demand reduction targets, 80% of the net present value of energy efficiency programs (i.e., the net benefits) would accrue to customers and 20% of the net benefits would accrue to shareholders. If the Utility achieves savings in excess of 100% of the CPUC’s targets, the Utility’s shareholders would receive 30% of the additional net benefits attributable to the portion of demand reduction that exceeds 100% of the CPUC’s targets and the Utility’s customers would receive the remaining 70%. The Utility would not receive any additional incentive earnings for achieving more than 110% of the CPUC’s target. Under this proposal, if the Utility achieved savings at 80% of the CPUC’s targets, the cumulative amount of potential pre-tax incentive earnings covering the three-year period would be approximately $141.2 million. If the Utility achieved savings at 100% of the CPUC’s targets, the cumulative amount of potential pre-tax incentive earnings covering the three-year period would be approximately $222.5 million. If the Utility achieved savings at 110% or more of the CPUC’s targets, the cumulative amount of potential pre-tax incentive earnings covering the three-year period would be a maximum of approximately $283.4 million.

Other parties have proposed that the utilities begin earning incentives only when a utility achieves between 85% and 100% of the CPUC’s energy savings targets set for that utility. Under the non-utility proposals, incentive earnings range from only 1.5% to 6% of the net benefits, if the utilities achieved 100% of their savings target. Of the various proposals submitted, TURN proposes a mechanism that would result in the lowest earnings. TURN proposes that the utilities receive 2% of the net benefits only if they achieved 100% of their savings target. The utilities would not receive any rewards for achieving savings below 100% of the target. Under TURN’s proposal, if the Utility achieves 100% of the CPUC’s savings targets, the Utility would receive $21 million in cumulative pre-tax incentive earnings covering the three-year period. TURN would allow the utilities to retain 2.5% of the net benefits if they achieved 120% of their target.

All parties have proposed penalties for poor performance in achieving the CPUC’s targets. The Utility has proposed that if it achieves less than 40% of the CPUC’s targets, the Utility would provide customers any shortfall between the

revenues received in rates for energy efficiency and benefits obtained through the energy efficiency programs. Other parties have proposed that penalties be imposed if the utilities achieve less than 50% to less than 85% of the CPUC’s targets. TURN has proposed that penalties would be incurred if the utilities failed to achieve 85% of the CPUC’s targets.

Depending upon the ratemaking method adopted by the CPUC, actual shareholder incentives or penalties may not be realized for several years. The Utility has proposed a process for earnings assessments and progress payments whereby 75% of earnings payments would be made in 2008 (for 2006 program activities), 75% in 2009 (for 2007 program activities) and 75% in 2010 (for 2008 program activities), with a final “true-up” relating to the remainder of payments that would also begin in 2010.

It is anticipated that the CPUC will issue a final decision on the adoption of a shareholder incentive and penalty mechanism in the second half of 2007.

PG&E Corporation and the Utility are unable to predict what incentive and penalty mechanism the CPUC may adopt and what impact the adopted mechanism may have on their financial condition and results of operations.

Potential Rulemaking Proceeding to Re-establish Direct Access

As previously disclosed, a petition was filed in December 2006 asking the CPUC to examine re-establishing the ability of the Utility's customers to become direct access customers by purchasing electricity from alternate energy providers by January 1, 2008. On April 24, 2007, the CPUC Commissioner assigned to the petition issued a proposed decision which, if adopted by the CPUC, would grant the petition and open a rulemaking proceeding to consider how, whether and when direct access should be re-established. The proposed decision states that any reinstituted direct access program must be conditioned on first implementing the necessary regulatory and market conditions to ensure reliable sources of long-term electric capacity at stable prices as well as fair and nondiscriminatory regulatory and ratemaking conditions to ensure that direct access customers pay their fair share of costs. The proposed decision states that given the extent and complexity of the issues to be resolved, including whether the CPUC has the legal authority to re-establish direct access before the DWR’s power purchase contracts have expired, it is unrealistic to adopt the petition’s proposed schedule. The proposed decision’s schedule anticipates the issuance of a final decision by the end of 2008 or early 2009.

PG&E Corporation and the Utility are unable to predict how any new rules that may be adopted by the CPUC relating to the availability of direct access will affect their financial condition or results of operations.

Catastrophic Event Memorandum Account Application

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk and interest rate risk. For a comprehensive discussion of PG&E Corporation’s market risk, see the “Risk Management Activities” section of the MD&A in the 2006 Annual Report. The following disclosures omit certain information that has not changed since the 2006 Annual Report was filed with the SEC.

Price Risk

Natural Gas Transportation and Storage

The Utility uses value-at-risk to measure the shareholder'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. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

The Utility's value-at-risk calculated under the methodology described above was approximately $23 million and $26 million at March 31, 2007 and December 31, 2006, respectively. The Utility's high, low, and average value-at-risk during the three months ended March 31, 2007 and for the year ended December 31, 2006 were approximately $28 million, $21 million, and $24 million, and $41 million, $22 million, and $33 million, respectively.

Convertible Subordinated Notes

At March 31, 2007, PG&E Corporation had outstanding $280 million of Convertible Subordinated Notes that mature on June 30, 2010. Holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying 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 common stock dividends paid on January 15 and April 15, 2007, PG&E Corporation paid approximately $6 million and $7 million, respectively, of "pass through dividends" to the holders of Convertible Subordinated Notes.

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” the dividend participation rights component of the Convertible Subordinated Notes 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, Net). At March 31, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $76 million and $79 million, respectively, of which $24 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $52 million and $56 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabilities - Other).

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, 2007, 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 2006 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, 2007, 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

See Note 2 of the Notes to the Condensed Consolidated Financial Statements for further discussion.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Condensed Consolidated Financial Statements for further discussion.

