q207_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 June 30, 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 August 6, 2007:

PG&E Corporation				353,357,915 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 JUNE 30, 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	22
	NOTE 8:		Related Party Agreements and Transactions	22
	NOTE 9:		Resolution of Remaining Chapter 11 Disputed Generator Claims	23
	NOTE 10:		Commitments and Contingencies	24

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			31
	Forward-Looking Statements			33
	Results of Operations			35
	Liquidity and Financial Resources			41
	Contractual Commitments			45
	Capital Expenditures			45
	Off-Balance Sheet Arrangements			46
	Contingencies			47
	Regulatory Matters			47
	Risk Management Activities			51
	Critical Accounting Policies			53
	New Accounting Policies			54
	Accounting Pronouncements Issued But Not Yet Adopted			54
	Environmental and Legal Matters			54

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			54
ITEM 4.	CONTROLS AND PROCEDURES			54

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			55

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			55
ITEM 5.	OTHER INFORMATION			55
ITEM 6.	EXHIBITS			55
SIGNATURES				56

PART I. FINANCIAL INFORMATION

ITEM 1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended						Six Months Ended
(in millions, except per share amounts)	June 30,						June 30,
	2007			2006			2007			2006
Operating Revenues
Electric	$	2,359		$	2,214		$	4,534		$	4,077
Natural gas		828			803			2,009			2,088
Total operating revenues		3,187			3,017			6,543			6,165
Operating Expenses
Cost of electricity		884			781			1,607			1,311
Cost of natural gas		396			368			1,150			1,241
Operating and maintenance		922			982			1,842			1,844
Depreciation, amortization, and decommissioning		430			421			860			835
Total operating expenses		2,632			2,552			5,459			5,231
Operating Income		555			465			1,084			934
Interest income		37			41			89			64
Interest expense		(185	)		(164	)		(375	)		(318	)
Other income, net		10			28			14			28
Income Before Income Taxes		417			370			812			708
Income tax provision		148			138			287			262
Net Income	$	269		$	232		$	525		$	446
Weighted Average Common Shares Outstanding, Basic		350			346			350			345
Net Earnings Per Common Share, Basic	$	0.75		$	0.65		$	1.46		$	1.26
Net Earnings Per Common Share, Diluted	$	0.74		$	0.65		$	1.45		$	1.25
Dividends Declared Per Common Share	$	0.36		$	0.33		$	0.72		$	0.66

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	June 30, 2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	366		$	456
Restricted cash		1,428			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $47 million in 2007 and $50 million in 2006)		2,201			2,343
Regulatory balancing accounts		886			607
Inventories:
Gas stored underground and fuel oil		191			181
Materials and supplies		161			149
Income taxes receivable		175			-
Prepaid expenses and other		435			716
Total current assets		5,843			5,867
Property, Plant, and Equipment
Electric		24,687			24,036
Gas		9,277			9,115
Construction work in progress		1,288			1,047
Other		16			16
Total property, plant, and equipment		35,268			34,214
Accumulated depreciation		(12,726	)		(12,429	)
Net property, plant, and equipment		22,542			21,785
Other Noncurrent Assets
Regulatory assets		4,626			4,902
Nuclear decommissioning funds		1,934			1,876
Other		488			373
Total other noncurrent assets		7,048			7,151
TOTAL ASSETS	$	35,433		$	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)	June 30, 2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	575		$	759
Long-term debt, classified as current		-			281
Rate reduction bonds, classified as current		147			290
Energy recovery bonds, classified as current		345			340
Accounts payable:
Trade creditors		822			1,075
Disputed claims and customer refunds		1,648			1,709
Regulatory balancing accounts		747			1,030
Other		429			420
Interest payable		638			583
Income taxes payable		-			102
Deferred income taxes		208			148
Other		1,391			1,513
Total current liabilities		6,950			8,250
Noncurrent Liabilities
Long-term debt		7,673			6,697
Energy recovery bonds		1,771			1,936
Regulatory liabilities		3,862			3,392
Asset retirement obligations		1,502			1,466
Income taxes payable		231			-
Deferred income taxes		2,889			2,840
Deferred tax credits		103			106
Other		2,004			2,053
Total noncurrent liabilities		20,035			18,490
Commitments and Contingencies (Notes 2, 4, 5, 9, and 10)
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 374,136,073 common and 1,283,877 restricted shares in 2007 and issued 372,803,521 common and 1,377,538 restricted shares in 2006		5,999			5,877
Common stock held by subsidiary, at cost, 24,665,500 shares		(718	)		(718	)
Reinvested earnings		2,925			2,671
Accumulated other comprehensive loss		(10	)		(19	)
Total common shareholders' equity		8,196			7,811
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	35,433		$	34,803

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Six Months Ended
(in millions)	June 30,
	2007			2006
Cash Flows From Operating Activities
Net income	$	525		$	446
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction		914			868
Deferred income taxes and tax credits, net		102			69
Other deferred charges and noncurrent liabilities		130			155
Gain on sale of assets		(1	)		(15	)
Net effect of changes in operating assets and liabilities:
Accounts receivable		142			373
Inventories		(22	)		60
Accounts payable		(214	)		(232	)
Accrued taxes and income taxes receivable		(61	)		(79	)
Regulatory balancing accounts, net		(483	)		18
Other current assets		273			(56	)
Other current liabilities		(46	)		(103	)
Other		(23	)		36
Net cash provided by operating activities		1,236			1,540
Cash Flows From Investing Activities
Capital expenditures		(1,320	)		(1,178	)
Net proceeds from sale of assets		8			7
Decrease (increase) in restricted cash		(13	)		48
Proceeds from nuclear decommissioning trust sales		548			757
Purchases of nuclear decommissioning trust investments		(606	)		(799	)
Net cash used in investing activities		(1,383	)		(1,165	)
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 issuance of commercial paper, net of $2 million discount in 2007		109			213
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(143	)		(141	)
Energy recovery bonds matured		(160	)		(130	)
Common stock issued		89			77
Common stock repurchased		-			(114	)
Common stock dividends paid		(242	)		(228	)
Other		14			(84	)
Net cash provided by (used in) financing activities		57			(667	)
Net change in cash and cash equivalents		(90	)		(292	)
Cash and cash equivalents at January 1		456			713
Cash and cash equivalents at June 30	$	366		$	421
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	239		$	270
Income taxes paid, net		282			247
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	128		$	115

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended						Six Months Ended
(in millions)	June 30,						June 30,
	2007			2006			2007			2006
Operating Revenues
Electric	$	2,359		$	2,214		$	4,534		$	4,077
Natural gas		828			803			2,009			2,088
Total operating revenues		3,187			3,017			6,543			6,165
Operating Expenses
Cost of electricity		884			781			1,607			1,311
Cost of natural gas		396			368			1,150			1,241
Operating and maintenance		921			982			1,840			1,844
Depreciation, amortization, and decommissioning		430			421			859			834
Total operating expenses		2,631			2,552			5,456			5,230
Operating Income		556			465			1,087			935
Interest income		35			39			83			58
Interest expense		(178	)		(157	)		(360	)		(303	)
Other income, net		15			25			24			31
Income Before Income Taxes		428			372			834			721
Income tax provision		154			141			299			273
Net Income		274			231			535			448
Preferred stock dividend requirement		4			4			7			7
Income Available for Common Stock	$	270		$	227		$	528		$	441

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	June 30, 2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	78		$	70
Restricted cash		1,428			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $47 million in 2007 and $50 million in 2006)		2,201			2,343
Related parties		5			6
Regulatory balancing accounts		886			607
Inventories:
Gas stored underground and fuel oil		191			181
Materials and supplies		161			149
Income taxes receivable		127			20
Prepaid expenses and other		433			714
Total current assets		5,510			5,505
Property, Plant, and Equipment
Electric		24,687			24,036
Gas		9,277			9,115
Construction work in progress		1,288			1,047
Total property, plant, and equipment		35,252			34,198
Accumulated depreciation		(12,711	)		(12,415	)
Net property, plant, and equipment		22,541			21,783
Other Noncurrent Assets
Regulatory assets		4,626			4,902
Nuclear decommissioning funds		1,934			1,876
Related parties receivable		25			25
Other		389			280
Total other noncurrent assets		6,974			7,083
TOTAL ASSETS	$	35,025		$	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)	June 30, 2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	575		$	759
Long-term debt, classified as current		-			1
Rate reduction bonds, classified as current		147			290
Energy recovery bonds, classified as current		345			340
Accounts payable:
Trade creditors		822			1,075
Disputed claims and customer refunds		1,648			1,709
Related parties		30			40
Regulatory balancing accounts		747			1,030
Other		412			402
Interest payable		625			570
Deferred income taxes		212			118
Other		1,224			1,346
Total current liabilities		6,787			7,680
Noncurrent Liabilities
Long-term debt		7,393			6,697
Energy recovery bonds		1,771			1,936
Regulatory liabilities		3,862			3,392
Asset retirement obligations		1,502			1,466
Income taxes payable		100			-
Deferred income taxes		2,950			2,972
Deferred tax credits		103			106
Other		1,879			1,922
Total noncurrent liabilities		19,560			18,491
Commitments and Contingencies (Notes 2, 4, 5, 9 and 10)
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		2,036			1,822
Reinvested earnings		5,467			5,213
Accumulated other comprehensive loss		(6	)		(16	)
Total shareholders' equity		8,678			8,200
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	35,025		$	34,371

