q307_form10q.htm

10-Q 1 q307_form10q.htm THIRD QUARTER 2007 FORM 10Q q307_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 September 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 October 29, 2007:

PG&E Corporation				354,051,663 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 SEPTEMBER 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	18
	NOTE 5:		Shareholders' Equity	20
	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 Claims	23
	NOTE 10:		Commitments and Contingencies	24

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			32
	Forward-Looking Statements			34
	Results of Operations			36
	Liquidity and Financial Resources			43
	Contractual Commitments			47
	Capital Expenditures			47
	Off-Balance Sheet Arrangements			48
	Contingencies			49
	Regulatory Matters			49
	Risk Management Activities			54
	Critical Accounting Policies			55
	New Accounting Policies			56
	Accounting Pronouncements Issued But Not Yet Adopted			56
	Environmental and Legal Matters			56

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			56
ITEM 4.	CONTROLS AND PROCEDURES			56

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			58
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			58
ITEM 5.	OTHER INFORMATION			58
ITEM 6.	EXHIBITS			58

SIGNATURES				60

PART I. FINANCIAL INFORMATION

ITEM 1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended						Nine Months Ended
(in millions, except per share amounts)	September 30,						September 30,
	2007			2006			2007			2006
Operating Revenues
Electric	$	2,574		$	2,470		$	7,107		$	6,547
Natural gas		705			698			2,714			2,786
Total operating revenues		3,279			3,168			9,821			9,333
Operating Expenses
Cost of electricity		998			884			2,606			2,195
Cost of natural gas		281			298			1,431			1,539
Operating and maintenance		953			795			2,794			2,639
Depreciation, amortization, and decommissioning		465			456			1,325			1,291
Total operating expenses		2,697			2,433			8,156			7,664
Operating Income		582			735			1,665			1,669
Interest income		36			40			125			104
Interest expense		(196	)		(152	)		(571	)		(470	)
Other income (expense), net		7			(22	)		22			6
Income Before Income Taxes		429			601			1,241			1,309
Income tax provision		151			208			438			470
Net Income	$	278		$	393		$	803		$	839
Weighted Average Common Shares Outstanding, Basic		352			347			350			345
Net Earnings Per Common Share, Basic	$	0.77		$	1.09		$	2.23		$	2.36
Net Earnings Per Common Share, Diluted	$	0.77		$	1.09		$	2.22		$	2.33
Dividends Declared Per Common Share	$	0.36		$	0.33		$	1.08		$	0.99

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	September 30, 2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	784		$	456
Restricted cash		1,446			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $54 million in 2007 and $50 million in 2006)		2,424			2,343
Regulatory balancing accounts		601			607
Inventories:
Gas stored underground and fuel oil		262			181
Materials and supplies		160			149
Income taxes receivable		-			-
Prepaid expenses and other		404			716
Total current assets		6,081			5,867
Property, Plant, and Equipment
Electric		25,028			24,036
Gas		9,380			9,115
Construction work in progress		1,398			1,047
Other		16			16
Total property, plant, and equipment		35,822			34,214
Accumulated depreciation		(12,788	)		(12,429	)
Net property, plant, and equipment		23,034			21,785
Other Noncurrent Assets
Regulatory assets		4,530			4,902
Nuclear decommissioning funds		1,978			1,876
Other		458			373
Total other noncurrent assets		6,966			7,151
TOTAL ASSETS	$	36,081		$	34,803

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	September 30, 2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,165		$	759
Long-term debt, classified as current		-			281
Rate reduction bonds, classified as current		73			290
Energy recovery bonds, classified as current		350			340
Accounts payable:
Trade creditors		772			1,075
Disputed claims and customer refunds		1,648			1,709
Regulatory balancing accounts		708			1,030
Other		418			420
Interest payable		605			583
Income taxes payable		118			102
Deferred income taxes		88			148
Other		1,546			1,513
Total current liabilities		7,491			8,250
Noncurrent Liabilities
Long-term debt		7,674			6,697
Energy recovery bonds		1,675			1,936
Regulatory liabilities		3,879			3,392
Asset retirement obligations		1,511			1,466
Income taxes payable		233			-
Deferred income taxes		2,874			2,840
Deferred tax credits		101			106
Other		1,993			2,053
Total noncurrent liabilities		19,940			18,490
Commitments and Contingencies (Notes 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 377,063,946 common and 1,235,467 restricted shares in 2007 and issued 372,803,521 common and 1,377,538 restricted shares in 2006		6,044			5,877
Common stock held by subsidiary, at cost, 24,665,500 shares		(718	)		(718	)
Reinvested earnings		3,076			2,671
Accumulated other comprehensive loss		(4	)		(19	)
Total common shareholders' equity		8,398			7,811
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	36,081		$	34,803

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended
(in millions)	September 30,
	2007			2006
Cash Flows From Operating Activities
Net income	$	803		$	839
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction		1,419			1,343
Deferred income taxes and tax credits, net		(33	)		(172	)
Other deferred charges and noncurrent liabilities		281			(37	)
Gain on sale of assets		(1	)		(15	)
Net effect of changes in operating assets and liabilities:
Accounts receivable		(80	)		239
Inventories		(92	)		(8	)
Accounts payable		(322	)		(175	)
Accrued taxes and income taxes receivable		234			212
Regulatory balancing accounts, net		(238	)		404
Other current assets		120			(71	)
Other current liabilities		19			(325	)
Other		(32	)		6
Net cash provided by operating activities		2,078			2,240
Cash Flows From Investing Activities
Capital expenditures		(2,035	)		(1,729	)
Net proceeds from sale of assets		15			11
Decrease (increase) in restricted cash		(32	)		58
Proceeds from nuclear decommissioning trust sales		703			942
Purchases of nuclear decommissioning trust investments		(805	)		(1,040	)
Net cash used in investing activities		(2,154	)		(1,758	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility		600			50
Repayments under accounts receivable facility		(300	)		(310	)
Net issuance of commercial paper, net of $2 million discount in 2007		91			281
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(217	)		(214	)
Energy recovery bonds matured		(251	)		(224	)
Common stock issued		120			108
Common stock repurchased		-			(114	)
Common stock dividends paid		(367	)		(342	)
Other		38			(8	)
Net cash provided by (used in) financing activities		404			(773	)
Net change in cash and cash equivalents		328			(291	)
Cash and cash equivalents at January 1		456			713
Cash and cash equivalents at September 30	$	784		$	422
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	443		$	450
Income taxes paid, net		307			428
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	127		$	116
Assumption of capital lease obligation		-			408

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)
	Three Months Ended						Nine Months Ended
(in millions)	September 30,						September 30,
	2007			2006			2007			2006
Operating Revenues
Electric	$	2,574		$	2,470		$	7,107		$	6,547
Natural gas		705			698			2,714			2,786
Total operating revenues		3,279			3,168			9,821			9,333
Operating Expenses
Cost of electricity		998			884			2,606			2,195
Cost of natural gas		281			298			1,431			1,539
Operating and maintenance		950			793			2,788			2,637
Depreciation, amortization, and decommissioning		465			456			1,325			1,290
Total operating expenses		2,694			2,431			8,150			7,661
Operating Income		585			737			1,671			1,672
Interest income		33			36			116			94
Interest expense		(189	)		(144	)		(549	)		(447	)
Other income (expense), net		13			(15	)		38			16
Income Before Income Taxes		442			614			1,276			1,335
Income tax provision		159			236			458			509
Net Income		283			378			818			826
Preferred stock dividend requirement		4			3			10			10
Income Available for Common Stock	$	279		$	375		$	808		$	816

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	September 30, 2007 (Unaudited)			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	460		$	70
Restricted cash		1,446			1,415
Accounts receivable:
Customers (net of allowance for doubtful accounts of $54 million in 2007 and $50 million in 2006)		2,424			2,343
Related parties		7			6
Regulatory balancing accounts		601			607
Inventories:
Gas stored underground and fuel oil		262			181
Materials and supplies		160			149
Income taxes receivable		-			20
Prepaid expenses and other		402			714
Total current assets		5,762			5,505
Property, Plant, and Equipment
Electric		25,028			24,036
Gas		9,380			9,115
Construction work in progress		1,397			1,047
Total property, plant, and equipment		35,805			34,198
Accumulated depreciation		(12,773	)		(12,415	)
Net property, plant, and equipment		23,032			21,783
Other Noncurrent Assets
Regulatory assets		4,530			4,902
Nuclear decommissioning funds		1,978			1,876
Related parties receivable		24			25
Other		359			280
Total other noncurrent assets		6,891			7,083
TOTAL ASSETS	$	35,685		$	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)	September 30, 2007 (Unaudited)			December 31, 2006
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,165		$	759
Long-term debt, classified as current		-			1
Rate reduction bonds, classified as current		73			290
Energy recovery bonds, classified as current		350			340
Accounts payable:
Trade creditors		772			1,075
Disputed claims and customer refunds		1,648			1,709
Related parties		43			40
Regulatory balancing accounts		708			1,030
Other		403			402
Interest payable		599			570
Income taxes payable		157			-
Deferred income taxes		92			118
Other		1,374			1,346
Total current liabilities		7,384			7,680
Noncurrent Liabilities
Long-term debt		7,394			6,697
Energy recovery bonds		1,675			1,936
Regulatory liabilities		3,879			3,392
Asset retirement obligations		1,511			1,466
Income taxes payable		103			-
Deferred income taxes		2,936			2,972
Deferred tax credits		101			106
Other		1,867			1,922
Total noncurrent liabilities		19,466			18,491
Commitments and Contingencies (Notes 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		5,619			5,213
Accumulated other comprehensive loss		(1	)		(16	)
Total shareholders' equity		8,835			8,200
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	35,685		$	34,371

