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, 2009 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [X] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PG&E Corporation:			[X] Large accelerated filer				[ ] Accelerated Filer
			[ ] Non-accelerated filer			[ ] Smaller reporting company
Pacific Gas and Electric Company:			[ ] Large accelerated filer				[ ] Accelerated Filer
			[X] Non-accelerated filer			[ ] Smaller reporting company

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 27, 2009:

PG&E Corporation					370,960,212
Pacific Gas and Electric Company					264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

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		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	13
	NOTE 2:		New and Significant Accounting Policies	13
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	18
	NOTE 4:		Debt	22
	NOTE 5:		Equity	23
	NOTE 6:		Earnings Per Share	23
	NOTE 7:		Derivatives and Hedging Activities	25
	NOTE 8:		Fair Value Measurements	29
	NOTE 9:		Related Party Agreements and Transactions	33
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	33
	NOTE 11:		Commitments and Contingencies	34

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			41
	Forward-Looking Statements			43
	Results of Operations			44
	Liquidity and Financial Resources			51
	Contractual Commitments			55
	Capital Expenditures			55
	Off-Balance Sheet Arrangements			56
	Contingencies			56
	Regulatory Matters			56
	Risk Management Activities			60
	Critical Accounting Policies			61
	New Accounting Policies			61
	Accounting Pronouncements Issued But Not Yet Adopted			63

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			65
ITEM 4.	CONTROLS AND PROCEDURES			65

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			66
ITEM 1A.	RISK FACTORS			66
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			66
ITEM 5.	OTHER INFORMATION			67
ITEM 6.	EXHIBITS			68

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
	September 30,						September 30,
(in millions, except per share amounts)	2009			2008			2009			2008
Operating Revenues
Electric	$	2,630		$	2,880		$	7,610		$	8,039
Natural gas		605			794			2,250			2,946
Total operating revenues		3,235			3,674			9,860			10,985
Operating Expenses
Cost of electricity		997			1,282			2,763			3,406
Cost of natural gas		134			351			879			1,613
Operating and maintenance		1,047			983			3,144			3,010
Depreciation, amortization, and decommissioning		450			419			1,298			1,240
Total operating expenses		2,628			3,035			8,084			9,269
Operating Income		607			639			1,776			1,716
Interest income		1			23			27			82
Interest expense		(174	)		(178	)		(533	)		(550	)
Other income (expense), net		23			(14	)		63			(4	)
Income Before Income Taxes		457			470			1,333			1,244
Income tax provision		136			163			376			413
Net Income		321			307			957			831
Preferred stock dividend requirement of subsidiary		3			3			10			10
Income Available for Common Shareholders	$	318		$	304		$	947		$	821
Weighted Average Common Shares Outstanding, Basic		370			357			367			356
Weighted Average Common Shares Outstanding, Diluted		388			358			386			357
Net Earnings Per Common Share, Basic	$	0.84		$	0.83		$	2.53		$	2.25
Net Earnings Per Common Share, Diluted	$	0.83		$	0.83		$	2.49		$	2.24
Dividends Declared Per Common Share	$	0.42		$	0.39		$	1.26		$	1.17

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	700		$	219
Restricted cash		569			1,290
Accounts receivable:
Customers (net of allowance for doubtful accounts of $68 million in 2009 and $76 million in 2008)		1,609			1,751
Accrued unbilled revenue		807			685
Regulatory balancing accounts		882			1,197
Inventories:
Gas stored underground and fuel oil		141			232
Materials and supplies		204			191
Income taxes receivable		58			120
Prepaid expenses and other		640			718
Total current assets		5,610			6,403
Property, Plant, and Equipment
Electric		29,875			27,638
Gas		10,524			10,155
Construction work in progress		1,767			2,023
Other		15			17
Total property, plant, and equipment		42,181			39,833
Accumulated depreciation		(13,997	)		(13,572	)
Net property, plant, and equipment		28,184			26,261
Other Noncurrent Assets
Regulatory assets		5,931			5,996
Nuclear decommissioning funds		1,870			1,718
Income taxes receivable		506			-
Other		450			482
Total other noncurrent assets		8,757			8,196
TOTAL ASSETS	$	42,551		$	40,860

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30, 2009			December 31, 2008
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	500		$	287
Long-term debt, classified as current		342			600
Energy recovery bonds, classified as current		382			370
Accounts payable:
Trade creditors		864			1,096
Disputed claims and customer refunds		816			1,580
Regulatory balancing accounts		629			730
Other		370			343
Interest payable		794			802
Income taxes payable		589			-
Deferred income taxes		172			251
Other		1,491			1,567
Total current liabilities		6,949			7,626
Noncurrent Liabilities
Long-term debt		9,839			9,321
Energy recovery bonds		928			1,213
Regulatory liabilities		4,152			3,657
Pension and other postretirement benefits		2,221			2,088
Asset retirement obligations		1,545			1,684
Income taxes payable		-			35
Deferred income taxes		4,321			3,397
Deferred tax credits		90			94
Other		2,092			2,116
Total noncurrent liabilities		25,188			23,605
Commitments and Contingencies
Equity
Shareholders’ Equity
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		-			-
Common stock, no par value, authorized 800,000,000 shares, issued 370,877,751 common and 670,552 restricted shares in 2009 and issued 361,059,116 common and 1,287,569 restricted shares in 2008		6,265			5,984
Reinvested earnings		4,097			3,614
Accumulated other comprehensive loss		(200	)		(221	)
Total shareholders’ equity		10,162			9,377
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		10,414			9,629
TOTAL LIABILITIES AND EQUITY	$	42,551		$	40,860