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Six Months Ended
(in millions)	June 30,
	2007			2006
Cash Flows From Operating Activities
Net income	$	535		$	448
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction		913			867
Deferred income taxes and tax credits, net		101			73
Other deferred charges and noncurrent liabilities		129			153
Gain on sale of assets		(1	)		(15	)
Net effect of changes in operating assets and liabilities:
Accounts receivable		143			373
Inventories		(22	)		60
Accounts payable		(221	)		(233	)
Accrued taxes and income taxes receivable		(59	)		(110	)
Regulatory balancing accounts, net		(483	)		18
Other current assets		271			(52	)
Other current liabilities		(48	)		(70	)
Other		(23	)		(2	)
Net cash provided by operating activities		1,235			1,510
Cash Flows From Investing Activities
Capital expenditures		(1,320	)		(1,178	)
Net proceeds from sale of assets		8			7
Decrease (increase) in restricted cash		(13	)		48
Proceeds from nuclear decommissioning trust sales		548			757
Purchases of nuclear decommissioning trust investments		(606	)		(799	)
Net cash used in investing activities		(1,383	)		(1,165	)
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 issuance of commercial paper, net of $2 million discount in 2007		109			213
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(143	)		(141	)
Energy recovery bonds matured		(160	)		(130	)
Common stock dividends paid		(254	)		(230	)
Preferred stock dividends paid		(7	)		(7	)
Equity infusion from PG&E Corporation		200			-
Other		21			(88	)
Net cash provided by (used in) financing activities		156			(643	)
Net change in cash and cash equivalents		8			(298	)
Cash and cash equivalents at January 1		70			463
Cash and cash equivalents at June 30	$	78		$	165
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	226		$	243
Income taxes paid, net		299			308

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 Note 2 of 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 long-lived assets and certain identifiable intangibles held and used in operations for impairment 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

On January 1, 2007, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). 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 based on the merits of the position. 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% 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.

The effects of adopting FIN 48 were 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 through January 1, 2007		52		21

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)
Three Months Ended June 30, 2007
Interest expense accrued on unrecognized tax benefits	$	6	$	2
Six Months Ended June 30, 2007
Interest expense accrued on unrecognized tax benefits	$	11	$	5

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 10 below.

Share-Based Compensation

On January 1, 2006, PG&E Corporation and the Utility adopted the provisions of Statement of Financial Accounting Standards (“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 and six months ended June 30, 2007 and 2006:

	PG&E Corporation				Utility
	Three Months Ended June 30,				Three Months Ended June 30,
(in millions)	2007		2006		2007		2006

Stock options	$	2	$	3	$	1	$	2
Restricted stock		5		3		3		2
Performance shares		6		6		4		4
Total compensation expense (pre-tax)	$	13	$	12	$	8	$	8

Total compensation expense (after-tax)

	PG&E Corporation				Utility
	Six Months Ended June 30,				Six Months Ended June 30,
(in millions)	2007		2006		2007			2006

Stock options	$	4	$	6	$	2		$	4
Restricted stock		13		11		8			8
Performance shares		-		21		(1	)		15
Total compensation expense (pre-tax)	$	17	$	38	$	9		$	27
Total compensation expense (after-tax)	$	10	$	23	$	5		$	16

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 and six months ended June 30, 2007 and 2006 are as follows:

(in millions)	Pension Benefits Three Months Ended June 30,						Other Benefits Three Months Ended June 30,
	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 ⁽¹⁾		-			-			6			6
Amortization of prior service cost ⁽¹⁾		12			14			4			4
Amortization of unrecognized (gain) loss ⁽¹⁾		-			8			(3	)		-
Net periodic benefit cost	$	29		$	54		$	10		$	14


⁽¹⁾ In 2007, under SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”), PG&E Corporation and the Utility recorded amounts related to other benefits in other comprehensive income, net of related deferred taxes. Other comprehensive income does not include amortization of the amounts related to defined benefit pension plan, which are recorded to the existing pension regulatory liability in accordance with the provisions of “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”).

(in millions)	Pension Benefits Six Months Ended June 30,						Other Benefits Six Months Ended June 30,
	2007			2006			2007			2006

Service cost for benefits earned	$	118		$	119		$	14		$	17
Interest cost		270			260			40			37
Expected return on plan assets		(354	)		(315	)		(48	)		(46	)
Amortization of transition obligation ⁽¹⁾		-			-			12			13
Amortization of prior service cost ⁽¹⁾		24			27			8			8
Amortization of unrecognized (gain) loss ⁽¹⁾		-			17			(6	)		(2	)

Net periodic benefit cost	$	58	$	108	$	20	$	27


⁽¹⁾ In 2007, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to other benefits in other comprehensive income, net of related deferred taxes. Other comprehensive income does not include amortization of the amounts related to defined benefit pension plan, which are recorded to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71.

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

Under 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 GAAP 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 for other benefits 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 currently, 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
	June 30,		December 31,
	2007		2006
(in millions)
Energy recovery bond regulatory asset	$	2,012	$	2,170
Utility retained generation regulatory assets		982		1,018
Regulatory assets for deferred income tax		665		599
Environmental compliance costs		299		303
Unamortized loss, net of gain, on reacquired debt		282		295
Regulatory assets associated with plan of reorganization		124		147
Scheduling coordinator costs		112		136
Post-transition period contract termination costs		103		120
Other		47		114
Total regulatory assets	$	4,626	$	4,902

The energy recovery bond (“ERB”) regulatory asset represents the 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 six months ended June 30, 2007, the Utility recorded amortization of the ERB regulatory asset of approximately $158 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 six months ended June 30, 2007, the Utility recorded amortization of the Utility’s retained generation regulatory assets of approximately $36 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 taxes 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 19 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.

The regulatory asset related to scheduling coordinator (“SC”) costs represents 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.

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.

As of June 30, 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 June 30, 2007 and December 31, 2006, the Utility had current regulatory assets of approximately $244 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 six months ended June 30, 2007, the Utility recorded amortization of the RRB regulatory asset of approximately $124 million. Price risk management regulatory assets consist of contracts with terms of less than one year to procure electricity and natural gas in order to reduce commodity price risks that 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 rates. 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
	June 30,		December 31,
	2007		2006
(in millions)
Cost of removal obligation	$	2,451	$	2,340
Asset retirement costs		604		608
Public purpose programs		290		169
Price risk management		123		37
California Solar Initiative		105		-
Employee benefit plans		70		23
Other		219		215
Total regulatory liabilities	$	3,862	$	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 consist of contracts with terms in excess of one year to procure electricity and natural gas in order to reduce commodity price risks that are accounted for as derivative instruments under SFAS No. 133. The costs and proceeds of these derivatives are recovered or refunded in regulated rates charged to customers.

California Solar Initiative liabilities represent revenues designated for public purpose program costs that are expected to be incurred in the future. These revenues will be used by the Utility to promote the use of solar energy in existing residential homes and existing and new commercial, industrial, and agricultural properties.

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.

As of June 30, 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 that 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 June 30, 2007 and December 31, 2006, the Utility had current regulatory liabilities of approximately $310 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
	June 30,			December 31,
	2007			2006
(in millions)
Electricity revenue and cost balancing accounts		$	773		$	501
Natural gas revenue and cost balancing accounts			113			106
Total		$	886		$	607

Regulatory Balancing Account Liabilities

	Balance At
	June 30,			December 31,
	2007			2006
(in millions)
Electricity revenue and cost balancing accounts		$	668		$	951
Natural gas revenue and cost balancing accounts			79			79
Total		$	747		$	1,030

During the six months ended June 30, 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 six months ended June 30, 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 ordered in the 2007 Annual Electric True-Up proceeding to reduce such over-collection.

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 June 30, 2007, neither were outstanding.

Convertible Subordinated Notes

At June 30, 2007, PG&E Corporation had outstanding $280 million of 9.5% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. Interest is payable semi-annually in arrears on June 30 and December 31. 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, April 15, and July 15, 2007, PG&E Corporation paid approximately $19 million of "pass-through dividends" to the holders of Convertible Subordinated Notes. Since no holders of the Convertible Subordinated Notes exercised the one-time right to require PG&E Corporation to repurchase the Convertible Subordinated Notes on June 30, 2007, PG&E Corporation has classified the Convertible Subordinated Notes as a noncurrent liability (in Noncurrent Liabilities - Long-Term Debt) in the accompanying Condensed Consolidated Balance Sheets as of June 30, 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. Dividend participation rights are recognized as financing cash flows on PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. 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 June 30, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $72 million and $79 million, respectively, of which $25 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $47 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 and provide materials to projects 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 10 below for a discussion of capital lease obligations related to certain contracts to purchase power from qualifying 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 June 30, 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 as described below. Letters of credit issued 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 June 30, 2007, there were no loans outstanding and approximately $174 million of letters of credit outstanding under the working capital facility.

Accounts Receivable Facility

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

On June 28, 2007, the Utility increased its borrowing capacity under the commercial paper program from $1 billion to $1.75 billion. Commercial paper borrowings are used primarily to cover fluctuations in cash flow requirements. These borrowings are supported by available capacity under the working capital facility described above. The commercial paper may have maturities up to 365 days and ranks equally with the Utility’s other unsubordinated and unsecured indebtedness. At June 30, 2007, the Utility had $577 million, including amortization of a $2 million discount, of commercial paper outstanding at an average yield of approximately 5.45%.

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 June 30, 2007 was approximately $147 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 June 30, 2007 was approximately $2.1 billion. The ERBs are scheduled to mature on December 25, 2012.

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 six months ended June 30, 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		525			535
Common stock issued		89			-
Common restricted stock amortization		13			-
Common stock dividends declared and paid		(126	)		(254	)
Common stock dividends declared but not yet paid		(127	)		-
Preferred stock dividends		-			(7	)
Tax benefit from share-based payment awards		20			15
Other comprehensive income		9			10
Equity infusion		-			200
Balance at June 30, 2007	$	8,196		$	8,678

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

Dividends

During the six months ended June 30, 2007, the Utility paid common stock dividends totaling $273 million, including $254 million of common stock dividends paid to PG&E Corporation and $19 million of common stock dividends paid to PG&E Holdings, LLC, a wholly owned subsidiary of the Utility.