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended
(in millions)	September 30,
	2007			2006
Cash Flows From Operating Activities
Net income	$	818		$	826
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction		1,417			1,342
Deferred income taxes and tax credits, net		(35	)		(172	)
Other deferred charges and noncurrent liabilities		270			(65	)
Gain on sale of assets		(1	)		(15	)
Net effect of changes in operating assets and liabilities:
Accounts receivable		(82	)		239
Inventories		(92	)		(8	)
Accounts payable		(315	)		(176	)
Accrued taxes and income taxes receivable		228			113
Regulatory balancing accounts, net		(238	)		404
Other current assets		120			(71	)
Other current liabilities		35			(301	)
Other		(32	)		(5	)
Net cash provided by operating activities		2,093			2,111
Cash Flows From Investing Activities
Capital expenditures		(2,035	)		(1,729	)
Net proceeds from sale of assets		15			11
Decrease (increase) in restricted cash		(32	)		58
Proceeds from nuclear decommissioning trust sales		703			942
Purchases of nuclear decommissioning trust investments		(805	)		(1,040	)
Net cash used in investing activities		(2,154	)		(1,758	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility		600			50
Repayments under accounts receivable facility		(300	)		(310	)
Net issuance of commercial paper, net of $2 million discount in 2007		91			281
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(217	)		(214	)
Energy recovery bonds matured		(251	)		(224	)
Common stock dividends paid		(381	)		(345	)
Preferred stock dividends paid		(10	)		(10	)
Equity infusion from PG&E Corporation		200			-
Other		29			24
Net cash provided by (used in) financing activities		451			(748	)
Net change in cash and cash equivalents		390			(395	)
Cash and cash equivalents at January 1		70			463
Cash and cash equivalents at September 30	$	460		$	68
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)	$	416		$	423
Income taxes paid, net		403			562
Supplemental disclosures of noncash investing and financing activities
Assumption of capital lease obligation	$	-		$	408

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, 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 September 30, 2007
Decrease in interest expense on unrecognized tax benefits	$	(3	)	$	(2	)
Nine Months Ended September 30, 2007
Increase in interest expense on unrecognized tax benefits	$	8		$	3

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 nine months ended September 30, 2007 and 2006:

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

Stock options	$	2	$	3		$	1	$	2
Restricted stock		6		4			4		3
Performance shares		15		(1	)		10		(1	)
Total compensation expense (pre-tax)	$	23	$	6		$	15	$	4
Total compensation expense (after-tax)	$	14	$	4		$	9	$	2

	PG&E Corporation				Utility
	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2007		2006		2007		2006

Stock options	$	6	$	9	$	3	$	6
Restricted stock		19		15		12		11
Performance shares		15		20		9		14
Total compensation expense (pre-tax)	$	40	$	44	$	24	$	31
Total compensation expense (after-tax)	$	24	$	26	$	14	$	18

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 nine months ended September 30, 2007 and 2006 are as follows:

	Pension Benefits						Other Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
(in millions)	2007			2006			2007			2006

Service cost for benefits earned	$	55		$	59		$	7		$	7
Interest cost		139			128			20			18
Expected return on plan assets		(178	)		(160	)		(23	)		(23	)
Amortization of transition obligation ⁽¹⁾		-			-			7			7
Amortization of prior service cost ⁽¹⁾		12			13			3			4
Amortization of unrecognized (gain) loss ⁽¹⁾		1			6			(1	)		(1	)
Net periodic benefit cost	$	29		$	46		$	13		$	12


⁽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 the defined benefit pension plan, which are recorded to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”).

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006

Service cost for benefits earned	$	173		$	177		$	22		$	21
Interest cost		408			383			59			55
Expected return on plan assets		(533	)		(480	)		(72	)		(67	)
Amortization of transition obligation ⁽¹⁾		-			-			19			19
Amortization of prior service cost ⁽¹⁾		37			41			12			11
Amortization of unrecognized (gain) loss ⁽¹⁾		2			17			(7	)		(2	)
Net periodic benefit cost	$	87		$	138		$	33		$	37

⁽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 the 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 cash collateral paid or 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 currently being recovered through rates, SFAS No. 71 requires that the regulated enterprise record those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future must be recorded as regulatory liabilities.

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

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance At
	September 30,		December 31,
(in millions)	2007		2006

Energy recovery bond regulatory asset	$	1,914	$	2,170
Utility retained generation regulatory assets		964		1,018
Regulatory assets for deferred income tax		697		599
Environmental compliance costs		306		303
Unamortized loss, net of gain, on reacquired debt		276		295
Regulatory assets associated with plan of reorganization		124		147
Scheduling coordinator costs		101		136
Post-transition period contract termination costs		99		120
Other		49		114
Total regulatory assets	$	4,530	$	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 nine months ended September 30, 2007, the Utility recorded amortization of the ERB regulatory asset of approximately $256 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 are amortized over their respective lives, with a weighted average life of approximately 16 years. During the nine months ended September 30, 2007, the Utility recorded amortization of the Utility’s retained generation regulatory assets of approximately $54 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 periods ranging from 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 an 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 September 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 Utility’s plan of reorganization.

Current Regulatory Assets

As of September 30, 2007 and December 31, 2006, the Utility had current regulatory assets of approximately $189 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 nine months ended September 30, 2007, the Utility recorded amortization of the RRB regulatory asset of approximately $190 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
	September 30,		December 31,
(in millions)	2007		2006

Cost of removal obligation	$	2,503	$	2,340
Asset retirement costs		620		608
Public purpose programs		294		169
California Solar Initiative		136		-
Employee benefit plans		100		23
Price risk management		48		37
Other		178		215
Total regulatory liabilities	$	3,879	$	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.

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.

Price risk management liabilities consist of contracts to procure electricity and natural gas with terms in excess of one year that have been entered into in order to reduce commodity price risks and are accounted for as derivative instruments under SFAS No. 133. 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.

As of September 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 customers 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 September 30, 2007 and December 31, 2006, the Utility had current regulatory liabilities of approximately $301 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 amounts 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
	September 30,			December 31,
(in millions)	2007			2006

Electricity revenue and cost balancing accounts		$	440		$	501
Natural gas revenue and cost balancing accounts			161			106
Total		$	601		$	607

Regulatory Balancing Account Liabilities

	Balance At
	September 30,			December 31,
(in millions)	2007			2006

Electricity revenue and cost balancing accounts		$	658		$	951
Natural gas revenue and cost balancing accounts			50			79
Total		$	708		$	1,030

During the nine months ended September 30, 2007, the under-collection in the Utility's electricity revenue and cost balancing account assets decreased from December 31, 2006 mainly because actual revenues were higher than the authorized revenue requirement. This is consistent with seasonal demand changes with the under-collection decreasing during the summer months when usage of electricity rises. In addition, the Utility's electricity revenue and cost balancing account liabilities decreased during the nine month period as a result of CPUC authorized rate reductions designed to reduce the 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 September 30, 2007, neither were outstanding.

Convertible Subordinated Notes

At September 30, 2007, PG&E Corporation had outstanding approximately $280 million of 9.50% 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 18,558,059 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 January 15 through October 15, 2007, PG&E Corporation paid approximately $26 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 reclassified the Convertible Subordinated Notes as a noncurrent liability (in Noncurrent Liabilities - Long-Term Debt) in the accompanying Condensed Consolidated Balance Sheets effective as of that date.

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 operating 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 (in Other Income, Net). At September 30, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $67 million and $79 million, respectively, of which $25 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $42 million and $56 million, respectively, was classified as a noncurrent liability (in Noncurrent Liabilities - Other) in the accompanying Condensed Consolidated Balance Sheets.

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

In March 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.

These and other 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 September 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 September 30, 2007, there were approximately $185 million of letters of credit and $600 million of borrowings outstanding under the working capital facility. The available capacity under the working capital facility is further reduced by the $565 million of outstanding commercial paper as discussed below. On October 22 and November 1, 2007, the Utility repaid $400 million and $200 million, respectively, of borrowings under the working capital facility with excess cash on hand.

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 $1.0 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 September 30, 2007, the Utility had $565 million of commercial paper outstanding at an average yield of approximately 5.57%.

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 September 30, 2007 was approximately $73 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 September 30, 2007 was approximately $2.0 billion. The ERBs are scheduled to mature on December 25, 2012.