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2009			2008
Cash Flows from Operating Activities
Net income	$	957		$	831
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,455			1,388
Allowance for equity funds used during construction		(71	)		(51	)
Deferred income taxes and tax credits, net		301			482
Other changes in noncurrent assets and liabilities		61			87
Effect of changes in operating assets and liabilities:
Accounts receivable		20			(181	)
Inventories		78			(153	)
Accounts payable		(159	)		(100	)
Disputed claims and customer refunds		(700	)		-
Income taxes receivable/payable		658			177
Regulatory balancing accounts, net		226			(94	)
Other current assets		27			(123	)
Other current liabilities		(50	)		(68	)
Other		4			(3	)
Net cash provided by operating activities		2,807			2,192
Cash Flows from Investing Activities
Capital expenditures		(3,022	)		(2,691	)
Decrease (increase) in restricted cash		732			(3	)
Proceeds from nuclear decommissioning trust sales		1,177			1,121
Purchases of nuclear decommissioning trust investments		(1,219	)		(1,161	)
Other		14			(41	)
Net cash used in investing activities		(2,318	)		(2,775	)
Cash Flows from Financing Activities
Net borrowings under revolving credit facility		-			283
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008		(290	)		524
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009		499			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $16 million in 2009 and $2 million in 2008		1,193			693
Long-term debt matured or repurchased		(909	)		(454	)
Energy recovery bonds matured		(273	)		(260	)
Common stock issued		211			150
Common stock dividends paid		(435	)		(406	)
Other		(4	)		(41	)
Net cash (used in) provided by financing activities		(8	)		489
Net change in cash and cash equivalents		481			(94	)
Cash and cash equivalents at January 1		219			345
Cash and cash equivalents at September 30	$	700		$	251

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(493	)	$	(449	)
Income taxes, net		437			146
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	156		$	140
Capital expenditures financed through accounts payable		229			224
Noncash common stock issuances		50			6

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
	September 30,						September 30,
(in millions)	2009			2008			2009			2008
Operating Revenues
Electric	$	2,630		$	2,880		$	7,610		$	8,039
Natural gas		605			794			2,250			2,946
Total operating revenues		3,235			3,674			9,860			10,985
Operating Expenses
Cost of electricity		997			1,282			2,763			3,406
Cost of natural gas		134			351			879			1,613
Operating and maintenance		1,047			982			3,143			3,009
Depreciation, amortization, and decommissioning		450			419			1,298			1,239
Total operating expenses		2,628			3,034			8,083			9,267
Operating Income		607			640			1,777			1,718
Interest income		3			20			29			77
Interest expense		(162	)		(170	)		(501	)		(528	)
Other income (expense), net		16			(2	)		52			24
Income Before Income Taxes		464			488			1,357			1,291
Income tax provision		111			167			374			421
Net Income		353			321			983			870
Preferred stock dividend requirement		3			3			10			10
Income Available for Common Stock	$	350		$	318		$	973		$	860

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	511		$	52
Restricted cash		569			1,290
Accounts receivable:
Customers (net of allowance for doubtful accounts of $68 million in 2009 and $76 million in 2008)		1,609			1,751
Accrued unbilled revenue		807			685
Related parties		2			2
Regulatory balancing accounts		882			1,197
Inventories:
Gas stored underground and fuel oil		141			232
Materials and supplies		204			191
Income taxes receivable		63			25
Prepaid expenses and other		635			705
Total current assets		5,423			6,130
Property, Plant, and Equipment
Electric		29,875			27,638
Gas		10,524			10,155
Construction work in progress		1,767			2,023
Total property, plant, and equipment		42,166			39,816
Accumulated depreciation		(13,983	)		(13,557	)
Net property, plant, and equipment		28,183			26,259
Other Noncurrent Assets
Regulatory assets		5,931			5,996
Nuclear decommissioning funds		1,870			1,718
Related parties receivable		26			27
Income taxes receivable		518			-
Other		365			407
Total other noncurrent assets		8,710			8,148
TOTAL ASSETS	$	42,316		$	40,537