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 $518 million at March 31, 2007 and approximately $511 million at December 31, 2006.

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 Noncurrent Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately $65 million at March 31, 2007 and $74 million at December 31, 2006.

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 (“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, 2007, 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 (“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.

There were no changes in internal controls over financial reporting that occurred during the quarter ended March 31, 2007 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

Diablo Canyon Power Plant

For information regarding matters relating to the Diablo Canyon Power Plant, see “Part I, Item 3: Legal Proceedings” in the 2006 Annual Report.

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

For more information regarding these cases, see “Part I, Item 3: Legal Proceedings” in the 2006 Annual Report.

The California Air Resources Board

As disclosed in “Part I, Item 3: Legal Proceedings” in the 2006 Annual Report, the California Air Resources Board (“CARB”) oversees the Periodic Smoke Inspection Program to test and repair heavy-duty diesel vehicles in order to ensure efficient operations and reduce particulate matter emissions. The program applies to approximately 2,000 vehicles owned by the Utility. In July 2006, the CARB requested the Utility's program compliance records. The Utility discovered that its records were incomplete and that some records could not be located. The Utility immediately notified the CARB and began the evaluation and implementation of process improvements to ensure accurate recordkeeping. The CARB is authorized to assess penalties of up to $500 per missing or incomplete record.

In May, 2007, the Utility reached a settlement with the CARB under which the Utility has agreed to pay a penalty of $220,000.

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 2006 Annual Report. There have been no material changes in the risks related to an investment in PG&E Corporation’s or the Utility’s securities that have been disclosed in the 2006 Annual Report. In addition, the section of this report entitled “Forward-Looking Statements” appearing in Part I, Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations, lists some of the factors that could affect PG&E Corporation’s and the Utility’s future results of operations and financial condition. Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, the listed factors and the risks discussed in the 2006 Annual Report could cause actual results to differ materially from the results expected or anticipated by management as expressed or implied by the forward-looking statements made in the 2006 Annual Report and in this 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, 2007, the period covered by this report.

PG&E Corporation did not repurchase any shares of its common stock during the first quarter of 2007. Pacific Gas and Electric Company did not redeem or repurchase any shares of its various series of preferred stock outstanding during the first quarter of 2007.

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

PG&E Corporation:

On April 18, 2007, 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	260,751,930	4,247,555
Leslie S. Biller	260,760,202	4,239,283
David A. Coulter	256,725,119	8,274,366
C. Lee Cox	258,170,043	6,829,442
Peter A. Darbee	258,317,210	6,682,275
Maryellen C. Herringer	260,445,415	4,554,070
Richard A. Meserve	260,760,904	4,238,581
Mary S. Metz	258,563,150	6,436,335
Barbara L. Rambo	260,266,351	4,733,134
Barry Lawson Williams	256,538,958	8,460,527

2. Ratification of the appointment of Deloitte & Touche LLP as the independent registered public accounting firm for the year 2007 (included as Item 2 in the proxy statement):

For:	259,134,050
Against:	3,097,737
Abstain:	2,767,698

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 performance-based stock options (included as Item 3 in the proxy statement):

For:	21,779,877
Against:	202,209,800
Abstain:	4,324,461
Broker non-vote ⁽¹⁾:	36,685,347

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 cumulative voting (included as Item 4 in the proxy statement):

For:	109,526,673
Against:	114,256,122
Abstain:	4,531,343
Broker non-vote ⁽¹⁾:	36,685,347

⁽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 18, 2007, the Utility held its annual meeting of shareholders. Shares of capital stock of the Utility 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 2007 joint

proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2007. 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	268,104,918	87,485
Leslie S. Biller	268,109,326	83,077
David A. Coulter	267,953,519	238,884
C. Lee Cox	268,105,364	87,039
Peter A. Darbee	268,108,298	84,105
Maryellen C. Herringer	268,107,116	85,287
Thomas B. King	268,108,807	83,596
Richard A. Meserve	268,097,444	94,959
Mary S. Metz	268,094,608	97,795
Barbara L. Rambo	268,106,286	86,117
Barry Lawson Williams	268,096,595	95,808

2. Ratification of the appointment of Deloitte & Touche LLP as the independent registered public accounting firm for the year 2007 (included as Item 2 in the proxy statement):

For:	268,086,501
Against:	47,535
Abstain:	58,367

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, 2007 was 2.85. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2007 was 2.81. 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

3.1	Bylaws of PG&E Corporation amended as of April 18, 2007 (incorporated by reference from PG&E Corporation’s Current Report on Form 8-K dated April 20, 2007, Exhibit 99.1)

3.2	Bylaws of Pacific Gas and Electric Company amended as of April 18, 2007 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 20, 2007, Exhibit 99.2)

4.1	First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007, Exhibit 4.1)

10.1	Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007

10.2	Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007

10.3*	Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007

10.4*	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007

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

*Management contract or compensatory agreement
**Pursuant to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished rather than filed with this report.

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

Vice President and Controller

(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

G. Robert Powell

Vice President and Controller

(duly authorized officer and principal accounting officer)

Dated: May 10, 2007

EXHIBIT INDEX

3.1	Bylaws of PG&E Corporation amended as of April 18, 2007 (incorporated by reference from PG&E Corporation’s Current Report on Form 8-K dated April 20, 2007, Exhibit 99.1)

3.2	Bylaws of Pacific Gas and Electric Company amended as of April 18, 2007 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 20, 2007, Exhibit 99.2)

4.1	First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007, Exhibit 4.1)

10.1	Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007

10.2	Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007

10.3*	Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007

10.4*	Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007

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

*Management contract or compensatory agreement
**Pursuant to Item 601(b) (32) of SEC Regulation S-K, these Exhibits are furnished rather than filed with this report.