On January 15, 2007, PG&E Corporation paid common stock dividends of $0.33 per share. On April 15 and July 15, 2007, PG&E Corporation paid common stock dividends of $0.36 per share. The above dividend payments totaled $393 million, including $26 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 and May 15, 2007, the Utility paid a cash dividend on various series of its preferred stock outstanding in the aggregate amount of $7 million. On June 20, 2007, the Board of Directors of the Utility declared a cash dividend on various series of its preferred stock payable on August 15, 2007 to shareholders of record on July 31, 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. 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 are assumed to be used to purchase common shares at the average market price during the reported period. The incremental shares (the difference between the number of shares assumed issued upon exercise and the number of shares assumed purchased) must be included in the number of weighted average common shares used for the calculation of diluted EPS.

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

	Three Months Ended				Six Months Ended
(in millions, except per share amounts)	June 30,				June 30,
	2007		2006		2007		2006

Net income	$	269	$	232	$	525	$	446
Less: distributed earnings to common shareholders		127		115		253		229
Undistributed earnings	$	142	$	117	$	272	$	217

Common shareholders earnings
*Basic*
Distributed earnings to common shareholders	$	127	$	115	$	253	$	229
Undistributed earnings allocated to common shareholders		135		111		258		206
Total common shareholders earnings, basic	$	262	$	226	$	511	$	435
*Diluted*
Distributed earnings to common shareholders	$	127	$	115	$	253	$	229
Undistributed earnings allocated to common shareholders		135		111		258		206
Total common shareholders earnings, diluted	$	262	$	226	$	511	$	435

Weighted average common shares outstanding, basic		350		346		350		345
9.50% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and participating securities, basic		369		365		369		364

Weighted average common shares outstanding, basic		350		346		350		345
Employee share-based compensation and accelerated share repurchase program ⁽¹⁾		2		3		2		4
Weighted average common shares outstanding, diluted		352		349		352		349
9.50% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and participating securities, diluted		371		368		371		368

Net earnings per common share, basic
Distributed earnings, basic ⁽²⁾	$	0.36	$	0.33	$	0.72	$	0.66
Undistributed earnings, basic		0.39		0.32		0.74		0.60
Total	$	0.75	$	0.65	$	1.46	$	1.26

Net earnings per common share, diluted
Distributed earnings, diluted	$	0.36	$	0.33	$	0.72	$	0.66
Undistributed earnings, diluted		0.38		0.32		0.73		0.59
Total	$	0.74	$	0.65	$	1.45	$	1.25


⁽¹⁾ Includes approximately 1 and 2 million shares of PG&E Corporation common stock treated as outstanding in connection with accelerated share repurchases for the three and six months ended June 30, 2006, respectively. The remaining shares relate to share-based compensation and are deemed to be outstanding per SFAS No. 128 for the purpose of calculating EPS.
⁽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 4,650 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the six months ended June 30, 2006 because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock over this period. All outstanding options to purchase PG&E Corporation common stock were included in the computation of diluted EPS for all other periods shown in the table above because the exercise prices of these options were lower 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 (see table below). 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 assets and liabilities associated with the Utility’s electricity and gas procurement activities appear as follows:

	Derivatives				Cash Flow Hedges
	June 30, 2007		December 31, 2006		June 30, 2007		December 31, 2006
(in millions)
Current Assets – Prepaid expenses and other	$	34	$	16	$	6	$	3
Other Noncurrent Assets – Other		123		37		40		8
Current Liabilities – Other		141		192		8		25
Noncurrent Liabilities – Other		25		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 cost of electricity and cost of natural gas as incurred.

Net realized gains or losses on derivative instruments are included in various items on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income, including cost of electricity and cost of natural gas. Cash inflows and outflows associated with the settlement of price risk management activities are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The dividend participation rights associated with PG&E Corporation's Convertible Subordinated Notes are recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 133. See Note 4 above for discussion of the Convertible Subordinated Notes.

NOTE 8: 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 are priced at their fully loaded costs (i.e., direct costs and allocations of overhead costs). 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				Six Months Ended				Receivable (Payable) Balance Outstanding at
(in millions)	June 30,				June 30,				June 30,			December 31,
	2007		2006		2007		2006		2007			2006
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1	$	2	$	2	$	-		$	2
Utility employee benefit assets due from PG&E Corporation		-		-		-		-		30			25
Interest from PG&E Corporation on employee benefit assets		1		1		1		1		-			-
Utility expenses from:
Administrative services received from PG&E Corporation	$	28	$	9	$	52	$	48	$	(30	)	$	(40	)
Utility employee benefit assets due to PG&E Corporation		1		1		2		2		-			-

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED GENERATOR CLAIMS

In connection with the Utility’s reorganization under Chapter 11 of the U.S. Bankruptcy Code on April 12, 2004, the Utility deposited approximately $1.7 billion into escrow for the payment of certain disputed claims that had been made by generators and power suppliers for transactions that occurred during the 2000-2001 California energy crisis. The disputed claims are being addressed in various FERC and judicial proceedings seeking refunds on behalf of California electricity purchasers (including the State of California and the Utility) from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the California Independent System Operator (“CAISO”) and the Power Exchange (“PX”) wholesale electricity markets between May 2000 and June 2001. 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 U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) retains jurisdiction over the Utility’s escrowed funds. (In addition, the 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.)

The Utility has entered into a number of settlements with various electricity suppliers resolving some of these disputed claims and the Utility's refund claims against these electricity suppliers. The Bankruptcy Court has approved the release of $0.6 billion from escrow in connection with these settlements. Through June 30, 2007, the Utility has received consideration of approximately $1.1 billion under these settlements through cash proceeds, reductions to the Utility's PX liability, and the transfer of the Gateway Generating Station, a partially constructed generating facility formerly owned by Mirant Corporation. 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 refund offset and interest issues being considered by the FERC.

The Utility received approximately $79 million (including interest) in cash-equivalent reductions to the Utility’s PX liability from four settlements approved by the FERC during the three months ended June 30, 2007. The Utility also received a cash distribution of approximately $19 million related to a prior settlement, which will be refunded to customers through rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers upon resolution of the remaining disputed claims either through settlement or the conclusion of the various FERC and judicial proceedings will be credited to customers (after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC).

As of June 30, 2007, the amount of the accrual for remaining net disputed claims was approximately $1.1 billion, consisting of approximately $1.6 billion of accounts payable-disputed claims primarily payable to the CAISO and the PX, offset by an accounts receivable from the CAISO and the PX of approximately $0.5 billion. The Utility held $1.1 billion in escrow for the payment of the remaining net disputed claims as of June 30, 2007. The amount held in escrow is classified as Restricted Cash in the Condensed Consolidated Balance Sheets.

As of June 30, 2007, the Utility has accrued interest of approximately $515 million (classified as Interest Payable in the Condensed Consolidated Balance Sheets) on the net disputed claims balance at the FERC-ordered interest rate. The rate of interest earned by the Utility on the escrowed amounts is less than the FERC-ordered interest rate. The Utility has been collecting the difference between the earned amount and the accrued amount from customers. The net interest amounts that have been collected from customers are not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest owed to generators, the Utility would refund to customers any excess net interest collected from customers. The ultimate amount of any interest that the Utility may be required to pay will depend on the final amount of refunds owed to the Utility.

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

NOTE 10: 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 June 30, 2007, the undiscounted future expected power purchase agreement payments based on June 30, 2007 forward prices were as follows:

(in millions)
2007	$	1,171
2008		2,397
2009		2,272
2010		2,122
2011		1,936
Thereafter		13,283
Total	$	23,181

Payments made by the Utility under power purchase agreements amounted to approximately $1,504 million for the six months ended June 30, 2007 and $1,038 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, the CPUC released a proposed decision (subsequently revised on July 20, 2007), that, if adopted, would modify the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. The CPUC is scheduled to consider the July 20, 2007 revised proposed decision on September 6, 2007. If adopted, the decision would affect those QFs that 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 the 2006 Annual Report for discussion of the settlement agreement.) Among other proposed changes, the revised 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 modified SRAC formula in the revised proposed decision would use a market index formula based on forward market price estimates. The Utility is currently evaluating the potential impact of the proposed new SRAC pricing formula to determine its likely effect on the energy payments to the non-settling QFs compared to the currently applicable SRAC pricing formula. Actual QF energy payments will depend on future natural gas 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	$	29
2008		50
2009		50
2010		50
2011		50
Thereafter		303
Total fixed capacity payments		532
Amount representing interest		(142	)
Present value of fixed capacity payments	$	390

Interest and amortization expense associated with the lease obligation is included in 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. These payments allow QFs to recover investment costs and compensate for improving system reliability. 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 sources of the Utility's natural gas procurement portfolio generally fluctuate based on market conditions.

At June 30, 2007, the Utility's undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2007	$	718
2008		597
2009		38
2010		22
2011		14
Thereafter		7
Total	$	1,396

Payments for natural gas purchases and gas transportation services amounted to approximately $1,230 million for the six months ended June 30, 2007 and $1,275 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 fourteen years and are intended to ensure long-term fuel supply. In most cases, the Utility's nuclear fuel contracts are requirements-based. The 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. New agreements are primarily based on forward market pricing and will begin to impact nuclear fuel costs starting in 2010.

At June 30, 2007, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2007	$	59
2008		153
2009		89
2010		106
2011		58
Thereafter		329
Total	$	794

Payments for nuclear fuel amounted to approximately $28 million for the six months ended June 30, 2007 and $22 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 June 30, 2007, the Utility’s estimated RMR agreement payments to CAISO could be approximately $32 million for the service months of July through December 2007. The Utility recovers these costs from 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 not received any claims nor does it consider it probable that any claims will be made under the guarantee. At June 30, 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

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 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 ordered 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 response to this order, in May 2007 the NRC issued a draft supplemental environmental assessment and preliminarily determined that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility. The NRC has adopted an expedited schedule for completion of the final supplemental environmental review and it is expected to be complete in early 2008.