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	500		$	287
Long-term debt, classified as current		95			600
Energy recovery bonds, classified as current		382			370
Accounts payable:
Trade creditors		864			1,096
Disputed claims and customer refunds		816			1,580
Related parties		14			25
Regulatory balancing accounts		629			730
Other		371			325
Interest payable		777			802
Income tax payable		612			53
Deferred income taxes		177			257
Other		1,289			1,371
Total current liabilities		6,526			7,496
Noncurrent Liabilities
Long-term debt		9,491			9,041
Energy recovery bonds		928			1,213
Regulatory liabilities		4,152			3,657
Pension and other postretirement benefits		2,170			2,040
Asset retirement obligations		1,545			1,684
Income taxes payable		-			12
Deferred income taxes		4,353			3,449
Deferred tax credits		90			94
Other		2,057			2,064
Total noncurrent liabilities		24,786			23,254
Commitments and Contingencies
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 264,374,809 shares in 2009 and 2008		1,322			1,322
Additional paid-in capital		3,022			2,331
Reinvested earnings		6,597			6,092
Accumulated other comprehensive loss		(195	)		(216	)
Total shareholders’ equity		11,004			9,787
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	42,316		$	40,537

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2009			2008
Cash Flows from Operating Activities
Net income	$	983		$	870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,439			1,388
Allowance for equity funds used during construction		(71	)		(51	)
Deferred income taxes and tax credits, net		274			470
Other changes in noncurrent assets and liabilities		95			55
Effect of changes in operating assets and liabilities:
Accounts receivable		20			(179	)
Inventories		78			(153	)
Accounts payable		(151	)		(85	)
Disputed claims and customer refunds		(700	)		-
Income taxes receivable/payable		534			208
Regulatory balancing accounts, net		226			(94	)
Other current assets		26			(125	)
Other current liabilities		(62	)		(80	)
Other		3			(4	)
Net cash provided by operating activities		2,694			2,220
Cash Flows from Investing Activities
Capital expenditures		(3,022	)		(2,691	)
Decrease (increase) in restricted cash		732			(3	)
Proceeds from nuclear decommissioning trust sales		1,177			1,121
Purchases of nuclear decommissioning trust investments		(1,219	)		(1,161	)
Other		7			21
Net cash used in investing activities		(2,325	)		(2,713	)
Cash Flows from Financing Activities
Net borrowings under revolving credit facility		-			283
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008		(290	)		524
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009		499			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008		847			693
Long-term debt matured or repurchased		(909	)		(454	)
Energy recovery bonds matured		(273	)		(260	)
Preferred stock dividends paid		(10	)		(10	)
Common stock dividends paid		(468	)		(426	)
Equity contribution		688			90
Other		6			(31	)
Net cash provided by financing activities		90			409
Net change in cash and cash equivalents		459			(84	)
Cash and cash equivalents at January 1		52			141
Cash and cash equivalents at September 30	$	511		$	57

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(481	)	$	(436	)
Income taxes, net		297			138
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	229		$	224

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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 (“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 regulated primarily 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 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 the accounts of the Utility and its wholly owned and controlled subsidiaries, as well as the accounts of variable interest entities (“VIEs”) for which the Utility absorbs a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles 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 therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. 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 information at December 31, 2008 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, 2008. PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2008, together with the information incorporated by reference into such report, is referred to in this quarterly report on Form 10-Q as the “2008 Annual Report.”

The accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report. Any significant changes to those policies or new significant policies are described in Note 2 below.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions, discussed further below in these notes, relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would 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.

This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and Notes to the Consolidated Financial Statements in the 2008 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Consolidation of Variable Interest Entities

PG&E Corporation and the Utility are required to consolidate any entity over which it has control. In most cases, control can be determined based on majority ownership. However, for certain entities, control is difficult to discern based on voting equity interests only. These entities are referred to as VIEs. Characteristics of a VIE include equity investment at risk that is not sufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or equity investors that lack any of the characteristics of a controlling financial interest. The primary beneficiary, defined as the entity that absorbs a majority of the expected losses of the VIE, receives a majority of the expected residual returns of the VIE, or both, is required to consolidate the VIE.

The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement. For those entities, the Utility assesses operational risk, commodity price risk, credit risk, and tax benefit risk on a qualitative basis to determine whether the Utility is a primary beneficiary of the entity and is required to consolidate the entity. This qualitative assessment also typically involves comparing the contract life to the economic life of the plant to consider the significance of the commodity price risk that the Utility might absorb. As of September 30, 2009, the Utility is not the primary beneficiary of any entities with which it has power purchase agreements.

Although the Utility is not required to consolidate any of these VIEs as of September 30, 2009, it held a significant variable interest in three VIEs as a result of being a party to the following power purchase agreements:

·	A 25-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 250-megawatt (“MW”) solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2012);

·	A 20-year power purchase agreement approved by the CPUC in 2009 to purchase energy from a 550-MW solar photovoltaic energy facility beginning on the date of commercial operations (expected in 2013); and

·	A 25-year power purchase agreement approved by the CPUC in 2008 to purchase energy from a 554-MW solar trough facility beginning on the date of commercial operations (expected in 2011).

Each of these VIEs is a subsidiary of another company whose activities are financed primarily through equity from investors and proceeds from non-recourse project-specific debt financing. Activities of the VIEs consist of renewable energy production from electric generating facilities for sale to the Utility. Under each of the power purchase agreements, the Utility is obligated to purchase as-delivered electric generation output from the VIEs. The Utility does not provide any other financial or other support to these VIEs. The Utility’s financial exposure is limited to the amounts paid for delivered electricity.