While PERF is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets (including the recovery property) of PERF 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 nine months ended September 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		803			818
Common stock issued		125			-
Common restricted stock amortization		19			-
Common stock dividends declared and paid		(253	)		(381	)
Common stock dividends declared but not yet paid		(127	)		-
Preferred stock dividends		-			(10	)
Tax benefit from share-based payment awards		23			14
Other comprehensive income		15			15
Equity infusion		-			200
Balance at September 30, 2007	$	8,398		$	8,835

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 nine months ended September 30, 2007, the Utility paid common stock dividends totaling $410 million, including $381 million of common stock dividends paid to PG&E Corporation and $29 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, July 15, and October 15, 2007, PG&E Corporation paid common stock dividends of $0.36 per share. The above dividend payments totaled $529 million, including $35 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, May 15, and August 15, 2007, the Utility paid cash dividends on various series of its preferred stock outstanding in the aggregate amount of $10 million. On September 19, 2007, the Board of Directors of the Utility declared cash dividends on various series of its preferred stock payable on November 15, 2007 to shareholders of record on October 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				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2007		2006		2007		2006

Net income	$	278	$	393	$	803	$	839
Less: distributed earnings to common shareholders		127		115		379		344
Undistributed earnings	$	151	$	278	$	424	$	495

Common shareholders earnings
*Basic*
Distributed earnings to common shareholders	$	127	$	115	$	379	$	344
Undistributed earnings allocated to common shareholders		143		264		402		469
Total common shareholders earnings, basic	$	270	$	379	$	781	$	813
*Diluted*
Distributed earnings to common shareholders	$	127	$	115	$	379	$	344
Undistributed earnings allocated to common shareholders		143		264		402		469
Total common shareholders earnings, diluted	$	270	$	379	$	781	$	813

Weighted average common shares outstanding, basic		352		347		350		345
9.50% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and participating securities, basic		371		366		369		364

Weighted average common shares outstanding, basic		352		347		350		345
Employee share-based compensation and accelerated share repurchase program ⁽¹⁾		1		2		2		4
Weighted average common shares outstanding, diluted		353		349		352		349
9.50% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and participating securities, diluted		372		368		371		368

Net earnings per common share, basic
Distributed earnings, basic ⁽²⁾	$	0.36	$	0.33	$	1.08	$	1.00
Undistributed earnings, basic		0.41		0.76		1.15		1.36
Total	$	0.77	$	1.09	$	2.23	$	2.36

Net earnings per common share, diluted
Distributed earnings, diluted	$	0.36	$	0.33	$	1.08	$	0.99
Undistributed earnings, diluted		0.41		0.76		1.14		1.34
Total	$	0.77	$	1.09	$	2.22	$	2.33


⁽¹⁾Includes approximately 1 million shares of PG&E Corporation common stock treated as outstanding in connection with accelerated share repurchases for the nine months ended September 30, 2006. The remaining shares relate to share-based compensation and are deemed to be outstanding under 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 number of shares outstanding rather than the actual number.

An insignificant number of options to purchase PG&E Corporation common stock were outstanding, but not included in the computation of diluted EPS for the three and nine months ended September 30, 2007 because the option exercise prices were above the average market price during these periods. All outstanding options to purchase PG&E Corporation common stock were included in the computation of diluted EPS for the three and nine months ended September 30, 2006 because the exercise prices of these options were below the average market price of PG&E Corporation common stock during these periods.

PG&E Corporation reflects the preferred dividends of subsidiaries as Other Expense for computation of both basic and diluted EPS.

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
(in millions)	September 30, 2007		December 31, 2006		September 30, 2007		December 31, 2006

Current Assets – Prepaid expenses and other	$	38	$	16	$	1	$	3
Other Noncurrent Assets – Other		48		37		14		8
Current Liabilities – Other		141		192		17		25
Noncurrent Liabilities – Other		32		50		8		-

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. They are recorded and recognized in income using accrual accounting. Therefore, expenses are recognized in 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				Nine Months Ended				Receivable (Payable) Balance Outstanding at
(in millions)	September 30,				September 30,				September 30,			December 31,
	2007		2006		2007		2006		2007			2006
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1	$	3	$	3	$	2		$	2
Utility employee benefit assets due from PG&E Corporation		-		-		-		-		29			25
Interest from PG&E Corporation on employee benefit assets		-		-		1		1		-			-
Utility expenses from:
Administrative services received from PG&E Corporation	$	31	$	24	$	83	$	72	$	(43	)	$	(40	)
Utility employee benefit asset contributions provided to PG&E Corporation		1		1		3		2		-			-

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

In connection with the Utility’s plan of 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 September 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 acquisition of Gateway. 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.

Since January 1, 2007, the Utility has received approximately $79 million (including interest) in cash-equivalent reductions to the Utility’s PX liability from four settlements approved by the FERC. During this period, the Utility has also received two cash distributions totaling to approximately $34 million related to a 2005 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 September 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 accounts receivable from the CAISO and the PX of approximately $0.5 billion. The amount held in escrow for

the payment of the remaining net disputed claims was $1.3 billion (including interest) as of September 30, 2007. The amount held in escrow is classified as Restricted Cash in the Condensed Consolidated Balance Sheets.

As of September 30, 2007, the Utility has accrued interest of approximately $551 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.

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 disputed claims, including 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 September 30, 2007, the undiscounted future expected power purchase agreement payments based on September 30, 2007 forward prices were as follows:

(in millions)
2007	$	582
2008		2,293
2009		2,215
2010		2,044
2011		1,870
Thereafter		12,813
Total	$	21,817

Payments made by the Utility under power purchase agreements amounted to approximately $2,367 million for the nine months ended September 30, 2007 and $1,863 million for the same period in 2006. The amounts 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 September 20, 2007, the CPUC issued a decision that modifies the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. The decision affects 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 changes, the decision modifies 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). The modified SRAC formula uses a market index formula based in part on forward market price estimates. The Utility is evaluating the new SRAC pricing formula to determine its effect on the energy payments that will be made to the non-settling QFs. Actual QF energy payments will depend on future natural gas and electricity prices. The adjustments to QF prices resulting from the CPUC’s decision will be reflected in the customers’ rates. (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	$	11
2008		50
2009		50
2010		50
2011		50
Thereafter		303
Total fixed capacity payments		514
Amount representing interest		(136	)
Present value of fixed capacity payments	$	378

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

Natural Gas Supply and Transportation Commitments

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

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

(in millions)
2007	$	468
2008		859
2009		68
2010		22
2011		14
Thereafter		7
Total	$	1,438

Payments for natural gas purchases and gas transportation services amounted to approximately $1,603 million for the nine months ended September 30, 2007 and $1,654 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. 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 September 30, 2007, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2007	$	21
2008		82
2009		83
2010		96
2011		72
Thereafter		462
Total	$	816

Payments for nuclear fuel amounted to approximately $82 million for the nine months ended September 30, 2007 and $41 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 September 30, 2007, the Utility’s estimated RMR agreement payments to CAISO could be approximately $18 million for the service months of October through December 2007. The Utility recovers these costs from customers.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, the self-generation incentive program, the California Solar Initiative program, energy efficiency programs and telecommunication contracts. At September 30, 2007, the future minimum payments related to other commitments and operating leases were as follows:

(in millions)
2007	$	102
2008		143
2009		18
2010		13
2011		11
Thereafter		35
Total	$	322

Payments for other commitments amounted to approximately $67 million and $73 million for the nine months ended September 30, 2007 and September 30, 2006, respectively.

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 September 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

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste no later than January 31, 1998 in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to provide for the disposal of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon (“Diablo Canyon”) and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”). The DOE failed to develop a permanent storage site by January 31, 1998. (As discussed below, the Utility, as well as other nuclear power plant owners, have sued the DOE for breach of contract.) Nevertheless, 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.

As a result of the DOE’s failure to develop a permanent storage site, the Utility applied for and received a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel through at least 2024. After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 that ordered the NRC to issue a supplemental environmental assessment report that considers the environmental consequences of a potential terrorist attack at Diablo Canyon and to review other contentions related to a terrorism threat raised by the appealing parties. In August 2007, the NRC staff issued a final supplemental environmental assessment report which concluded there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility. Although the NRC has not yet decided whether it will hold an evidentiary hearing on any of the other contentions raised by the appealing parties, the NRC recently affirmed its intent to complete the review required by the Ninth Circuit in early 2008.

The Utility expects to complete the dry cask storage facility and begin loading spent fuel 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.

The Utility’s lawsuit against the DOE seeks to recover the substantial costs the Utility has incurred, and continues to incur, to develop on-site storage at Diablo Canyon and Humboldt Bay Unit 3. Any amounts recovered from the DOE will be credited to customers. In October 2006, the U.S. Court of Federal Claims found the DOE had breached its contract and awarded the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004. The Utility has filed an appeal 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 to recover costs incurred after 2004 in future lawsuits against the DOE.

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. 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.