The Utility estimates that it could complete the dry cask storage project in 2008. 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 has appealed 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 Claims’ 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 will seek recovery of costs incurred after 2004 in future lawsuits against the DOE.

If the U.S. Court of Federal Claims’ 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 has requested the CPUC to authorize the Utility to recover under the CEMA tariff a revenue requirement of approximately $42 million for recorded capital and expense costs related to the 2005-2006 winter storms and the July 2006 “heat storm.” The Utility has requested that this revenue requirement be recovered through rates from 2008 to 2010. On July 26, 2007, the CPUC disallowed approximately $23 million of the Utility’s request for costs incurred in connection with the July 2006 heat storm finding that there was no direct link between the emergency declarations and damage to the Utility’s facilities.

The CPUC did not address recovery of costs incurred by the Utility in connection with the 2005-2006 winter storms. On July 6, 2007, the CPUC’s Division of Ratepayer Advocates issued its report on the 2005-2006 winter storms, recommending that the CPUC disallow recovery of $8 million of the approximately $19 million remaining revenue requirement that the Utility had requested. It is expected that the CPUC will issue a separate decision to address costs related to the 2005-2006 winter storms. The Utility would recognize income to the extent the CPUC approves the recovery of costs already incurred in connection with the 2005-2006 winter storms. PG&E Corporation and the Utility are unable to predict when a final 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 25% of the electricity delivered to the Utility's customers for the six months ended June 30, 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. On May 31, 2007, Standard & Poor’s Rating Service raised the Utility’s credit rating to “BBB+” from “BBB;”

·	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, the Utility is eliminating and consolidating various employee positions in numerous Utility locations. As a result, the Utility has incurred severance costs and expects that it will incur additional severance costs as consolidation continues. Estimating the amount of future 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. At June 30, 2007, the Utility’s future severance costs are expected to range from $37 million to approximately $94 million. The Utility has recorded a liability of $37 million as of June 30, 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		10
Less: Payments		(7	)
Balance at June 30, 2007	$	37

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 $516 million at June 30, 2007 and approximately $511 million at December 31, 2006. The $516 million accrued at June 30, 2007 consists of:

·	approximately $239 million for remediation at the Hinkley and Topock natural gas compressor sites;

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

·	approximately $179 million related to remediation costs for the Utility’s generation and other facilities, 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 $516 million environmental remediation liability, approximately $142 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately $282 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 $810 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 $810 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site or has determined that a potential liability exists with respect to the site.

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. In May 2007, the parties filed for further review with the Second Circuit and in July 2007, the court denied the request. The parties have until October 2007 to request U.S. Supreme Court review. The EPA has suspended its regulations and will likely require significant time to review and revise them. 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. 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 certain deductions claimed by PG&E Corporation, including deductions for abandoned or worthless assets. In addition, the IRS is proposing to disallow $104 million of synthetic fuel credits claimed. 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 relates to timing differences, 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. On a net basis, adjustments proposed have no impact and result in no significant disallowances.

The California Franchise Tax Board recently notified PG&E Corporation of its intent to begin an audit of PG&E Corporation’s 2004 and 2005 combined California income tax returns.

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 NEGT stock in 2004, which, if not used by December 2009, will expire.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, 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 matter. 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 $66 million at June 30, 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 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. 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 4.3 million natural gas distribution customers at June 30, 2007. The Utility had approximately $35.0 billion in assets at June 30, 2007 and generated revenues of approximately $6.5 billion in the six months ended June 30, 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 (“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, which, 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 and Six Months Ended June 30, 2007

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three and six months ended June 30, 2007 were $0.74 per share and $1.45 per share, respectively, compared to $0.65 per share and $1.25 per share, respectively, for the same periods in 2006. The increases in diluted EPS for 2007 compared to 2006 are primarily due to increased revenues associated with the Utility’s return on equity (“ROE”) on additional capital investments authorized by the CPUC in the Utility’s 2007 General Rate Case (“GRC”) effective January 1, 2007, and by the FERC in the Utility’s Transmission Owner Rate Case effective March 1, 2007. These regulatory authorizations resulted in increased EPS for the three and six months ended June 30, 2007, of approximately $0.09 and $0.16, respectively. In addition, EPS for the six months ended June 30, 2007 reflects the Utility’s lower storm-related expenses compared to the same period in 2006, resulting in an approximate $0.02 EPS improvement.

For the three and six months ended June 30, 2007, PG&E Corporation’s net income increased by approximately $37 million, or 16%, to $269 million, and by approximately $79 million, or 18%, to $525 million, respectively, compared to $232 million and $446 million, respectively, for the same periods in 2006. The increases in net income for 2007 primarily result from the Utility’s increased revenues associated with additional capital investments authorized by the CPUC in the GRC and the FERC in the Transmission Owner Rate Case, as described above. For the three months ended June 30, 2007, these increased revenues account for approximately $33 million of additional net income. For the six month period, these increased revenues account for approximately $59 million of additional net income. Net income for the six months ended

June 30, 2007 also reflects the Utility’s lower storm-related expenses which account for approximately $7 million of additional net income compared to the same period in 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 that the Utility is authorized to recover from customers are primarily determined through regulatory proceedings. The timing of CPUC and FERC decisions also affect when the Utility is able to record the authorized revenues. In March 2007, the CPUC issued a decision in the 2007 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 were effective January 1, 2007. In June 2007, the FERC approved the Utility’s offer of settlement that set the electric transmission retail revenue requirement at $674 million, effective March 1, 2007, an increase of approximately $68 million over the prior 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% common equity component. For 2006 and 2007, the Utility is authorized to earn a ROE of 11.35% on its electricity and natural gas distribution and electric generation rate base. On May 8, 2007 the Utility filed an application requesting the CPUC to set the Utility’s authorized capital structure and rates of return for 2008. (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 achieve operational excellence and improved customer service. PG&E Corporation’s and the Utility’s financial condition and results of operations will be affected by whether, when, and how much actual cost savings exceed actual implementation costs.

·	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). (See further discussion under “Capital Expenditures” below.) 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. In addition, if the Utility’s capital expenditures exceed authorized amounts and if the CPUC or the FERC disallows those excess expenditures, the Utility could write off any disallowed amounts and would be unable to earn a return on rate base on the disallowed amounts.

·	The Amount and Timing of Financing Needs. The Utility issued $700 million principal amount of 5.80% Senior Notes in March 2007 to finance the capital expenditures discussed above and for working capital (see Note 4 of the Notes to the Condensed Consolidated Financial Statements). The amount of additional long-term debt the Utility may issue during the remainder of 2007 will be affected by the amount and timing of capital expenditures and the level of cash available. The Utility’s additional financing needs after 2007 will continue to be affected by the amount and timing of capital expenditures and, in addition, will be affected by the amount and timing of payments required to be made in connection with the disputed generator claims arising from the 2000-2001 California energy crisis, including accrued interest, upon settlement or resolution of the pending FERC and judicial proceedings. PG&E Corporation plans to contribute equity to the Utility to maintain the Utility’s authorized capital structure. (See further discussion under “Liquidity and Financial Resources” below.) PG&E Corporation’s and the Utility’s financial condition and results of operations will be affected by the interest rates, timing, and terms and conditions of this financing.

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 six months ended June 30, 2007, approximately $11 million related to environmental remediation expenses was recorded. (See discussion under “Environmental and Legal Matters” below.)

FORWARD-LOOKING STATEMENTS

This quarterly report, 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, anticipated costs and savings associated with the Utility’s efforts to implement changes to its business processes and systems, 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 incurs costs and liabilities in connection with 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. 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 and six-month periods ended June 30, 2007 and 2006.

	(Unaudited)
	Three Months Ended						Six Months Ended
(in millions)	June 30,						June 30,
	2007			2006			2007			2006

Utility
Electric operating revenues	$	2,359		$	2,214		$	4,534		$	4,077
Natural gas operating revenues		828			803			2,009			2,088
Total operating revenues		3,187			3,017			6,543			6,165
Cost of electricity		884			781			1,607			1,311
Cost of natural gas		396			368			1,150			1,241
Operating and maintenance		921			982			1,840			1,844
Depreciation, amortization, and decommissioning		430			421			859			834
Total operating expenses		2,631			2,552			5,456			5,230
Operating income		556			465			1,087			935
Interest income		35			39			83			58
Interest expense		(178	)		(157	)		(360	)		(303	)
Other income, net⁽¹⁾		11			21			17			24
Income before income taxes		424			368			827			714
Income tax provision		154			141			299			273
Income available for common stock	$	270		$	227		$	528		$	441
PG&E Corporation, Eliminations and Other⁽²⁾
Operating revenues	$	-		$	-		$	-		$	-
Operating expenses		1			-			3			1
Operating loss		(1	)		-			(3	)		(1	)
Interest income		2			2			6			6
Interest expense		(7	)		(7	)		(15	)		(15	)
Other income (expense), net		(1	)		7			(3	)		4
Income (loss) before income taxes		(7	)		2			(15	)		(6	)
Income tax benefit		(6	)		(3	)		(12	)		(11	)
Net income (loss)	$	(1	)	$	5		$	(3	)	$	5
Consolidated Total⁽²⁾
Operating revenues	$	3,187		$	3,017		$	6,543		$	6,165
Operating expenses		2,632			2,552			5,459			5,231
Operating income		555			465			1,084			934
Interest income		37			41			89			64
Interest expense		(185	)		(164	)		(375	)		(318	)
Other income, net⁽¹⁾		10			28			14			28
Income before income taxes		417			370			812			708
Income tax provision		148			138			287			262
Net income	$	269		$	232		$	525		$	446


⁽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 and six months ended June 30, 2007 and 2006.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts collected through rates charged to customers for electricity generation and procurement and for electric transmission and distribution services.