Asset Retirement Obligations

See Note 2 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report for a discussion of PG&E Corporation’s and the Utility’s accounting policy for ARO. A reconciliation of the changes in the ARO liability is as follows:

(in millions)
ARO liability at December 31, 2008	$	1,684
Revision in estimated cash flows		(172	)
Accretion		73
Liabilities settled		(40	)
ARO liability at September 30, 2009	$	1,545

Detailed studies of the cost to decommission the Utility’s nuclear power plants are conducted every three years in conjunction with the filing of the Nuclear Decommissioning Cost Triennial Proceedings. Estimated cash flows were revised as a result of the studies completed in the first quarter of 2009.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for certain employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for certain employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for certain employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.

The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended September 30,						Three Months Ended September 30,
(in millions)	2009			2008			2009			2008
Service cost for benefits earned	$	62		$	59		$	7		$	7
Interest cost		158			148			23			21
Expected return on plan assets		(144	)		(173	)		(17	)		(22	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		16			12			4			4
Amortization of unrecognized (gain) loss		27			1			1			(3	)
Net periodic benefit cost		119			47			24			13
Less: transfer to regulatory account (1)		(78	)		(5	)		-			-
Total	$	41		$	42		$	24		$	13

(1) For the three months ended September 30, 2009 and 2008, the Utility recorded $78 million as an addition to the existing pension regulatory asset and $5 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Service cost for benefits earned	$	194		$	177		$	22		$	22
Interest cost		468			436			66			61
Expected return on plan assets		(434	)		(522	)		(51	)		(70	)
Amortization of transition obligation		-			-			19			19
Amortization of prior service cost		39			35			12			12
Amortization of unrecognized (gain) loss		76			1			2			(11	)
Net periodic benefit cost		343			127			70			33
Less: transfer to regulatory account (1)		(221	)		(3	)		-			-
Total	$	122		$	124		$	70		$	33

(1) For the nine months ended September 30, 2009 and 2008, the Utility recorded $221 million as an addition to the existing pension regulatory asset and $3 million as a reduction to the existing pension regulatory liability, respectively, to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking purposes, which is based on a funding approach.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three and nine months ended September 30, 2009 and 2008.

Adoption of New Accounting Pronouncements

Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

On January 1, 2009, PG&E Corporation and the Utility adopted Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 requires an entity to provide qualitative disclosures about its objectives and strategies for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments. SFAS No. 161 also requires disclosures about credit risk-related contingent features of derivative instruments. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51

On January 1, 2009, PG&E Corporation and the Utility adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 defines a “noncontrolling interest,” previously called a “minority interest,” as the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. Among other items, SFAS No. 160 requires that an entity (1) include a noncontrolling interest in its consolidated statement of financial position within equity separate from the parent’s equity, (2) report amounts inclusive of both the parent’s and noncontrolling interest’s shares in consolidated net income, and (3) separately report the amounts of consolidated net income attributable to the parent and noncontrolling interest on the consolidated statement of operations. If a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be measured at fair value, and a gain or loss must be recognized in net income based on such fair value.

PG&E Corporation has reclassified its noncontrolling interest in the Utility from Preferred Stock of Subsidiaries to equity in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 160 for all periods presented. The Utility had no material noncontrolling interests in consolidated subsidiaries as of September 30, 2009 and December 31, 2008.

PG&E Corporation and the Utility applied the presentation and disclosure requirements of SFAS No. 160 retrospectively. Other than the change in presentation of noncontrolling interests, adoption of SFAS No. 160 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement

On January 1, 2009, PG&E Corporation and the Utility adopted Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”). EITF 08-5 clarifies the unit of account in determining the fair value of a liability. Specifically, it requires an entity to exclude any third-party credit enhancements that are issued with, and are inseparable from, a debt instrument from the fair value measurement of that debt instrument. Adoption of EITF 08-5 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Equity Method Investment Accounting

On January 1, 2009, PG&E Corporation and the Utility adopted EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”). EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost. Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than the Business Combinations Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”). However, the investor in an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs. An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings. Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Subsequent Events

On June 30, 2009, PG&E Corporation and the Utility adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 does not significantly change the prior accounting practice for subsequent events, except for the requirement to disclose the date through which an entity has evaluated subsequent events and the basis for that date. PG&E Corporation and the Utility have evaluated material subsequent events through October 29, 2009, the issue date of PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. Other than this disclosure, adoption of SFAS No. 165 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Interim Disclosures about Fair Value of Financial Instruments

On June 30, 2009, PG&E Corporation and the Utility adopted FASB Staff Position (“FSP”) SFAS 107-1 and Accounting Principles Board (“APB”) 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP requires disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods. In particular, an entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and to disclose where the carrying amount is classified in the Condensed Consolidated Balance Sheets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.)