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 nine months ended September 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. The Utility’s issuer rating by Moody’s Investor Service is Baa1 and the Utility’s long-term issuer credit rating by Standard & Poor’s Rating Service is 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. At September 30, 2007, the Utility’s future severance costs are expected to range from $39 million to approximately $94 million, given the uncertainty of each of the aforementioned variables. The Utility has recorded a liability of $39 million as of September 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		15
Less: Payments		(10	)
Balance at September 30, 2007	$	39

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 $515 million at September 30, 2007 and approximately $511 million at December 31, 2006. The $515 million accrued at September 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 $178 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 $515 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 $816 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 $816 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, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

In July 2004, the U.S. Environmental Protection Agency (“EPA”) published regulations under Section 316(b) of the Clean Water Act that apply to existing electricity generation facilities that use over 50 million gallons of water per day, which typically include some form of "once-through" cooling in which water from natural bodies of water is used to cool a generating facility and the heated water is discharged back into the source. The Utility's Diablo Canyon power plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The EPA regulations are intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. The EPA regulations allow site-specific compliance determinations if a facility's cost of compliance is significantly greater than either the benefits to be achieved or the compliance costs considered by the EPA. The EPA regulations also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In June 2006, the California State Water Resources Control Board (“Water Board”) published a draft policy for California’s implementation of Section 316(b) that proposes to eliminate the EPA’s site-specific compliance options, although the draft state policy would permit environmental restoration as a compliance option for nuclear facilities if the installation of cooling towers would conflict with a nuclear safety requirement. 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 January 2007, the Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and held that a cost-benefit test could not

be used to comply with performance standards or to obtain a variance from the standards. The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard. The due date for seeking the U.S. Supreme Court’s review of the Second Circuit’s decision is November 3, 2007. The EPA has suspended its regulations. It is uncertain when the EPA will issue revised regulations, how the Second Circuit decision will affect the Water Board’s proposed policy, and when the Water Board will issue its final policy. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, the Utility may be forced to cease operations at Diablo Canyon if the installation of cooling towers is not technically or economically feasible.

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 is currently 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 (“RAR”), 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. Although the IRS has indicated it will complete its final RAR by the end of 2007, PG&E Corporation may not receive the RAR until the first quarter of 2008. 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. Various adjustments have been proposed, but such adjustments, if agreed to, will not have a material effect on the financial condition or results of operations of PG&E Corporation.

The California Franchise Tax Board is currently auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns. To date, no adjustments have been proposed.

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

PG&E Corporation has $247 million of remaining federal capital loss carry-forwards from the disposition of NEGT stock in 2004, which, if not used by December 2009, will expire. PG&E Corporation also has $2.1 billion of California capital loss carry-forwards, the majority of which, if not used by 2008, will expire.

California Labor Code Issues

Approximately 13,400 of the Utility’s employees are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, and the Service Employees International Union, Local 24/7. Employees in California are entitled to an unpaid, uninterrupted 30-minute, duty-free meal period for every four hours of work. California Labor Code Section 226.7 prohibits employers from requiring employees to work during any mandated meal. Employers who fail to provide the mandated meal period must provide the employee with one additional hour of pay at the employee's regular rate of compensation for each work day that the meal period is not provided. (If the employee worked during the 30-minute unpaid meal period, the employer must also pay the employee for this time.)

In April 2007, the California Supreme Court ruled that this California law requiring employers to pay an employee an additional hour of pay for each work day that a required meal is not provided is a “wage” rather than a penalty, subject to a three-year statute of limitations rather than the one-year statute of limitations for penalty payments (Murphy v. Kenneth Cole Productions, Inc., California Supreme Court, April 16, 2007). Prior to this decision, the Utility believed that its collective bargaining agreement with the IBEW, which did not provide certain employee groups a continuous 30-minute meal period before the completion of the fifth hour of work, preempted state law.

In July 2007, the Utility established a joint committee composed of IBEW and Utility representatives to review the Utility’s current collective bargaining agreements to ensure compliance with California labor law in light of the California Supreme Court’s ruling. In June 2007, the Utility and the IBEW reached an agreement under which those employees whose

shifts do not allow for a 30-minute meal break will be paid one hour of pay for each 30-minute meal period missed going back three years. As of September 30, 2007, the Utility has accrued approximately $20 million for payments to approximately 1,900 employees in connection with this agreement. The Utility is continuing to investigate whether other employees may be entitled to payment for a missed or delayed meal. Until this investigation is complete, the Utility is unable to determine the amount of loss it may incur in connection with this matter. The ultimate outcome of this matter may have a material adverse impact on PG&E Corporation’s and the Utility’s results of operations or financial condition.

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 Current Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately $67 million at September 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 September 30, 2007. The Utility had approximately $35.7 billion in assets at September 30, 2007 and generated revenues of approximately $9.8 billion in the nine months ended September 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 Nine Months Ended September 30, 2007

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three and nine months ended September 30, 2007 were $0.77 per share and $2.22 per share, respectively, compared to $1.09 per share and $2.33 per share, respectively, for the same periods in 2006. For the three and nine months ended September 30, 2007, PG&E Corporation’s net income decreased by approximately $115 million, or 29%, to $278 million, and by approximately $36 million, or 4%, to $803 million, respectively, compared to $393 million and $839 million, respectively, for the same periods in 2006.

The decreases in diluted EPS and net income for 2007 compared to 2006 are primarily due to events that increased 2006 results which were not repeated in 2007. These events include (1) the FERC’s 2006 approval of recovery of scheduling coordinator (“SC”) costs the Utility began incurring in 1998 (representing $55 million and $77 million of the difference between the comparable three-and nine-month periods, respectively), (2) the recovery of certain interest and litigation costs following the completion of the CPUC’s verification audit in 2006 (representing $39 million of the difference between both of the comparable three-and nine-month periods), and (3) a decrease in 2006 for the accrual of long-term disability benefits and the recognition in 2006 of a tax benefit from capital loss utilitization (representing $26 million of the difference between both of the comparable three-and nine-month periods). The impact of these events in 2007 was partially offset by increased revenues associated with the Utility’s return on equity (“ROE”) on additional capital investments authorized by the CPUC in the Utility’s General Rate Case (“GRC”) effective January 1, 2007, and by the FERC in the Utility’s transmission owner rate

case, effective March 1, 2007 ($33 million and $92 million for the three and nine months ended September 30, 2007, respectively).

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, 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. In June 2007, the FERC approved the Utility’s offer of settlement that set the annual electric transmission retail revenue requirement at $674 million, effective March 1, 2007, an increase of approximately $68 million over the prior authorized amount. During the quarter ended September 30, 2007, several CPUC decisions were issued that have or will impact PG&E Corporation’s and the Utility’s financial results. These include decisions to establish incentive ratemaking mechanisms relating to energy efficiency programs, a multi-party settlement agreement (known as the Gas Accord IV) that establishes the Utility’s natural gas transmission and storage rates and associated revenue requirements for 2008 through 2010, and to order the Utility to refund to customers approximately $35 million in charges that the CPUC found had been improperly billed. In addition, in September 2007, the FERC issued an order accepting the Utility’s proposed electric transmission owner rates effective March 1, 2008, subject to hearing and refund, that would represent a revenue increase of approximately $78 million over March 1, 2007 rates. The outcome of various other regulatory proceedings also could 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, including a requested ROE of 11.70%. (See “2008 Cost of Capital Proceeding” below.) 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 common equity ratio of 52% 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”). The Utility’s current credit ratings from Moody’s and S&P are Baa1 and BBB+, respectively. On April 9, 2007, Moody’s placed the Utility’s credit rating on watch for possible upgrade.

·	The Ability of the Utility to Control Operating Costs and Achieve Operational Excellence and Improved Customer Service. The Utility’s GRC provides revenues anticipated to provide recovery of forecasted operating costs and a return of, and on, invested capital. The Utility’s actual costs to operate its facilities and provide service to its customers may differ materially from the forecasted costs used in the GRC to determine authorized revenue requirements and set rates. In addition, the forecasted costs used to set the revenue requirements authorized in the GRC reflected assumptions about future operating cost efficiencies expected to be achieved. In 2005, the Utility began to identify and implement various initiatives to increase cost efficiencies, achieve operational excellence, and improve customer service. The Utility periodically reviews and makes adjustments to the scope and timing of implementation of theses initiatives resulting in changes to the level of forecasted costs and benefits. To the extent that the level of forecasted benefits declines, the Utility seeks to offset such decline through the identification of new initiatives or other efforts to achieve cost savings. There can be no assurance that the Utility will realize the full extent of the forecasted benefits of its initiatives or offset such decline through other efforts.

·	The Amount and Timing of Capital Expenditures. The CPUC authorized the Utility to make substantial capital expenditures in connection with the construction or acquisition of new generation facilities 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. Earnings from rate base additions would be partially offset by associated depreciation and tax expense. Further, if the CPUC or the FERC disallows a material portion of the Utility’s capital expenditures, the Utility would be unable to recover the disallowed expenditures and would forego earning a return on the disallowed amounts. Finally, if the Utility’s capital expenditures otherwise exceed authorized amounts, the Utility may not be able to fully recover the excess amounts which, in turn, would negatively affect the Utility’s ability to earn its authorized return on rate base.

·	The Amount and Timing of Debt and Equity 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 Utility expects it will issue $400 million to $600 million of additional long-term debt during the remainder of 2007. The Utility’s additional financing needs after 2007 will be affected by the amount and timing of capital expenditures and, in addition, will be affected by the amount and timing of interest payments required to be made in connection with the disputed claims made in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Disputed Claims”) arising from the 2000-2001 California energy crisis upon settlement or resolution of the pending FERC and judicial proceedings. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.) 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 any such financing. PG&E Corporation plans to contribute equity to the Utility to maintain the Utility’s authorized capital structure. The timing and amount of these equity contributions will affect the timing and amount of any new PG&E Corporation equity issuances which, in turn, will affect PG&E Corporation’s results of operations and financial condition. (See further discussion under “Liquidity and Financial Resources” below.)