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

	Three Months Ended						Six Months Ended
(in millions)	June 30,						June 30,
	2007			2006			2007			2006

Electric revenues	$	2,868		$	2,688		$	5,594		$	5,064
DWR pass-through revenue⁽¹⁾		(509	)		(474	)		(1,060	)		(987	)
Total electric operating revenues	$	2,359		$	2,214		$	4,534		$	4,077
Total electricity sales (in Gigawatt hours)		16,177			15,710			30,955			30,828


⁽¹⁾These are revenues collected on behalf of the California Department of Water Resources (“DWR”) for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income.

The Utility’s electric operating revenues increased in the three months ended June 30, 2007 by approximately $145 million, or approximately 7%, 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 $130 million. (See “Cost of Electricity” below.)

·	The Utility recognized an increase to its authorized 2007 base revenue requirements of approximately $55 million as authorized in the 2007 GRC.

·	Other electric operating revenues, including those associated with public purpose programs, recovery of net interest costs related to disputed generator claims (see “Interest Income” and “Interest Expense” below and the 2006 Annual Report), and electric transmission revenues (see “Regulatory Matters - FERC Transmission Owner Rate Case” below), increased by approximately $33 million.

These increases were partially offset by the following:

·	A decrease of approximately $45 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 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	A decrease of approximately $28 million reflecting the difference between six months of pension revenues recorded in the second quarter of June 2006 following the June 2006 CPUC approval of a pension settlement agreement and only three months of pension revenues recorded in the second quarter of 2007.

The Utility’s electric operating revenues increased in the six months ended June 30, 2007 by approximately $457 million, or approximately 11%, 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 $362 million. (See “Cost of Electricity” below.)

·	The Utility recognized an increase to its authorized 2007 base revenue requirements of approximately $110 million as authorized in the 2007 GRC.

·	Other electric operating revenues, including those associated with public purpose programs, recovery of net interest costs related to disputed generator claims (see “Interest Income” and “Interest Expense” below and the 2006 Annual Report), and electric transmission revenues (see “Regulatory Matters - FERC Transmission Owner Rate Case” below), increased by approximately $101 million.

These increases were partially offset by a decrease of approximately $116 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 10 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 and by the FERC in electric transmission rate cases. 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. 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.)

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						Six Months Ended
(in millions)	June 30,						June 30,
	2007			2006			2007			2006
Cost of purchased power	$	892		$	820		$	1,620		$	1,429
Proceeds from surplus sales allocated to the Utility		(46	)		(69	)		(88	)		(198	)
Fuel used in own generation		38			30			75			80
Total cost of electricity	$	884		$	781		$	1,607		$	1,311
Average cost of purchased power per kWh	$	0.084		$	0.080		$	0.087		$	0.078
Total purchased power (in millions of kWh)		10,629			10,302			18,683			18,258

In the three and six months ended June 30, 2007, the Utility's cost of electricity increased by approximately $103 million and $296 million, or 13% and 23%, respectively, compared to the same periods in 2006. These increases were primarily driven by a 5% and 12% increase in the average cost of purchased power for the three and six months ended June 30, 2007, respectively. The average cost of purchased power increased $0.004 and $0.009 per kilowatt-hour (“kWh”) for the three and six months ended June 30, 2007, respectively, compared to the same periods in 2006, primarily due to higher energy payments made to qualifying facilities (“QFs”) after their five-year fixed price contracts expired during the summer of 2006. In addition, due to less than average precipitation, the Utility produced less hydroelectric power during the first six months of 2007 compared to the same period in 2006. As a result, the Utility increased the amount of power that it purchased from third parties during the three and six months ended June 30, 2007 compared to the same periods in 2006.

The Utility's cost of electricity in 2007 and in future periods will depend upon electricity prices, the level of hydroelectric and nuclear power that the Utility produces, 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, the CPUC is expected to issue a decision in the third quarter of 2007 that 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 federal or state legislation or rules which may be adopted to regulate the emissions of greenhouse gases from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. 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. The Utility's transportation services are provided by a transmission system (which includes backbone and local transmission lines) and a distribution system. The transmission system transports natural gas throughout California for delivery to the Utility's distribution system which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. The Utility also delivers natural gas to off-system markets, primarily in southern California, in competition with interstate pipelines.

The Utility’s natural gas operating revenues consist of “bundled natural gas revenues” collected through rates from substantially all residential and small commercial (or “core”) customers who buy natural gas, as well as transportation and distribution services, from the Utility as a bundled service. The Utility's natural gas operating revenues also include revenues from industrial, larger commercial and electric generation (or “non-core”) customers who generally purchase only transportation services from the Utility.

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

	Three Months Ended				Six Months Ended
(in millions)	June 30,				June 30,
	2007		2006		2007		2006
Bundled natural gas revenues	$	746	$	734	$	1,849	$	1,951
Transportation service-only revenues		82		69		160		137
Total natural gas operating revenues	$	828	$	803	$	2,009	$	2,088
Average bundled revenue per Mcf of natural gas sold	$	14.20	$	11.84	$	11.23	$	11.78
Total bundled natural gas sales (in millions of Mcf)		53		62		165		166

In the three months ended June 30, 2007, the Utility's natural gas operating revenues increased by approximately $25 million, or 3%, compared to the same period in 2006. This is primarily due to an increase in bundled natural gas revenues of approximately $12 million, or 2%, as a result of a 20% increase in the average price of natural gas supplied to the Utility’s customers, which are recoverable costs (see “Cost of Natural Gas” below). This increase was partially offset by a decrease in volume of approximately 15%, which is primarily due to a milder winter as compared to the same period in 2006.

In the six months ended June 30, 2007, the Utility's natural gas operating revenues decreased by approximately $79 million, or 4%, compared to the same period in 2006. This is primarily due to a decrease in bundled natural gas revenues of approximately $102 million, or 5%, due to a decrease in the cost of natural gas, which is passed through to customers (see “Cost of Natural Gas” below).

In the three and six months ended June 30, 2007, the Utility’s revenues associated with transportation service increased by approximately $13 million and $23 million, or 19% and 17%, respectively, primarily due to an increase volume associated with the Utility’s delivery of natural gas to large end-use customers as compared to the same periods in 2006.

The Utility expects that its natural gas operating revenues for gas transmission and storage will increase slightly in 2007 due primarily to higher gas demand. For 2008 through 2010, as discussed under “Regulatory Matters - Natural Gas Transmission and Storage Rate Case” below, the proposed Gas Accord IV settlement agreement calls for an overall modest increase in the revenue requirements for the Utility’s gas transmission and storage services. In addition, the Utility’s natural gas operating revenues for distribution are expected to increase through 2010 as a result of revenue requirement increases authorized by the CPUC in the 2007 GRC. Future natural gas operating revenues also will be impacted by changes in the cost of natural gas, through put volume, and other factors.

Cost of Natural Gas

The Utility's cost of natural gas includes the purchase costs of natural gas and transportation costs on interstate pipelines. It 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				Six Months Ended
(in millions)	June 30,				June 30,
	2007		2006		2007		2006
Cost of natural gas sold	$	354	$	333	$	1,060	$	1,170
Cost of natural gas transportation		42		35		90		71
Total cost of natural gas	$	396	$	368	$	1,150	$	1,241
Average cost per Mcf of natural gas sold	$	6.68	$	5.37	$	6.42	$	7.05
Total natural gas sold (in millions of Mcf)		53		62		165		166

In the three months ended June 30, 2007, the Utility's total cost of natural gas increased by approximately $28 million, or 8%, compared to the same period in 2006, primarily due to an increase in the average market price of natural gas sold due to industry perceptions of risks associated with severe weather changes (as discussed further below). This increase was partially offset by a decrease in the volume of natural gas supplied to the Utility’s customers. The decrease in the total volume of natural gas sold of approximately 9 million Mcf, where Mcf equals one thousand cubic feet, or 15%, was primarily due to a milder winter as compared to the same period in 2006.

In the six months ended June 30, 2007, the Utility's total cost of natural gas decreased by approximately $91 million, or 7%, compared to the same period in 2006, primarily due to a decrease in the average market price of natural gas purchased of approximately $0.63 per Mcf, or 9%. The industry perceptions impacting the average price of natural gas for the three months ended June 30, 2007 did not have a significant impact for the six months ended June 30, 2007 due to significantly higher average market prices of natural gas in the first quarter 2006 as compared to the same period in 2007.

The Utility's cost of natural gas in 2007 will be primarily affected by the prevailing costs of natural gas, which are determined by market forces in North America. Such market forces include supply availability, customer demand and industry perceptions of risks that may affect either, such as the possibility of hurricanes in the gas-producing regions of the Gulf of Mexico or of protracted heat waves that may increase gas-fired electric demand from high air conditioning loads.

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 June 30, 2007, the Utility’s operating and maintenance expenses decreased by approximately $61 million, or 6%, compared to the same period in 2006, mainly due to the net effect of the following factors:

·	A decrease of $79 million in pension expense primarily due to lower annual pension contributions as approved by the CPUC in June 2006. In addition, the Utility recorded six months of pension expense in the second quarter of June 2006 following the June 2006 CPUC approval of a pension settlement agreement and only three months of pension expense in the second quarter of 2007. Pension expense also was lower because the Utility earned a higher return on pension plan assets in the second quarter of 2007 as compared to the same period in 2006.

·	A decrease of $22 million in environmental remediation expenses at the gas compressor station located near Hinkley, California. Higher expenses in 2006 were primarily due to changes in the California Regional Water Quality Control Board’s imposed remediation levels.