Recognition and Presentation of Other-Than-Temporary Impairments

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” Under this FSP, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses. In addition, this FSP requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements. However, this FSP does not amend recognition and measurement guidance for other-than-temporary impairments of equity securities. Adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

On June 30, 2009, PG&E Corporation and the Utility adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This FSP provides guidance on estimating fair value when the volume or the level of activity for an asset or a liability has significantly decreased or when transactions are not orderly, when compared with normal market conditions. In particular, this FSP calls for adjustments to quoted prices or historical transaction data when estimating fair value in such circumstances. This FSP also provides guidance to identify such circumstances. Furthermore, this FSP requires fair value measurement disclosures made pursuant to the Fair Value Measurements and Disclosures Topic of the FASB ASC to be categorized by major security type (i.e., based on the nature and risks of the security). (See Note 8 of the Notes to the Condensed Consolidated Financial Statements.) Other than this change, adoption of this FSP did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles

On July 1, 2009, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-01, “Topic 105 - Generally Accepted Accounting Principles - amendments based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles” (“ASU No. 2009-01”). ASU No. 2009-01 re-defines authoritative GAAP for nongovernmental entities to be only comprised of the FASB Accounting Standards CodificationTM (“Codification”) and, for SEC registrants, guidance issued by the SEC. The Codification is a reorganization and compilation of all then-existing authoritative GAAP for nongovernmental entities, except for guidance issued by the SEC. The Codification is amended to effect non-SEC changes to authoritative GAAP. Adoption of ASU No. 2009-01 only changed the referencing convention of GAAP in PG&E Corporation’s and the Utility’s Notes to the Condensed Consolidated Financial Statements.

Accounting Pronouncements Issued But Not Yet Adopted

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends and expands the disclosure requirements of the Compensation - Retirement Benefits Topic of the FASB ASC. In particular, this FSP requires an entity to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. In addition, this FSP requires quantitative disclosures showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs. This FSP is effective prospectively for PG&E Corporation and the Utility for the annual period ending December 31, 2009 and for subsequent annual periods. PG&E Corporation and the Utility will include the expanded disclosures described above in PG&E Corporation’s and the Utility’s Notes to the Consolidated Financial Statements for the annual period ending December 31, 2009.

Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140” (“SFAS No. 166”). SFAS No. 166 eliminates the concept of a qualifying special-purpose entity and clarifies the requirements for derecognizing a financial asset and for applying sale accounting to a transfer of a financial asset. In addition, SFAS No. 166 requires an entity to disclose more information about transfers of financial assets, the entity’s continuing involvement, if any, with transferred financial assets, and the entity’s continuing risks, if any, from transferred financial assets. SFAS No. 166 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 166.

Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends the Consolidation Topic of the FASB ASC regarding when and how to determine, or re-determine, whether an entity is a VIE. In addition, SFAS No. 167 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach. Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

The Utility accounts for the financial effects of regulation based on the Regulated Operations Topic of the FASB ASC, which applies to regulated entities whose rates are designed to recover the cost of providing service (“cost-of-service rate regulation”). All of the Utility’s operations are subject to cost-of-service rate regulation.

The Utility capitalizes and records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. The regulatory assets are amortized over future periods when the costs are expected to be recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, 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

Long-term regulatory assets are composed of the following:

	Balance At
(in millions)	September 30, 2009		December 31, 2008
Pension benefits	$	1,732	$	1,624
Energy recovery bonds		1,219		1,487
Deferred income tax		982		847
Utility retained generation		754		799
Price risk management		340		362
Environmental compliance costs		398		385
Unamortized loss, net of gain, on reacquired debt		209		225
Regulatory assets associated with plan of reorganization		87		99
Contract termination costs		71		82
Other		139		86
Total long-term regulatory assets	$	5,931	$	5,996

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 14 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.)

In connection with 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 (“Chapter 11 Settlement Agreement”), the CPUC authorized the Utility to recover $2.21 billion (“settlement regulatory asset”) over a nine year period. In order to lower the costs borne by customers, PG&E Energy Recovery Funding LLC (“PERF”), a wholly owned consolidated subsidiary of the Utility, issued energy recovery bonds (“ERB”) to refinance the settlement regulatory asset. The regulatory asset for ERBs represents the refinancing of the settlement regulatory asset. The regulatory asset is amortized over the life of the bonds consistent with the period over which the related billed revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.

The regulatory assets for deferred income tax represent deferred income tax benefits previously passed through to customers offset by deferred income tax liabilities. The CPUC requires the Utility to pass through certain tax benefits to customers, ignoring 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 45 years.

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 16 years.

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation expense that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 30 years. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.

Regulatory assets associated with the Utility’s plan of reorganization represent costs incurred in relation to the Utility’s plan of reorganization under Chapter 11, including financing costs and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Land Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization. The Utility expects to recover these costs over the remaining periods ranging from 4 to 25 years, and these costs should be fully recovered by 2034.

The regulatory assets for contract termination costs represent costs that the Utility incurred in terminating a 30-year power purchase agreement. These costs are being amortized and collected in rates on a straight-line basis through the end of September 2014, the power purchase agreement’s original termination date.