·	Changes in Environmental and Legal 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 nine months ended September 30, 2007, the Utility recorded approximately $17 million related to environmental remediation expenses. In addition, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits, including the matters discussed in Note 10. (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 systems and customer service;

·	whether the Utility’s planned capital investment projects are completed within authorized cost amounts;

·	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 insurance or other third parties;

·	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 nine-month periods ended September 30, 2007 and 2006.

	(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2007			2006			2007			2006

Utility
Electric operating revenues	$	2,574		$	2,470		$	7,107		$	6,547
Natural gas operating revenues		705			698			2,714			2,786
Total operating revenues		3,279			3,168			9,821			9,333
Cost of electricity		998			884			2,606			2,195
Cost of natural gas		281			298			1,431			1,539
Operating and maintenance		950			793			2,788			2,637
Depreciation, amortization, and decommissioning		465			456			1,325			1,290
Total operating expenses		2,694			2,431			8,150			7,661
Operating income		585			737			1,671			1,672
Interest income		33			36			116			94
Interest expense		(189	)		(144	)		(549	)		(447	)
Other income (expense), net⁽¹⁾		9			(18	)		28			6
Income before income taxes		438			611			1,266			1,325
Income tax provision		159			236			458			509
Income available for common stock	$	279		$	375		$	808		$	816
PG&E Corporation, Eliminations and Other⁽²⁾
Operating revenues	$	-		$	-		$	-		$	-
Operating expenses		3			2			6			3
Operating loss		(3	)		(2	)		(6	)		(3	)
Interest income		3			4			9			10
Interest expense		(7	)		(8	)		(22	)		(23	)
Other income (expense), net		(2	)		(4	)		(6	)		-
Loss before income taxes		(9	)		(10	)		(25	)		(16	)
Income tax benefit		(8	)		(28	)		(20	)		(39	)
Net income (loss)	$	(1	)	$	18		$	(5	)	$	23
Consolidated Total⁽²⁾
Operating revenues	$	3,279		$	3,168		$	9,821		$	9,333
Operating expenses		2,697			2,433			8,156			7,664
Operating income		582			735			1,665			1,669
Interest income		36			40			125			104
Interest expense		(196	)		(152	)		(571	)		(470	)
Other income (expense), net⁽¹⁾		7			(22	)		22			6
Income before income taxes		429			601			1,241			1,309
Income tax provision		151			208			438			470
Net income	$	278		$	393		$	803		$	839


⁽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 nine months ended September 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						Nine Months Ended
	September 30,						September 30,
(in millions)	2007			2006			2007			2006

Electric revenues	$	3,172		$	3,055		$	8,765		$	8,119
DWR pass-through revenue⁽¹⁾		(598	)		(585	)		(1,658	)		(1,572	)
Total electric operating revenues	$	2,574		$	2,470		$	7,107		$	6,547
Total electricity sales (in Gigawatt hours)		18,688			18,644			49,643			49,472


⁽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 September 30, 2007 by approximately $104 million, or approximately 4%, 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 $250 million. (See “Cost of Electricity” below.)

·	The Utility recognized an increase to its authorized 2007 base revenue requirements of approximately $58 million as authorized in the 2007 GRC.

·	An increase in transmission revenues, including an increase in revenues as authorized in the FERC transmission owner rate case, increased electric operating revenues by approximately $39 million. (See “Regulatory Matters - FERC Transmission Owner Rate Cases” below.)

·	Other electric operating revenues, including those associated with public purpose programs, and recovery of net interest costs related to Disputed Claims, increased by approximately $12 million. (See “Interest Income” and “Interest Expense” below and Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

These increases were partially offset by the following:

·	A decrease of approximately $54 million in transmission revenues due to a decrease in the number of reliability must run (“RMR”) agreements with the CAISO and the associated costs. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	In 2006, the Utility recognized approximately $136 million following the FERC’s order allowing the Utility to recover SC costs the Utility incurred from April 1998 through December 2005, but no similar amount was recognized in 2007.

·	In 2006, upon completion of the CPUC’s 2005 Annual Electric True-up (“AET”) verification audit, the Utility recognized approximately $65 million of revenues due to the recovery of net interest related to Disputed Claims for the period between the effective date of the Utility’s plan of reorganization under Chapter 11 and the first issuance of the energy recovery bonds (“ERBs”), and for certain energy supplier refund litigation costs, but no similar amount was recognized in 2007.

The Utility’s electric operating revenues increased in the nine months ended September 30, 2007 by approximately $560 million, or approximately 9%, 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 $612 million. (See “Cost of Electricity” below.)

·	The Utility recognized an increase to its authorized 2007 base revenue requirements of approximately $167 million, as authorized in the 2007 GRC.

·	An increase in transmission revenues, including an increase in revenues as authorized in the FERC transmission owner rate case, increased electric operating revenues by approximately $67 million (See “Regulatory Matters - FERC Transmission Owner Rate Cases” below.)

·	Other electric operating revenues, including those associated with public purpose programs, and recovery of net interest costs related to Disputed Claims, increased by approximately $71 million. (See “Interest Income” and “Interest Expense” below and Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

These increases were partially offset by the following:

·	A decrease of approximately $156 million in transmission revenues due to a decrease in the number of RMR agreements with the CAISO and the associated costs. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	In 2006, the Utility recognized approximately $136 million following the FERC’s order allowing the Utility to recover SC costs the Utility incurred from April 1998 through September 2006, but no similar amount was recognized in 2007.

·	In 2006, upon completion of the 2005 AET verification audit, the Utility recognized approximately $65 million of revenues due to the recovery of net interest costs related to Disputed Claims for the period between the effective date of the Utility’s plan of reorganization under Chapter 11 and the first issuance of ERBs, and for certain energy supplier refund litigation costs, with no similar amount in 2007.

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 owner 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						Nine Months Ended
(in millions)	September 30,						September 30,
	2007			2006			2007			2006
Cost of purchased power	$	990		$	895		$	2,609		$	2,325
Proceeds from surplus sales allocated to the Utility		(26	)		(46	)		(112	)		(245	)
Fuel used in own generation		34			35			109			115
Total cost of electricity	$	998		$	884		$	2,606		$	2,195
Average cost of purchased power per kWh	$	0.088		$	0.081		$	0.087		$	0.079
Total purchased power (in millions of kWh)		11,291			11,037			29,975			29,295

In the three months ended September 30, 2007, the Utility’s cost of electricity increased by approximately $114 million, or 13%, compared to the same period in 2006. This increase was primarily driven by a 9% increase in the average cost of purchased power. The average cost of purchased power increased $0.007 per kilowatt-hour (“kWh”) 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, the Utility increased power purchased from third parties primarily due to a decrease in lower cost hydroelectric power resulting from less than average precipitation as compared to the same period in 2006. The increase was partially offset by a decrease in costs associated with RMR agreements. (See “Electric Operating Revenues” above and Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

In the nine months ended September 30, 2007, the Utility's total cost of electricity increased by approximately $411 million, or 19%, compared to the same period in 2006. This increase was primarily driven by a 10% increase in the average cost of purchased power. The average cost of purchased power increased $0.008 per kWh primarily due to higher energy payments made to QFs after their five-year fixed price contracts expired during the summer of 2006. In addition, the Utility increased power purchased from third parties primarily due to a decrease in lower cost hydroelectric power resulting from less than average precipitation during 2007 as compared to the same period in 2006. The increase was partially offset by a decrease in costs associated with RMR agreements. (See “Electric Operating Revenues” above and Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

The Utility's cost of electricity in 2007 and in future periods will depend upon electricity and natural gas 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 issued a decision in September 2007 that modifies the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. The new pricing formula will affect the cost of purchases from certain QFs. Changes in the costs will be reflected in the customers’ rates. (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. The Utility expects that it will recover its incremental costs to comply with future federal and state greenhouse gas emissions regulations from the Utility’s customers under the CPUC’s ratemaking standards applicable to electricity procurement costs. The statewide cap on greenhouse gas emissions is scheduled to be adopted by the end of 2007, and initial proposals for applying the statewide cap to categories of sources of greenhouse gas emissions in the state are expected to be announced during 2008.

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 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				Nine Months Ended
(in millions)	September 30,				September 30,
	2007		2006		2007		2006
Bundled natural gas revenues	$	620	$	615	$	2,469	$	2,565
Transportation service-only revenues		85		83		245		221
Total natural gas operating revenues	$	705	$	698	$	2,714	$	2,786
Total bundled natural gas sales (in millions of Mcf)		36		36		200		202

In the three months ended September 30, 2007, the Utility's natural gas operating revenues increased by approximately $7 million, or 1%, compared to the same period in 2006. This is primarily due to an increase in base revenue requirements as authorized in the 2007 GRC.

In the nine months ended September 30, 2007, the Utility's natural gas operating revenues decreased by approximately $72 million, or 3%, compared to the same period in 2006. This is primarily due to a decrease in bundled natural gas revenues of approximately $96 million, or 4%, due to a decrease in the cost of natural gas, which is passed through to customers (see “Cost of Natural Gas” below). This decrease is partially offset by an increase in base revenue requirements as authorized in the 2007 GRC.