·	An increase of $31 million in payments made for customer assistance programs primarily due to increased customer participation in these programs.

·	An increase of $11 million related to higher costs associated with base salaries and incentives.

During the six months ended June 30, 2007, the Utility’s operating and maintenance expenses decreased by approximately $4 million, or less than 1%, compared to the same period in 2006, mainly due to the net effect of the following factors:

·	A decrease of $50 million in pension expense primarily due to lower annual pension contributions as approved by the CPUC in June 2006. Pension expense also was lower because the Utility earned a higher return on pension plan assets in 2007 as compared to the same period in 2006.

·	A decrease of $20 million in environmental remediation expenses at the gas compressor station located near Hinkley, California. Higher expenses in 2006 were primarily due to changes in the California Regional Water Quality Control Board’s imposed remediation levels.

·	An increase of $44 million in payments made for customer assistance programs primarily due to increased customer participation in these programs.

·	An increase of $21 million related to higher costs associated with base salaries and incentives.

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 the implementation of initiatives to achieve operational excellence and improved customer service. As the Utility implements these initiatives, jobs from numerous locations around California are being consolidated and a number of positions are being eliminated. The Utility expects that more positions will be eliminated and, as a result, expects to incur additional severance expenses in the future. (See further discussion in Note 10 of the Notes to the Condensed Consolidated Financial Statements.) In addition, the Utility expects that it will incur higher expenses to comply with conditions in renewed hydroelectric generation licenses and the construction of the dry cask storage facility at Diablo Canyon. Although it is unlikely, the NRC may require the Utility to shut down Diablo Canyon Unit 2 by December 31, 2007 to perform a weld repair in response to the NRC’s industry-wide concerns over specific dissimilar metal welds. It is expected that the NRC will confirm by the end of August 2007 that the steps the affected utilities have taken, including enhanced monitoring, inspection, and mitigation of the welds, are sufficient to address the NRC’s concerns. If the NRC requires the Utility to shut down Unit 2 in 2007 to perform the weld repair, the Utility’s operating and maintenance expenses would increase.

Depreciation, Amortization, and Decommissioning

In the three and six months ended June 30, 2007, the Utility's depreciation, amortization, and decommissioning expenses increased by approximately $9 million and $25 million, 2% and 3%, respectively, as compared to the same periods in 2006, mainly due to depreciation rate changes and plant additions authorized by 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 depreciation rates.

Interest Income

In the three months ended June 30, 2007, the Utility’s interest income decreased by approximately $4 million, or 10%, compared to the same period in 2006 primarily due to interest income recorded in June 2006 associated with the recovery of a portion of the costs the Utility incurred as a scheduling coordinator (“SC”) during April 1998 through July 2005 with no similar amount recorded in 2007. This decrease was partially offset by an increase in interest income due to an increase in interest earned on funds held in escrow for disputed generator claims (see “Electric Operating Revenues” above for further discussion).

In the six months June 30, 2007, the Utility’s interest income increased by approximately $25 million, or 43%, compared to the same period in 2006 primarily due to an increase in interest income earned on funds held in escrow for disputed generator claims. (See “Electric Operating Revenues” above for further discussion.) In addition, in the first quarter of 2007, the Utility recognized interest income of approximately $16 million related to a settlement of refund claims with the Internal Revenue Service. No similar amount was recorded in the same period in 2006. These increases were partially offset by a decrease in interest income due to interest income recorded in June 2006 associated with the recovery of a portion of the costs incurred as a SC during April 1998 through July 2005 with no similar amount recorded in 2007.

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

Interest Expense

In the three months ended June 30, 2007, the Utility interest expense increased by approximately $21 million, or 13%, compared to the same period in 2006, primarily due to interest related to the additional $700 million in Senior Notes issued on March 13, 2007. This increase was partially offset by lower interest expense on the rate reduction bonds (“RRBs”) and energy recovery bonds (“ERBs”) due to their declining balance.

In the six months ended June 30, 2007, the Utility’s interest expense increased by approximately $57 million, or 19%, compared to the same period in 2006, primarily due to an increase in interest expense related to disputed generator claims. (See “Electric Operating Revenues” above for further discussion.) In addition, interest expense increased due to interest related to the additional $700 million in Senior Notes issued on March 13, 2007. These increases were partially offset by lower interest expense on the RRBs and ERBs due to their declining balances.

Net interest costs resulting from differences between interest income on funds held in escrow and interest expense related to disputed generator claims are passed through to customers. 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 bear variable interest rates, as well as by changes in the amount of debt, including future debt expected to be issued in 2007 and later to partially finance capital investments.

Income Tax Expense

In the three months ended June 30, 2007, the Utility's income tax expense increased by approximately $13 million, or 9%, compared to the same period in 2006, primarily due to the increase in pre-tax income of $56 million. The effective tax rates for the three months ended June 30, 2007 and 2006 were 35.9% and 37.9%, respectively.

In the six months ended June 30, 2007, the Utility's income tax expense increased by approximately $26 million, or 10%, compared to the same period in 2006, primarily due to the increase in pre-tax income of $113 million. The effective tax rates for the six months ended June 30, 2007 and 2006 were 35.8% 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 and six months ended June 30, 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.

At June 30, 2007, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $366 million and restricted cash of approximately $1.4 billion. At June 30, 2007, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $288 million; the Utility had cash and cash equivalents of approximately $78 million and restricted cash of approximately $1.4 billion. Restricted cash primarily consists of approximately $1.3 billion, including interest, of cash held in escrow pending the resolution of the remaining disputed claims that had been made by generators and power suppliers for transactions that occurred during the 2000-2001 California energy crisis, 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.

The Utility seeks to maintain or strengthen its credit ratings to provide liquidity through efficient access to financial and trade credit, and to reduce financing costs. 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% and a minimum 52% common equity ratio until the Utility receives a credit rating of “A3” from Moody’s Investors Service (“Moody’s”) or “A-” from Standard & Poor’s Ratings Service (“S&P”). PG&E Corporation and the Utility seek to maintain this 52% level. In May 2007, S&P upgraded the Utility’s credit rating from “BBB” to “BBB+.”

Moody's and S&P are nationally recognized credit rating organizations. These ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. A credit rating is not a recommendation to buy, sell, or hold securities.

As of June 30, 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 $1.2 billion, respectively. As of June 30, 2007, the Utility had $174 million of letters of credit outstanding under its working capital facility and $577 million of outstanding commercial paper. On February 26, 2007, 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, on June 28, 2007, the Utility increased its borrowing capacity under the commercial paper program from $1 billion to $1.75 billion.

The Utility issued $700 million of Senior Notes in March 2007 (see Note 4 of the Notes to the Condensed Consolidated Financial Statements). The amount of additional long-term debt the Utility may issue during the remainder of 2007 will be affected by the amount and timing of capital expenditures and the level of cash available.

The Utility also estimates that it will need to increase its amount of common equity 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. 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. On June 20, 2007, the Board of Directors of PG&E Corporation authorized PG&E Corporation to make periodic additional equity infusions to the Utility in a total aggregate amount of up to $450 million, through December 31, 2009, to be financed with cash on hand at the time of the infusions.

The amount and timing of the Utility’s financing needs after 2007 will depend on various factors, including: (1) the timing and amount of forecasted capital expenditures and any incremental capital expenditures beyond those currently forecasted; (2) the amount of cash internally generated through normal business operations; (3) the timing of the resolution of the disputed generator claims (upon settlement or the conclusion of the FERC and judicial proceedings); and (4) the amount that the Utility is required to pay (including accrued interest) upon resolution of the disputed generator claims. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation anticipates that it will partially fund the Utility’s equity needs from the proceeds of common stock issued upon exercise of employee stock options, and to the trustee of PG&E Corporation’s 401(k) plan for the account of employee-participants. The trustee of the 401(k) plan began purchasing shares for the 401(k) plan directly from PG&E Corporation in May 2007. During the six months ended June 30, 2007, PG&E Corporation issued approximately 2,672,166 shares of common stock related to the exercise of employee stock options and for the account of 401(k) plan participants, generating approximately $89 million of cash available for reinvestment and other uses. In addition, PG&E Corporation expects that it will issue additional shares under its new dividend reinvestment and stock purchase plan, scheduled to become effective on October 1, 2007. PG&E Corporation will continue to evaluate how to fund the Utility’s future equity needs, which may result in equity and debt issuances in addition to the equity sources discussed above.

Dividends

During the six months ended June 30, 2007, the Utility used cash in excess of amounts needed for operations, debt service, capital expenditures, and preferred stock requirements to pay common stock dividends of $273 million. Approximately $254 million of 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 August 6, 2007.

On March 16, 2007, PG&E Corporation declared its quarterly dividend at $0.36 per share, an increase of $0.03 per share over the previous level of $0.33 per share. The increased dividend is consistent with PG&E Corporation’s targeted dividend payout ratio of between 50% to 70% of earnings. On January 15, April 15, and July 15, 2007, PG&E Corporation paid common stock dividends in the aggregate amount of $393 million, including approximately $26 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 August 6, 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 six months ended June 30, 2007 and 2006 were as follows:

	Six Months Ended
(in millions)	June 30,
	2007			2006
Net income	$	535		$	448
Adjustments to reconcile net income to net cash provided by operating activities		1,142			1,078
Changes in operating assets and liabilities, and other		(442	)		(16	)
Net cash provided by operating activities	$	1,235		$	1,510

In the six months ended June 30, 2007, net cash provided by operating activities decreased by approximately $275 million from the same period in 2006, primarily due to an approximately $180 million decrease in cash settlements from energy suppliers from $270 million in the six months ended June 30, 2006 to $90 million in the six months ended June 30, 2007.