At September 30, 2009, “Other” primarily consisted of regulatory assets relating to ARO costs recorded in accordance with GAAP, which are probable of future recovery through the ratemaking process, as well as costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), as approved by the CPUC for future recovery. At December 31, 2008, “Other” primarily consisted of regulatory assets relating to ARO costs, as well as scheduling coordinator costs that the Utility incurred beginning in 1998 in its capacity as scheduling coordinator for its then-existing wholesale electric transmission customers.

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

Current Regulatory Assets

At September 30, 2009 and December 31, 2008, the Utility had current regulatory assets of $421 million and $355 million, respectively, consisting primarily of the current portion of price risk management regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of less than one year. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.

Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance At
(in millions)	September 30, 2009		December 31, 2008
Cost of removal obligation	$	2,886	$	2,735
Public purpose programs		521		442
Recoveries in excess of asset retirement obligation		498		226
Price risk management		82		81
Gateway Generating Station		65		67
Environmental remediation insurance recoveries		39		52
Other		61		54
Total long-term regulatory liabilities	$	4,152	$	3,657

The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the decommissioning expenses recorded in accordance with GAAP. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

The regulatory liability for price risk management represents the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

The regulatory liability related to the Gateway Generating Station (“Gateway”) represents the gain associated with the Utility’s acquisition of Gateway, as part of a settlement that the Utility entered with Mirant Corporation, to be credited to customers in future rates. The regulatory liability is being amortized over 30 years beginning in January 2009, when Gateway was placed in service.

The regulatory liabilities associated with environmental remediation insurance recoveries represent amounts that are refunded to customers as a reduction to rates, as costs are incurred for hazardous substance remediation.

“Other” is an aggregate of various other regulatory liabilities representing amounts collected for future costs.

Current Regulatory Liabilities

At September 30, 2009 and December 31, 2008, the Utility had current regulatory liabilities of $232 million and $313 million, respectively, primarily consisting of regulatory liabilities for the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates. Current regulatory liabilities are included in Current Liabilities – Other in the Condensed Consolidated Balance Sheets.

Regulatory Balancing Accounts

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. 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 represent the amount expected to be 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 in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, net

	Receivable (Payable)
	Balance At
(in millions)	September 30, 2009			December 31, 2008
Utility generation	$	199		$	164
Gas fixed cost		167			60
Transmission revenue		147			173
Public purpose programs		(70	)		(263	)
Energy procurement costs		(117	)		598
Energy recovery bonds		(167	)		(231	)
Other		94			(34	)
Total regulatory balancing accounts, net	$	253		$	467

The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, the under-collection generally decreases due to higher rates and electric usage that cause an increase in generation revenues.

The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas-distribution related costs. The under-collection or over-collection position of this account is dependent on seasonality and volatility in gas prices.

The transmission revenue balancing account represents the difference between electric transmission wheeling revenues received by the Utility from the California Independent System Operator (“CAISO”) (on behalf of electric transmission wholesale customers) and refunds to customers plus interest.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirement and the actual cost of such programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs. A refund of $230 million from the California Energy Commission for unspent renewable program funding previously collected is being returned to customers through lower rates throughout 2009.

The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur during the following year, and rates are set to recover such expected costs.

The energy recovery bonds balancing account records certain benefits and costs associated with ERBs that are provided to, or received from, customers. In addition, this account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs were issued.

At September 30, 2009 and December 31, 2008, “Other” includes the California Alternate Rates for Energy balancing account, which records the revenue shortfall associated with the low-income customer assistance program. Participation in the program is generally impacted by economic conditions. Program spending increases as more customers participate in the programs, resulting in an under-collection. At December 31, 2008, “Other” also included incentive awards earned by the Utility for implementing customer energy efficiency programs.

NOTE 4: DEBT

PG&E Corporation

Senior Notes

On March 12, 2009, PG&E Corporation issued $350 million principal amount of 5.75% Senior Notes due April 1, 2014.

Credit Facility

At September 30, 2009, PG&E Corporation had no borrowings outstanding under its $187 million revolving credit facility. PG&E Corporation amended its revolving credit facility on April 27, 2009 to remove Lehman Brothers Bank, FSB (“Lehman Bank”) as a lender. Prior to the amendment, the total borrowing capacity under the revolving credit facility was $200 million, including a commitment from Lehman Bank that represented $13 million, or 7%, of the total.

Utility

Senior Notes

On March 6, 2009, the Utility issued $550 million principal amount of 6.25% Senior Notes due March 1, 2039.

On June 11, 2009, the Utility issued $500 million principal amount of Floating Rate Senior Notes due June 10, 2010. The interest rate for the Floating Rate Senior Notes is equal to the three-month London Interbank Offered Rate plus 0.95% and will reset quarterly beginning on September 10, 2009. At September 30, 2009, the interest rate on the Floating Rate Senior Notes was 1.25%.

Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank (“CIEDB”), serving as conduit issuer, have issued various series of tax-exempt pollution control bonds for the benefit of the Utility.