Future natural gas operating revenues will be impacted by changes in the cost of natural gas, throughput volume, and other factors. For 2008 through 2010, as discussed under “Regulatory Matters - Natural Gas Transmission and Storage Rate Case” below, the 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.

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				Nine Months Ended
(in millions)	September 30,				September 30,
	2007		2006		2007		2006
Cost of natural gas sold	$	239	$	265	$	1,299	$	1,435
Cost of natural gas transportation		42		33		132		104
Total cost of natural gas	$	281	$	298	$	1,431	$	1,539
Average cost per Mcf of natural gas sold	$	6.64	$	7.36	$	6.50	$	7.10
Total natural gas sold (in millions of Mcf)		36		36		200		202

In the three months ended September 30, 2007, the Utility's total cost of natural gas decreased by approximately $17 million, or 6%, compared to the same period in 2006, primarily due to a decrease in the average market price of natural gas sold of approximately $0.72 per Mcf, where Mcf equals one thousand cubic feet, or 10%. The price of natural gas has declined due to a relatively mild hurricane season in 2007 as compared to industry forecasts.

In the nine months ended September 30, 2007, the Utility's total cost of natural gas decreased by approximately $108 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 $0.60 per Mcf, or 8%. This decrease was primarily due to significantly higher average market prices in the beginning of 2006 as a result of damage to production facilities caused by severe weather, resulting in a reduction in natural gas supply as compared the same period in 2007. In addition, the price of natural gas has declined due to a relatively mild hurricane season in 2007 as compared to industry forecasts.

The Utility's cost of natural gas in 2007 and subsequent periods will be primarily determined by market forces in North America. 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 September 30, 2007, the Utility’s operating and maintenance expenses increased by approximately $157 million, or 20%, compared to the same period in 2006, mainly due to the following factors:

·	An increase of approximately $18 million in payments made for customer assistance programs primarily due to increased customer participation in these programs.

·	An increase of approximately $13 million due to maintenance expenses partially related to the management of vegetation in the Utility’s service territory.

·	An increase of approximately $11 million related to distribution expenses partially due to the implementation of information systems to improve customer service.

·	An increase of approximately $20 million related to increased customer contact, billing, and collection costs.

·	An increase of approximately $21 million related to higher labor costs.

·	An increase of approximately $10 million related to outside consulting services and contracts primarily related to information systems and advertising.

·	An increase of approximately $7 million related to California labor code compliance for certain Utility employees covered under collective bargaining agreements. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	An additional accrual of approximately $12 million as a result of the CPUC's order in the Delayed Billing Investigation to provide refunds to customers for failure to issue bills at regular intervals. (See “Regulatory Matters - Delayed Billing Investigation” below.)

·	In 2006, the Utility reduced its accrual for long-term disability benefits by approximately $11 million reflecting changes in sick leave eligibility rules, but there was no similar adjustment in 2007.

During the nine months ended September 30, 2007, the Utility’s operating and maintenance expenses increased by approximately $151 million, or 6%, compared to the same period in 2006, mainly due to the net effect of the following factors:

·	An increase of approximately $61 million in payments made for customer assistance programs, primarily due to increased customer participation in these programs.

·	An increase of approximately $26 million related to distribution expenses primarily due to the implementation of information systems to improve customer service, creation of new dispatch and scheduling stations, and management of vegetation in the Utility’s service territory.

·	An increase of approximately $25 million related to increased customer contact, billing, and collection costs.

·	An increase of approximately $25 million related to higher labor costs.

·	An increase of approximately $21 million related to outside consulting services primarily related to information systems support and advertising.

·	An increase of approximately $20 million related to California labor code compliance for certain Utility employees covered under collective bargaining agreements. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	An additional accrual of approximately $12 million as a result of the CPUC's order in the Delayed Billing Investigation to provide refunds to customers for failure to issue bills at regular intervals. (See “Regulatory Matters - Delayed Billing Investigation” below.)

·	In 2006, the Utility reduced its accrual for long-term disability benefits by approximately $11 million reflecting changes in the sick leave eligibility rules, but there was no similar adjustment in 2007.

·	A decrease of approximately $73 million in pension expense consistent with annual pension contributions as approved by the CPUC in June 2006. Pension expense was also lower because the Utility earned a higher return on pension plan assets in 2007 as compared to the same period in 2006.

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, material costs, and various other administrative and general expenses. The Utility anticipates that it will incur higher material, permitting, and labor costs in the future as well as higher costs to operate and maintain its aging infrastructure. The Utility also expects that its operating and maintenance expenses, including severance costs, will increase as the Utility continues to implement initiatives to achieve operational excellence and improved customer service. (See further discussion of severance costs in Note 10 of the Notes to the Condensed Consolidated Financial Statements.) The Utility periodically reviews and makes adjustments to the scope and timing of implementation of these initiatives resulting in changes to the level of forecasted costs and benefits. To the extent that the level of forecasted benefits declines, the Utility seeks to offset such decline through the identification of new initiatives or other efforts to achieve cost savings. There can be no assurance that the Utility will realize the full extent of the forecasted benefits of its initiatives or offset such decline through other efforts. For the remainder of 2007 and in subsequent periods, the Utility expects that it will incur higher expenses to comply with the requirements of renewed hydroelectric generation licenses and to complete the construction of the dry cask storage facility at Diablo Canyon. The Utility’s operating and maintenance expenses will also increase in the first quarter of 2008 due to the planned refueling outage at Diablo Canyon Unit 2. The Utility anticipates that the refueling outage will last at least 66 days, longer than the average outage duration, in order for the Utility to replace the steam generators.

Depreciation, Amortization, and Decommissioning

In the three and nine months ended September 30, 2007, the Utility's depreciation, amortization, and decommissioning expenses increased by approximately $9 million and $35 million, or 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 and subsequent periods 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 September 30, 2007, the Utility’s interest income decreased by approximately $3 million, or 8%, compared to the same period in 2006 primarily due to an August 31, 2006 FERC decision approving recovery of SC costs, including interest, with no similar amount in 2007.

In the nine months ended September 30, 2007, the Utility’s interest income increased by approximately $22 million, or 23%, compared to the same period in 2006. 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. This increase was offset by an August 31, 2006 FERC decision approving recovery of SC costs, including interest, with no similar amount in 2007.

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

Interest Expense

In the three and nine months ended September 30, 2007, the Utility’s interest expense increased by approximately $45 million and $102 million, or 31% and 23%, respectively, compared to the same periods in 2006, primarily due to an increase in interest expense related to Disputed Claims. (See “Electric Operating Revenues” above and Note 9 of the Notes to the Condensed Consolidated Financial Statements for further discussion.) In addition, interest expense increased due to interest related to the additional $700 million in Senior Notes issued in March 2007. These increases were partially offset by lower

interest expense on the Rate Reduction Bonds and the ERBs due to their declining balances.

The Utility’s interest expense in 2007 and subsequent periods will be impacted by changes in interest rates as the Utility’s short-term debt and a portion of its long-term debt 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. (See “Liquidity and Financial Resources” below.)

Income Tax Expense

In the three months ended September 30, 2007, the Utility's income tax expense decreased by approximately $77 million, or 33%, compared to the same period in 2006, primarily due to the decrease in pre-tax income of $172 million and an increase in tax deductible decommissioning expense in 2007 as compared to the same period in 2006. The effective tax rates for the three months ended September 30, 2007 and 2006 were 36.0% and 38.4%, respectively.

In the nine months ended September 30, 2007, the Utility's income tax expense decreased by approximately $51 million, or 10%, compared to the same period in 2006, primarily due to the decrease in pre-tax income of $59 million and an increase in tax deductible decommissioning expense in 2007 as compared to the same period in 2006. The effective tax rates for the nine months ended September 30, 2007 and 2006 were 35.9% and 38.1%, 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 nine months ended September 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 September 30, 2007, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $784 million and restricted cash of approximately $1.4 billion. At September 30, 2007, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $324 million; the Utility had cash and cash equivalents of approximately $460 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 as well as deposits made by customers and other third parties under certain agreements. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in institutional money market funds.

As of September 30, 2007, PG&E Corporation and the Utility had credit facilities totaling $200 million and $2 billion, respectively. Subject to obtaining commitments from existing or new lenders and satisfying other conditions, PG&E Corporation and the Utility may increase the aggregate lender commitments under the facilities to $300 million and $3 billion, respectively. As of September 30, 2007, the Utility had $185 million of letters of credit outstanding, $600 million of borrowings outstanding under its credit facility (“working capital facility”), and $565 million of outstanding commercial paper. On June 28, 2007, the Utility increased its borrowing capacity under the commercial paper program from $1.0 billion to $1.75 billion. On October 22 and November 1, 2007, the Utility repaid $400 million and $200 million, respectively, of borrowings under the working capital facility with excess cash on hand. The Utility’s outstanding letters of credit and commercial paper are backed by its working capital facility.

The Utility seeks to maintain its credit ratings to provide liquidity through efficient access to financial and trade credit, and to reduce financing costs. PG&E Corporation and the Utility seek to maintain the Utility’s CPUC-authorized capital structure which includes a 52% equity component. The Chapter 11 Settlement Agreement requires the CPUC to authorize a minimum 52% common equity ratio (and a minimum ROE for the Utility of 11.22%) until the Utility receives a credit rating of “A3” from Moody’s or “A-” from S&P. The Utility’s current credit ratings from Moody’s and S&P are Baa1 and BBB+, respectively. On April 9, 2007, Moody’s placed the Utility’s credit rating on watch for possible upgrade.