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 six months ended June 30, 2007 and 2006 were as follows:

	Six Months Ended
(in millions)	June 30,
	2007			2006
Capital expenditures	$	(1,320	)	$	(1,178	)
Net proceeds from sale of assets		8			7
Decrease (increase) in restricted cash		(13	)		48
Other investing activities		(58	)		(42	)
Net cash used in investing activities	$	(1,383	)	$	(1,165	)

Net cash used in investing activities increased by approximately $218 million in the six months ended June 30, 2007 compared to the same period in 2006, primarily due to an increase of approximately $142 million in capital expenditures for the SmartMeter™ installation project, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.) In addition, the Utility released approximately $80 million less from escrow in the six months ended June 30, 2007 upon settlement of disputed Chapter 11 generator claims, compared to the same period in 2006.

Financing Activities

The Utility’s cash flows from financing activities for the six months ended June 30, 2007 and 2006 were as follows:

	Six Months Ended
	June 30,
(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 issuance of commercial paper, net of $2 million discount in 2007		109			213
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million		690			-
Rate reduction bonds matured		(143	)		(141	)
Energy recovery bonds matured		(160	)		(130	)
Common stock dividends paid		(254	)		(230	)
Preferred dividends paid		(7	)		(7	)
Equity infusion from PG&E Corporation		200			-
Other		21			(88	)
Net cash provided by (used in) financing activities	$	156		$	(643	)

In the six months ended June 30, 2007, net cash used in financing activities decreased by approximately $799 million compared to the same period in 2006. This was mainly due to the net effect of the following factors:

·	In March 2007, the Utility issued Senior Notes and received net proceeds of approximately $690 million with no similar issuance in 2006.

·	The Utility received an equity infusion of $200 million from PG&E Corporation in 2007, with no similar infusion in 2006.

·	There was a decrease in the Utility’s net issuance of commercial paper from $213 million in 2006 to only $109 million in 2007.

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 six months ended June 30, 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 six months ended June 30, 2007 and 2006.

Financing Activities

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

PG&E Corporation's cash flows from financing activities for the six months ended June 30, 2007 and 2006 were as follows:

	Six Months Ended
	June 30,
(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 issuance of commercial paper, net of $2 million discount in 2007		109			213
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million		690			-
Rate reduction bonds matured		(143	)		(141	)
Energy recovery bonds matured		(160	)		(130	)
Common stock issued		89			77
Common stock repurchased		-			(114	)
Common stock dividends paid		(242	)		(228	)
Other		14			(84	)
Net cash provided by (used in) financing activities	$	57		$	(667	)

During the six months ended June 30, 2007, PG&E Corporation's consolidated net cash used in financing activities decreased by approximately $724 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 $114 million paid as additional consideration for the 2005 repurchase of common stock in the first six months of 2006, with no similar payments in 2007.

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’s commitments now include $700 million of Senior Notes due March 1, 2037. (See Notes 2, 4, 9, and 10 of the Notes to the Condensed Consolidated Financial Statements and the 2006 Annual Report for further discussion.)

CAPITAL EXPENDITURES

The Utility expects that capital expenditures will total approximately $3.2 billion in 2007. During the six months ended June 30, 2007, the Utility incurred capital expenditures of approximately $1.3 billion. (See “Liquidity and Financial Resources – Investing Activities” above.) Based on the estimated capital expenditures for 2007, the Utility projects a weighted average rate base for 2007 of approximately $17.0 billion. Over the next four 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.

Advanced Metering Initiative

In compliance with the CPUC decision authorizing the Utility to install an advanced metering infrastructure, known as the SmartMeter™ program, on July 20, 2007, the Utility submitted its semi-annual report to the CPUC explaining the steps that the Utility has taken to monitor advanced metering technology developments. The Utility also issued a request to vendors seeking proposals to test emerging technologies that could build upon and enhance the benefits of the Utility’s SmartMeter™ program and help the Utility better serve its customers through an enterprise-wide communications network to enable more advanced energy management.

While the evaluation of new technology will focus on enhanced functions for the electric system, the Utility will consider the commercial feasibility of a common network to cover both electric and gas meters. Proposals are due in mid-August 2007. If the request for proposals yields technically feasible and economic options, the Utility would request authorization from the CPUC to pursue the new technology and for the recovery of associated costs. Pending the new technology evaluation process, the Utility currently plans to continue the installation of advanced electric and gas meters as part of its SmartMeter™ program with the installation of approximately 240,000 advanced meters by the end of 2007. The technology evaluation underway, however, may result in a deployment planning adjustment that could impact the timing of

capital expenditures going forward. The agreements between the Utility and the vendors involved in the SmartMeter™ program allow the Utility to terminate the contracts for the Utility’s convenience. If the Utility exercises its right to terminate the contracts, the Utility would be obligated to pay termination fees. The Utility believes that the aggregate amount of any termination fees that it may become obligated to pay would not be material. The Utility would seek to recover the amount of any termination fees that it may be required to pay through rates.

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 10 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-related losses attributable to receivables and electric 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 provisions, 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 ties many energy contracts to 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 following table 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 June 30, 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)
June 30, 2007	$	291	$	93	$	198		2	$	96
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.
⁽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 Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

This section of MD&A discusses developments that have occurred in significant pending regulatory proceedings discussed in the 2006 Annual Report and significant new pending regulatory proceedings that were initiated since the 2006 Annual Report was filed with the SEC. The outcome of these proceedings could have a significant effect on PG&E Corporation’s and the Utility’s results of operations and financial condition.

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 $1.0 billion for natural gas distribution (an increase of $21 million over the 2006 authorized amount), and approximately $1.0 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.

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 that 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 electric and natural gas distribution and electric 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 rate base, and (3) establishes the costs of preferred equity and debt that the Utility will be authorized to recover. 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 $34 million over the currently authorized revenue requirement for electric distribution and electric generation operations, and

$7 million over the currently authorized revenue requirement for natural gas distribution, 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 also has proposed to replace the annual cost of capital proceeding 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 cost of equity, if the change in the benchmark interest rate is more than 75 basis points. If the change is more than 75 basis points, the cost of equity 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.

On June 21, 2007, the assigned CPUC commissioner issued a ruling stating that the proceeding would be handled in two phases and set a schedule for each phase. The first phase will address test year 2008 cost of capital issues, with an interim decision scheduled to be issued by December 6, 2007. The second phase will address mechanisms that could replace the annual cost of capital proceedings, with a final decision scheduled to be issued by April 24, 2008.

PG&E Corporation and the Utility are unable to predict the outcome of this proceeding.

FERC Transmission Owner Rate Cases

On June 7, 2007, the FERC approved a settlement that sets the Utility’s annual transmission retail revenue requirement at $674 million, an increase of approximately $68 million over previously authorized revenue requirements, effective March 1, 2007. As of March 1, 2007, the Utility began collecting from customers based on an estimated annual transmission retail revenue requirement of approximately $719 million; the Utility will refund any over-collected amounts, with interest, to customers.

On July 30, 2007, the Utility filed an application with the FERC requesting an annual transmission retail revenue requirement of approximately $761 million, effective October 1, 2007; however, in the past, similar requests for such increases have been suspended for an additional five months which would result in a March 1, 2008 effective date. The proposed rates represent an increase of approximately $78 million over current authorized revenue requirements.

PG&E Corporation and the Utility are unable to predict the outcome of this proceeding.

Rulemaking Proceeding to Modify QF Pricing and Policies

On April 24, 2007, the CPUC released a proposed decision (subsequently revised on July 20, 2007), that, if adopted, would modify the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. The CPUC is scheduled to consider the July 20, 2007 revised proposed decision on September 6, 2007. If adopted, the decision would affect those QFs that 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 the 2006 Annual Report for a discussion of the settlement agreement.) Among other proposed changes, the revised 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 modified SRAC formula in the revised proposed decision would use a market index formula based on forward market price estimates. The Utility is currently evaluating the potential impact of the proposed new SRAC pricing formula to determine its likely effect on the energy payments to the non-settling QFs compared to the currently applicable SRAC pricing formula. Actual QF energy payments will depend on future natural gas prices.

The revised 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.

PG&E Corporation and the Utility are unable to predict whether the CPUC will adopt the revised proposed decision. Any adjustments to QF prices resulting from the CPUC’s adoption of the revised proposed decision or any alternate decision that may be adopted 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 supporting 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 (“DRA”). The Gas Accord IV proposes a 2008 natural gas transmission and storage revenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the proposed 2008 revenue requirement), and a 2010 revenue requirement of $471 million (approximately 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 core customers can select a third-party gas supplier and use the Utility only to deliver gas to them through its transmission and distribution systems, most core customers buy natural gas from the Utility, as part of bundled service that includes transmission and distribution.

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, 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

During June 2007, evidentiary hearings were held in the energy efficiency rulemaking proceeding pending before the CPUC. The hearings primarily addressed 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.

Under the mechanisms proposed by the investor-owned 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 achieves 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. The California Large Energy Consumers Association representing industrial customers supports TURN’s proposed mechanism.

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 the value of the benefits to customers 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 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.

Rulemaking Proceeding to Re-establish Direct Access

On May 24, 2007, the CPUC opened a rulemaking proceeding to consider how, whether and when to re-establish direct access, i.e., the ability of retail electric customers to purchase electricity from an independent supplier rather than from an investor-owned utility.

The decision states that any program to reinstitute retail competition 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 decision states that the first phase of the proceeding will examine the CPUC’s legal authority to re-establish direct access before the DWR’s power purchase contracts have expired. The second phase will consider the public policy issues that surround lifting the direct access suspension and any and all applicable wholesale market structure issues. The third phase will develop the rules that should govern a reinstituted direct access market, e.g., entry, exit, switching, default service arrangements, and cost recovery issues, among others. The decision’s schedule anticipates the issuance of a final decision by the end of 2008 or early 2009.