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.

The Utility currently plans to issue approximately $400 million to $600 million of long-term debt in the fourth quarter of 2007. In addition, subject to the factors described below, the Utility forecasts that it will issue approximately $1 billion in long-term debt annually for each of the next four years (2008-2011), primarily to finance forecasted capital expenditures.

The Utility also estimates that it will need to increase its amount of common equity to maintain the 52% authorized common equity component of its capital structure and ensure that it 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.

PG&E Corporation anticipates that it will partially fund these equity infusions from the proceeds of common stock issued (1) upon exercise of employee stock options, (2) to the trustee of PG&E Corporation’s 401(k) plan for employee-participant accounts, and (3) under the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan (“DRSPP”). During the nine months ended September 30, 2007, PG&E Corporation issued 3,599,443 shares of common stock upon the exercise of employee stock options and for the account of 401(k) plan participants, generating approximately $120 million of cash. The trustee of the 401(k) plan began purchasing shares for the 401(k) plan directly from PG&E Corporation in May 2007 and PG&E Corporation started issuing additional shares under its DRSPP in October 2007. PG&E Corporation will continue to evaluate how to best fund the Utility’s future equity needs, which may result in equity and debt issuances in addition to the equity sources discussed above.

The amount and timing of the Utility’s financing needs 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; and (3) the timing of the resolution of the Disputed Claims (upon settlement or the conclusion of the FERC and judicial proceedings) and the amount of interest on these claims that the Utility will be required to pay. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Dividends

During the nine months ended September 30, 2007, the Utility paid common stock dividends of $410 million. Approximately $381 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 holds approximately 7% of the Utility's common stock.

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, July 15, and October 15, 2007, PG&E Corporation paid common stock dividends in the aggregate amount of $529 million, including approximately $35 million to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation that holds approximately 7% of PG&E Corporation’s common stock.

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 nine months ended September 30, 2007 and 2006 were as follows:

	Nine Months Ended
(in millions)	September 30,
	2007			2006
Net income	$	818		$	826
Adjustments to reconcile net income to net cash provided by operating activities		1,651			1,090
Changes in operating assets and liabilities, and other		(376	)		195
Net cash provided by operating activities	$	2,093		$	2,111

In the nine months ended September 30, 2007, net cash provided by operating activities decreased by approximately $18 million from the same period in 2006, primarily due to an approximately $180 million decrease in cash settlements from energy suppliers and a power plant owner, from $270 million in the nine months ended September 30, 2006 to $90 million in the nine months ended September 30, 2007. This change was partially offset by a decrease of approximately $105 million in tax payments from $560 million in the nine months ended September 30, 2006 to $455 million in the same period in 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 nine months ended September 30, 2007 and 2006 were as follows:

	Nine Months Ended
(in millions)	September 30,
	2007			2006
Capital expenditures	$	(2,035	)	$	(1,729	)
Net proceeds from sale of assets		15			11
Decrease (increase) in restricted cash		(32	)		58
Other investing activities		(102	)		(98	)
Net cash used in investing activities	$	(2,154	)	$	(1,758	)

Net cash used in investing activities increased by approximately $396 million in the nine months ended September 30, 2007 compared to the same period in 2006, primarily due to an increase of approximately $306 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 $100 million less from escrow in the nine months ended September 30, 2007 upon settlement of Disputed Claims, compared to the same period in 2006.

Financing Activities

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

	Nine Months Ended
	September 30,
(in millions)	2007			2006

Borrowings under accounts receivable facility and working capital facility	$	600		$	50
Repayments under accounts receivable facility		(300	)		(310	)
Net issuance of commercial paper, net of $2 million discount in 2007		91			281
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(217	)		(214	)
Energy recovery bonds matured		(251	)		(224	)
Common stock dividends paid		(381	)		(345	)
Preferred dividends paid		(10	)		(10	)
Equity infusion from PG&E Corporation		200			-
Other		29			24
Net cash provided by (used in) financing activities	$	451		$	(748	)

In the nine months ended September 30, 2007, net cash provided by financing activities increased by approximately $1.2 billion 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 for net proceeds of approximately $690 million with no similar issuance in 2006.

·	In August 2007, as interest rates in the commercial paper market increased, the Utility borrowed $600 million under its $2 billion working capital facility compared to $50 million in borrowings in 2006.

·	As the Utility increased its borrowings under its working capital facility, the Utility’s net issuance of commercial paper decreased from $281 million in 2006 to only $91 million in 2007.

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

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 flows associated with operating activities for the nine months ended September 30, 2007 and 2006.

Investing Activities

PG&E Corporation, on a stand-alone basis, did not have any material cash flows associated with investing activities for the nine months ended September 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 nine months ended September 30, 2007 and 2006 were as follows:

	Nine Months Ended
	September 30,
(in millions)	2007			2006

Borrowings under accounts receivable facility and working capital facility	$	600		$	50
Repayments under accounts receivable facility		(300	)		(310	)
Net issuance of commercial paper, net of $2 million discount in 2007		91			281
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 million in 2007		690			-
Rate reduction bonds matured		(217	)		(214	)
Energy recovery bonds matured		(251	)		(224	)
Common stock issued		120			108
Common stock repurchased		-			(114	)
Common stock dividends paid		(367	)		(342	)
Other		38			(8	)
Net cash provided by (used in) financing activities	$	404		$	(773	)

During the nine months ended September 30, 2007, PG&E Corporation's consolidated net cash provided by financing activities increased by approximately $1.2 billion compared to the same period in 2006. The decrease in cash used after consideration of the Utility’s cash flows provided by financing activities, was primarily due to $114 million paid as additional consideration for the 2005 repurchase of common stock in the first nine 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 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 $2.9 billion in 2007. During the nine months ended September 30, 2007, the Utility incurred capital expenditures of approximately $2.0 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 $16.9 billion. For 2008, the Utility projects a weighted average rate base of $18.7 billion.

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 received in mid-August 2007 are currently being evaluated and the Utility plans to conduct pilot testing with selected vendors. If the request for proposals and pilot testing yield feasible technical and economic results, 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 and amount 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 at 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 indemnity obligations of National Energy & Gas Transmission, Inc., 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 its 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 September 30, 2007 and December 31, 2006:

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

September 30, 2007	$	307	$	91	$	216		2	$	89
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 2007 GRC 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 applications for rehearing do not stay the effectiveness of, or the Utility’s compliance with, the 2007 GRC decision. The CPUC is scheduled to vote on the disposition of the applications for rehearing at its meeting to be held on November 1, 2007.

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 establishes (1) the proportions of common equity, preferred equity, and debt that will comprise the Utility's total authorized capital structure, (2) the rate of return that the Utility is authorized to earn on the rate base, and (3) 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 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 and associated rate changes. On September 28, 2007, FERC issued an order accepting the proposed rates, subject to hearing and refund, effective March 1, 2008. These rates represent a revenue increase of approximately $78 million over current authorized rates.

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

Rulemaking Proceeding to Modify QF Pricing and Policies

On September 20, 2007, the CPUC issued a decision that modifies the CPUC’s policies and pricing mechanisms applicable to the investor-owned electric utilities’ purchase of energy and capacity from certain QFs. The decision affects 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 changes, the decision modifies 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). The modified SRAC formula uses a market index formula based in part on forward market price estimates. The Utility is evaluating the new SRAC pricing formula to determine its effect on the energy payments that will be made to the non-settling QFs. Actual QF energy payments will depend on future natural gas and electricity prices. The adjustments to QF prices resulting from the CPUC’s decision will be reflected in the customers’ rates.

The decision also establishes a “Prospective QF Program” for new QFs and QFs whose existing contracts will expire. Under this program, there will be two alternative standard power purchase contract options available to QFs. Utilities will be required to execute such contracts for QFs that are 20 megawatts (“MW”) or larger unless the utility can demonstrate that the capacity is not needed, after meeting and conferring with a group composed of non-market participants who consult and review the details of the Utility’s procurement strategy, contracts, and processes. Utilities must accept such contracts with small QFs (i.e., QFs that are less than 20 MW or that (i) offer equivalent annual energy deliveries of 131,400 megawatt-hours, (ii) consume at least 25 percent of the power internally, and (iii) sell 100 percent of the surplus to the utility) unless the purchase would exceed a utility-specific cap on purchases of capacity from small QFs. (The Utility’s cap on purchases of capacity from small QFs is 216.6 MW.) QFs also will continue to have the option to participate in the utilities’ generation resource solicitations or negotiate a bilateral agreement with a utility.

On October 25, 2007, the Utility, along with the other investor-owned electric utilities, TURN and the CPUC’s Division of Ratepayer Advocates (“DRA”), filed an application for rehearing of the decision. The application alleges that: (1) the CPUC failed to make adequate findings to support the new time of use factors and SRAC pricing formula; (2) requiring the utilities to enter into standard contracts with small QFs without regard to the utilities’ need for such power contravenes federal law; (3) the CPUC erred in not ordering a retroactive true-up of previous energy payments to QFs which exceeded the utilities’ avoided costs; and (4) extending previous contract terms for QFs with expiring contracts while requiring the utilities to pay those QFs based on the new SRAC pricing formula would result in QF payments that are higher than the utilities’ avoided costs. Responses to the rehearing application are due November 9, 2007. It is uncertain when the CPUC will respond to the application.