Depending on the final forms of any rules that the CPUC may adopt, the re-establishment of direct access could significantly increase the uncertainty associated with the Utility’s future level of bundled electric load for which it must procure electricity and secure generating capacity. If the Utility experiences a material loss of customers, the Utility's existing electricity purchase contracts could obligate it to purchase more electricity than its remaining customers require. This would result in a “long position” (i.e., when the Utility’s supply of electricity from its own generation resources plus net energy purchase contracts exceeds customer demand) and require the Utility to sell the excess, possibly at a loss. In addition, excess electricity generated by the Utility’s generation facilities may also have to be sold, possibly at a loss, and costs that the Utility may have incurred to develop or acquire new generation resources may become stranded. Conversely, if a material number of direct access customers decide to return to receiving bundled services from the Utility, the Utility would be in a “short position” (i.e., when customer demand exceeds the amount of electricity that can be economically produced from the Utility’s own generation facilities plus net energy purchase contracts). If the Utility’s short position unexpectedly increases, the Utility would need to purchase electricity in the wholesale market under contracts priced at the time of execution or, if made in the spot market, at the then-current market price of wholesale electricity. If the CPUC fails to adjust the Utility's rates to reflect the impact of changing loads, PG&E Corporation's and the Utility's financial condition, results of operations, and cash flowscould be materially adversely affected.

Spent Nuclear Fuel Storage Proceedings

As previously disclosed, after receiving a permit from the Nuclear Regulatory Commission (“NRC”) in March 2004, the Utility began building an on-site dry cask storage facility at Diablo Canyon to store spent nuclear fuel through at least 2024. Various parties appealed the NRC’s issuance of the permit. In 2006, the U.S. Court of Appeals for the Ninth Circuit ordered the NRC to consider the environmental consequences of a potential terrorist attack at Diablo Canyon. In response to this order, in May 2007 the NRC issued a draft supplemental environmental assessment and preliminarily determined that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage

facility. The NRC has adopted an expedited schedule for completion of the final supplemental environmental review and it is expected to be complete in early 2008.

The Utility expects to complete the dry cask storage facility in 2008. 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.

Catastrophic Event Memorandum Account Application

The CPUC did not address recovery of costs incurred by the Utility in connection with the 2005-2006 winter storms. On July 6, 2007, the CPUC’s DRA issued its report on the 2005-2006 winter storms, recommending that the CPUC disallow recovery of $8 million of the approximately $19 million remaining revenue requirement that the Utility had requested. It is expected that the CPUC will issue a separate decision to address costs related to the 2005-2006 winter storms. The Utility would recognize income to the extent the CPUC approves the recovery of costs already incurred in connection with the 2005-2006 winter storms. PG&E Corporation and the Utility are unable to predict when a final decision will be issued.

Market Redesign and Technology Upgrade

In response to the electricity market manipulation that occurred during the 2000-2001 energy crisis and the underlying need for improved congestion management, the CAISO has undertaken a Market Redesign and Technology Upgrade (“MRTU”) initiative. MRTU will implement a new day-ahead wholesale electricity market and is intended to improve electricity grid management reliability, operational efficiencies and related technology infrastructure. MRTU, currently scheduled to become effective in February 2008, will add significant market complexity and will require major changes to the Utility’s systems and software interfacing with the CAISO.

Among other features, the MRTU initiative provides that electric transmission congestion costs and credits will be determined between any two locations and charged to the market participants, including load serving entities (“LSEs”), taking energy that passes between those locations. The CAISO also will provide Congestion Revenue Rights (“CRRs”) to allow market participants, including LSEs, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The CAISO will release CRRs through an annual and monthly process, each of which includes both an allocation phase (in which LSEs receive CRRs at no cost) and an auction phase (priced at market, and available to all market participants).

Based on the CAISO’s current schedule for conducting the 2008 allocation phase, the Utility plans to request CRRs in the third quarter of 2007. The Utility expects the CAISO to begin allocating CRRs in the third quarter of 2007 and to complete the 2008 CRR allocation and auction process in the first quarter of 2008, before MRTU becomes effective. The CRRs are derivative instruments and will be recorded in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets at fair value. Changes in the fair value of the CRRs will be deferred and recorded in regulatory accounts to the extent they are recoverable through rates.

PG&E Corporation and the Utility are unable to predict what impact the implementation of the MRTU initiative will have on their financial condition and results of operations, whether the Utility will incur costs related to MRTU that are not determined to be recoverable, or whether the Utility will be able to successfully manage its congestion costs under MRTU.

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

Electricity Procurement

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities. A failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts would reduce the size of the Utility's electricity supply portfolio.

Calpine Corporation (“Calpine”), a supplier of power under contracts with the DWR, filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in 2005. As part of that filing, Calpine requested permission to reject a contract that supplies approximately 1,000 megawatts (“MW”) of power needed by the Utility’s customers. In June 2007, Calpine filed its plan of reorganization to emerge from Chapter 11 and is asking the bankruptcy court to repudiate this contract with DWR. The Utility opposes Calpine’s unilateral repudiation of the contract. If Calpine were to prevail under its plan of reorganization, the Utility would be required to purchase electricity on the spot and forward market, at potentially much higher prices, to replace the 1,000 MW of power. The Utility’s additional power procurements costs attributable to repudiation of the Calpine contract would be recoverable from Utility customers in the same manner as other power procurement costs are currently recovered.

Natural Gas Procurement (Core Customers)

In the past, the Utility’s cost of gas hedging for core customers was accounted for in its Core Procurement Incentive Mechanism (“CPIM”), which rewards the Utility when its gas purchases are less costly than a market benchmark, and penalizes the Utility when its gas purchases are more expensive than the market benchmark.

On June 7, 2007, the CPUC issued a decision approving a long-term hedging program for the Utility’s core gas purchases. The decision approved a settlement agreement between the Utility and three major consumer advocate groups that represent the interest of core customers, including the CPUC’s DRA, Aglet Consumer Alliance, and TURN. Beginning with the 2007-2008 winter season, the Utility will file an annual plan that prescribes the financial hedges that will be put in place on a rolling three-year basis (the current winter season and the next two subsequent winter seasons), consistent with pre-defined hedge program parameters. There will be five annual plan filings. The final annual plan (year five) will be filed for the 2011-2012 winter season and run through the 2013-2014 winter season. The CPUC approved the 2007-2008 winter season annual hedge plan on June 26, 2007.

Under the decision, all gains and losses associated with hedging purchases under an approved annual plan will be accounted for outside the CPIM. The Utility will consult with an advisory group, consisting of members of the consumer advocate groups, before submitting its annual hedging plan to the CPUC for approval. The Utility’s hedging costs will be recovered from its core procurement customers as long as the CPUC finds that the Utility implemented its hedges in accordance with the pre-approved plan.

The decision also modifies the CPIM to provide more benefits to customers in the event that the Utility purchases gas for less than the lower range of the market benchmark. The CPIM is modified to assign an 80%, instead of 75%, share of savings to customers and a 20%, instead of 25%, share to the Utility.

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 $31 million and $26 million at June 30, 2007 and December 31, 2006, respectively. The Utility's high, low, and average value-at-risk during the six months ended June 30, 2007 and for the year ended December 31, 2006 were approximately $31 million, $21 million, and $25 million, and $41 million, $22 million, and $33 million, respectively.

Convertible Subordinated Notes

At June 30, 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, April 15, and July 15, 2007, PG&E Corporation paid approximately $19 million of “pass-through dividends” to the holders of Convertible Subordinated Notes. Since no holders of the Convertible Subordinated Notes exercised the one-time right to require PG&E Corporation to repurchase the Convertible Subordinated Notes on June 30, 2007, PG&E Corporation has classified the Convertible Subordinated Notes as a noncurrent liability (in Noncurrent Liabilities - Long-Term Debt) in the accompanying Condensed Consolidated Balance Sheets as of June 30, 2007.

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. Dividend participation rights are recognized as financing cash flows on PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. 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 June 30, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $72 million and $79 million, respectively, of which $25 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $47 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 June 30, 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 less than $4 million, 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.

On January 1, 2007, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.” (See Note 2 of the Notes to the Condensed Consolidated Financial Statements for further discussion.)

For the period ended June 30, 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 10 of the Notes to the Condensed Consolidated Financial Statements, the Utility had an undiscounted environmental remediation liability of approximately $516 million at June 30, 2007 and approximately $511 million at December 31, 2006.

PG&E Corporation and the Utility are subject to various laws and regulations and 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 10 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 $66 million at June 30, 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 June 30, 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 June 30, 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

The California Air Resources Board

For more information regarding the resolution of this matter, see “Part II, Item 1. Legal Proceedings” in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 and “Part I, Item 3. Legal Proceedings” in the 2006 Annual Report.

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

On April 18, 2007, PG&E Corporation and Pacific Gas and Electric Company held their joint annual meeting of shareholders. Information regarding the voting results of the meetings is contained in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, Part II, Item 4, and such information is incorporated by reference into this report.

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 and six months ended June 30, 2007 was 2.96 and 2.91, respectively. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three and six months ended June 30, 2007 was 2.90 and 2.86, respectively. 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	Bylaws of Pacific Gas and Electric Company, as amended as of July 1, 2007

10.3*	Separation Agreement between Bruce R. Worthington and PG&E Corporation dated April 6, 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

Christopher P. Johns

Senior Vice President, Chief Financial Officer, and Treasurer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

G. Robert Powell

Vice President, Chief Financial Officer, and Controller

(duly authorized officer and principal accounting officer)

Dated: August 7, 2007

EXHIBIT INDEX

3	Bylaws of Pacific Gas and Electric Company, as amended as of July 1, 2007

10.3*	Separation Agreement between Bruce R. Worthington and PG&E Corporation dated April 6, 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.