Natural Gas Transmission and Storage Rate Case

On September 20, 2007, the CPUC issued a final decision approving 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 from January 1, 2008 through December 31, 2010. The Utility’s first Gas Accord was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.

The Gas Accord IV establishes 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). A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers (i.e., residential and small commercial customers), will continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements will continue to depend on throughput volumes, gas prices, and the extent to which noncore customers (i.e., industrial, large commercial, and electric generation customers) and other shipperscontract for firm transmission services.

Delayed Billing Investigation

On September 20, 2007, the CPUC ordered the Utility to refund, at shareholder expense, approximately $35 million to customers for failure to issue bills at regular intervals based on actual metering data and by issuing backbills related to delayed bills and estimated bills beyond the time limits permitted under the tariff. The CPUC also ordered the Utility to refund reconnection fees and pay credits to approximately 3,000 customers whose service was shutoff for nonpayment of backbills that violated the tariff. The decision found that penalties were not warranted. After considering accruals already made related to this matter, PG&E Corporation and the Utility do not expect that the payment of such refunds will have a material adverse effect on their financial condition or results of operations.

Energy Efficiency Rulemaking

On September 20, 2007, the CPUC voted to establish incentive ratemaking mechanisms applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. The CPUC will review the adopted mechanisms in 2011 prior to continuation to subsequent program cycles.

Under the adopted incentive mechanism, before the utilities can earn incentives, the utilities must (1) achieve at least 85% of the CPUC’s overall savings goal over the three-year program cycle and (2) achieve at least 80% of the individual kWh, kilowatt (kW), and therm savings metric goals over the three-year program cycle. If the utilities achieve between 85% and 99% of the CPUC’s overall savings goal, 9% of the verified net benefits (i.e., energy resource savings minus total energy efficiency program costs) will accrue to shareholders and 91% of the verified net benefits will accrue to customers. If the utilities achieve 100% or more of the CPUC’s savings goal, the shared rate increases so that 12% of the total verified net benefits will accrue to shareholders and 88% will accrue to customers up to a stated maximum. The maximum amount of shareholder incentives that the Utility could earn over the 2006-2008 program cycle is $180 million.

If the utilities achieve less than 65% of any one of the individual savings metric goals, then the utilities must reimburse customers based on the greater of (1) 5 cents per kWh, 45 cents per therm, and $25 per kW for each kWh, therm,

or kW unit below the 65% threshold or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee. The maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.

The decision requires that two interim claims occur during the three-year program cycle, subject to verification of the actual amount of net benefits in a final true-up claim. The CPUC will determine for each interim claim whether a utility is entitled to incentives or is required to reimburse customers based on the level of achievement of the CPUC’s savings goals on a cumulative-to-date basis. The decision requires that 30% of the incentives or reimbursement obligations calculated for each interim claim be “held back” until completion of measurement studies verifying the actual energy savings for the entire three-year program cycle, in order to minimize the risk of overpaying the utilities in their interim claims. The final true-up may result in an adjustment to the prior year interim claims. The decision states that any reimbursement obligations that might arise in the final true-up claim may be recorded in the next energy efficiency program cycle. It is uncertain whether the Utility will be able to record any interim incentives or reimbursement obligations before the CPUC completes the final verification of actual energy savings for the relevant three-year program period. On October 31, 2007, the Utility, along with other investor-owned electric utilities, filed a petition for modification of the shareholder incentive mechanism to reduce the possibility of utilities having to pay back interim earnings as long as the final measured energy savings stay above 65% of the CPUC savings goals.

The amount and timing of the financial impact of the adopted rules on PG&E Corporation’s and the Utility’s financial condition and results of operations will depend on the level of energy efficiency savings actually achieved over the three-year program cycle and when the applicable accounting standard for recognizing incentives or reimbursement obligations is met.

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 expire. 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 as to the level of bundled electric load for which the Utility 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 flows could be materially adversely affected.

Spent Nuclear Fuel Storage Proceedings

paid by the utilities. In 1983, the DOE entered into a contract with the Utility to provide for the disposal of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon (“Diablo Canyon”) and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”). The DOE failed to develop a permanent storage site by January 31, 1998. (As discussed below, the Utility, as well as other nuclear power plant owners, have sued the DOE for breach of contract.) Nevertheless, 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.

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 on April 1, 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).

The Utility has been allocated certain CRRs as of September 30, 2007 and anticipates acquiring additional CRRs through the allocation and auction phases prior to the MRTU effective date. The CRRs are derivative instruments and will be recorded in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets after a fair value can be determined based on

observable market data. 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 MW of power needed by the Utility’s customers. In September 2007, the bankruptcy court approved a motion by Calpine, supported by the DWR, to assume rather than reject the contract and to continue performing under the contract. In addition, in September 2007, Calpine stipulated to a dismissal of its pending appeal in the United States Court of Appeal of a prior decision by the U.S. District Court finding that the bankruptcy court lacked jurisdiction to allow Calpine to reject the contract. As a result of these developments, the Utility expects that Calpine will continue to supply power to the Utility’s customers under the terms of the existing contract with DWR until the contract expires at the end of 2009.

Natural Gas Procurement (Core Customers)

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.

Under the decision, the long-term hedging program will be in place for up to five years starting with the 2007-2008 winter season. The Utility consults with an advisory group, consisting of members of the three core gas 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 gas customers as long as the CPUC finds that the Utility implemented its hedges in accordance with the pre-approved plan.

The Utility’s filed hedging plan prescribes the financial hedges that will be put in place in a rolling three-year basis (the current winter season and the next two subsequent winter seasons), consistent with pre-defined hedge program parameters. The CPUC approved the 2007-2008 winter season annual hedge plan on June 26, 2007. The Utility completed the execution of its hedge plan in the third quarter of 2007.

Natural Gas Transportation and Storage

The Utility uses value-at-risk to measure the shareholders' exposure to price and volumetric risks resulting from variability in the price of and demand for natural gas transportation and storage services 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 $36 million and $26 million at September 30, 2007 and December 31, 2006, respectively. The Utility's high, low, and average value-at-risk during the nine months ended September 30, 2007 and for the year ended December 31, 2006 were approximately $36 million, $21 million, and $28 million, and $41 million, $22 million, and $33 million, respectively.

Convertible Subordinated Notes

At September 30, 2007, PG&E Corporation had outstanding approximately $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 distributed January 15 through October 15, 2007, PG&E Corporation paid approximately $26 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 reclassified the Convertible Subordinated Notes as a noncurrent liability (in Noncurrent Liabilities - Long-Term Debt) in the accompanying Condensed Consolidated Balance Sheets effective as of that date.

In accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“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 operating 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 (in Other Income, Net). At September 30, 2007 and December 31, 2006, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $67 million and $79 million, respectively, of which $25 million and $23 million, respectively, was classified as a current liability (in Current Liabilities - Other) and $42 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 September 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 approximately $5.4 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 September 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 $515 million at September 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 Current Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately $67 million at September 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 above under 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 September 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 September 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.

Solano County District Attorney’s Office

In a letter dated July 11, 2007, the Solano County District Attorney's Office stated its intention to file a civil complaint against the Utility for record-keeping violations related to an underground storage tank at the Utility’s service center in Vallejo, California. The letter attached a copy of the draft complaint, which detailed a series of alleged California Health and Safety Code record-keeping violations, some of which date back to 2004. Alleged violations include failing to complete inspections, testing, and certifications, and to make records available to the County. Under the California Health and Safety Code, penalties of up to $5,000 per day for each violation may be assessed. The draft complaint also seeks penalties for unfair and unlawful business practices under California Business and Professions Code Section 17200, under which penalties of up to $5,000 per violation may be assessed. There are no allegations related to the discharge of any hazardous substances. The Utility is investigating the allegations and has entered into discussions with the District Attorney. The Utility believes that the ultimate outcome of this matter would not result in a material adverse effect on its financial condition or results of operations.

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

During the quarter ended September 30, 2007, PG&E Corporation issued 596 shares of common stock at a conversion price of $15.09 per share in an unregistered offering upon conversion of $9,000 principal amount of PG&E Corporation 9.50% Convertible Subordinated Notes originally issued in an unregistered offering in 2002. During the quarter ended September 30, 2007, the Utility did not make any sales of unregistered equity securities.

PG&E Corporation did not repurchase any shares of its common stock during the third quarter of 2007. The Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding during the third quarter of 2007.

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 nine months ended September 30, 2007 was 2.92 and 2.91, respectively. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three and nine months ended September 30, 2007 was 2.86 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

3.1	Bylaws of PG&E Corporation, as amended as of September 19, 2007

3.2	Bylaws of Pacific Gas and Electric Company, as amended as of September 19, 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


**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: November 1, 2007

EXHIBIT INDEX

3.1	Bylaws of PG&E Corporation, as amended as of September 19, 2007

3.2	Bylaws of Pacific Gas and Electric Company, as amended as of September 19, 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


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