On September 1, 2009, the CIEDB issued $149 million of tax-exempt pollution control bonds series 2009 A and B due on November 1, 2026 and $160 million of tax-exempt pollution control bonds series 2009 C and D due on December 1, 2016. The proceeds were used to repurchase the corresponding series of 2008 pollution control bonds. The series 2009 bonds, issued at par with an initial rate of 0.20%, are variable rate demand notes with interest resetting daily and backed by direct-pay letters of credit. Unlike the series 2008 bonds, interest earned on the series 2009 bonds is not subject to the alternative minimum tax (“AMT”). A provision in the American Recovery and Reinvestment Act of 2009 allows certain tax-exempt bonds that are subject to AMT to be reissued or refunded in 2009 or 2010 as tax-exempt bonds that are not subject to AMT. As a result, the series 2009 bonds were issued at a lower interest rate, reducing the Utility’s interest expense.

Credit Facility and Short-Term Borrowings

At September 30, 2009, the Utility had $273 million of letters of credit outstanding under the Utility’s $1.94 billion revolving credit facility. The Utility amended its revolving credit facility on April 27, 2009 to remove Lehman Bank as a lender. Prior to the amendment, the total borrowing capacity under the revolving credit facility was $2.0 billion, including a commitment from Lehman Bank that represented $60 million, or 3%, of the total.

The revolving credit facility also provides liquidity support for commercial paper offerings. At September 30, 2009, the Utility had no commercial paper outstanding.

Energy Recovery Bonds

PG&E Energy Recovery Funding LLC, a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion in 2005. 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 amount of ERB principal outstanding was $1.3 billion at September 30, 2009.

While PERF is a wholly owned 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: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2009 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders’ Equity
Balance at December 31, 2008	$	9,629		$	9,787
Net income		957			983
Common stock issued		261			-
Share-based compensation amortization		17			-
Common stock dividends declared and paid		(309	)		(468	)
Common stock dividends declared but not yet paid		(156	)		-
Preferred stock dividend requirement		-			(10	)
Preferred stock dividend requirement of subsidiary		(10	)		-
Tax benefit from employee stock plans		4			3
Other comprehensive income		21			21
Equity contribution		-			688
Balance at September 30, 2009	$	10,414		$	11,004

For the nine months ended September 30, 2009, PG&E Corporation contributed equity of $688 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, 2009, the Utility paid common stock dividends totaling $468 million to PG&E Corporation.

During the nine months ended September 30, 2009, PG&E Corporation paid common stock dividends totaling $435 million, net of $18 million that was reinvested in additional shares of common stock by participants in the PG&E Corporation Dividend Reinvestment and Stock Purchase Plan. On September 16, 2009, the Board of Directors of PG&E Corporation declared a dividend of $0.42 per share, totaling $156 million, which was paid on October 15, 2009 to shareholders of record on September 30, 2009.

During the nine months ended September 30, 2009, the Utility paid cash dividends totaling $10 million to holders of its outstanding series of preferred stock. On September 16, 2009, the Board of Directors of the Utility declared a cash dividend totaling $3 million on its outstanding series of preferred stock, payable on November 15, 2009 to shareholders of record on October 30, 2009.

NOTE 6: EARNINGS PER 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 9.5% Convertible Subordinated Notes (“Convertible Subordinated Notes”) are entitled to receive pass-through dividends and meet the criteria of participating securities. All of the participating securities participate in dividends on a 1:1 basis with shares of common stock.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic earnings per share:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2009		2008		2009		2008
Basic
Income Available for Common Shareholders	$	318	$	304	$	947	$	821
Less: distributed earnings to common shareholders		156		140		465		419
Undistributed earnings	$	162	$	164	$	482	$	402
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	156	$	140	$	465	$	419
Undistributed earnings allocated to common shareholders		155		156		461		382
Total common shareholders earnings	$	311	$	296	$	926	$	801
Weighted average common shares outstanding, basic		370		357		367		356
Convertible Subordinated Notes		16		19		17		19
Weighted average common shares outstanding and participating securities		386		376		384		375
Net earnings per common share, basic
Distributed earnings, basic (1)	$	0.42	$	0.39	$	1.27	$	1.18
Undistributed earnings, basic		0.42		0.44		1.26		1.07
Total	$	0.84	$	0.83	$	2.53	$	2.25

(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.

In calculating diluted EPS, PG&E Corporation applies the if-converted method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted earnings per share for three and nine months ended September 30, 2009:

	September 30, 2009
(in millions, except per share amounts)	Three Months Ended		Nine Months Ended
Diluted
Income Available for Common Shareholders	$	318	$	947
Add earnings impact of assumed conversion of participating securities:
Interest expense on Convertible Subordinated Notes, net of tax		4		12
Unrealized loss on embedded derivative, net of tax		-		2
Income Available for Common Shareholders and Assumed Conversion	$	322	$	961

Weighted average common shares outstanding, basic		370		367
Add incremental shares from assumed conversions:
Convertible Subordinated Notes		16		17
Employee share-based compensation		2		2
Weighted average common shares outstanding, diluted		388		386
Total earnings per common share, diluted	$	0.83	$	2.49

Stock options to purchase 7,285 and 11,935 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and nine months ended September 30, 2009, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted earnings per share for three and nine months ended September 30, 2008:

	September 30, 2008
(in millions, except per share amounts)	Three Months Ended		Nine Months Ended
Diluted
Income Available for Common Shareholders	$	304	$	821
Less: distributed earnings to common shareholders		140		419
Undistributed earnings	$	164	$	402

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	140	$	419
Undistributed earnings allocated to common shareholders		156		382
Total common shareholders earnings	$	296	$	801

Weighted average common shares outstanding, basic		357		356
Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, basic		376		375
Weighted average common shares outstanding, basic		357		356
Employee share-based compensation		1		1
Weighted average common shares outstanding, diluted		358		357
Convertible Subordinated Notes		19		19
Weighted average common shares outstanding and participating securities, diluted		377		376
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.39	$	1.17
Undistributed earnings, diluted		0.44		1.07
Total earnings per common share, diluted	$	0.83	$	2.24

Stock options to purchase 7,285 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and nine months ended September 30, 2008, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility faces market risk primarily related to electricity and natural gas commodity prices. Substantially all of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers. The CPUC and the FERC allow the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas. As these costs are passed through to customers, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of electricity and natural gas.

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

·	forward contracts that commit the Utility to purchase a commodity in the future;

·	swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity;

·	option contracts that provide the Utility with the right to buy a commodity at a predetermined price; and

·	futures contracts that are exchange-traded contracts that commit the Utility to purchase a commodity or make a cash settlement at a specified price and future date.

These instruments are not held for speculative purposes and are subject to certain limitations imposed by regulatory requirements.

Commodity-Related Price Risk

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed Consolidated Balance Sheets. Certain commodity-related price risk management activities reduce the cash flow variability associated with fluctuating commodity prices. Prior to September 2009, the Utility designated qualifying derivative transactions as cash flow hedges for accounting purposes. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the fair value of these derivative instruments, including those designated as cash flow hedges, are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers. As of September 30, 2009, the Utility de-designated all cash flow hedge relationships. Due to the regulatory accounting treatment described above, the de-designation of cash flow hedge relationships had no impact on Income Available for Common Shareholders or the Condensed Consolidated Balance Sheet.

The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under California Department of Water Resources (“DWR”) contracts, and its own electricity generation facilities. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments and, therefore, are recorded at fair value within the Condensed Consolidated Balance Sheets. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments. Derivative instruments that are eligible for the normal purchase and normal sales exception are not required to be recorded at fair value.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the cash flow variability associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases under those power purchase agreements. These financial swaps are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

Electric Transmission Congestion Revenue Rights

The CAISO-controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update on April 1, 2009. The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve), and an auction phase (in which CRRs are priced at market and available to all market participants). In the third quarter of 2009, the Utility acquired CRRs through both allocation and auction.

CRRs are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

Natural Gas Procurement (Electric Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the future cash flow variability associated with fluctuating natural gas prices, the Utility purchases financial instruments such as futures, swaps, and options. These financial instruments are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets.

Natural Gas Procurement (Small Commercial and Residential Customers)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “core,” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the monthly and, to a lesser extent, daily spot market to balance such seasonal supply and demand.

The Utility manages its winter exposure to variable natural gas prices in accordance with its CPUC-approved annual core portfolio hedging implementation plan. Accordingly, the Utility has entered into various financial instruments, such as swaps and options, intended to reduce the uncertainty associated with fluctuating natural gas purchase prices. These financial instruments are considered derivative instruments that are recorded at fair value within the Condensed Consolidated Balance Sheets.

Other Risk

At September 30, 2009, PG&E Corporation had $247 million of Convertible Subordinated Notes outstanding scheduled to mature on June 30, 2010. The 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 prices. The dividend participation rights associated with the Convertible Subordinated Notes are embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other income (expense), net).

Volume of Derivative Activity

At September 30, 2009, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts was as follows:

		Contract Volumes (1)
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year But Less Than 3 Years		Greater Than 3 Years But Less Than 5 Years		Greater Than 5 Years (2)
Natural Gas (3) (MMBtus (4))	Forwards, Futures, and Swaps		331,103,829		192,707,140		21,277,500		-
	Options		136,232,644		86,837,080		-		-

Electricity (Megawatt-hours)	Forwards, Futures, and Swaps		3,508,656		7,644,024		5,093,912		4,768,447
	Options		9,400		11,450		110,980		557,512
	Congestion Revenue Rights		55,374,468		64,267,318		59,648,715		107,581,890

PG&E Corporation Equity (Shares)	Dividend Participation Rights		16,370,789		-		-		-

(1) Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.
(2) Derivatives in this category expire between 2014 and 2022.
(3) Amounts shown are for the combined positions of the electric and core gas portfolios.
(4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists. The net balances include outstanding cash collateral associated with derivative positions.

At September 30, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

(in millions)	Gross Derivative Balance (1)			Netting (2)			Cash Collateral (2)		Total Derivative Balances
Commodity Risk (PG&E Corporation and Utility)
Current Assets – Prepaid expenses and other	$	48		$	(9	)	$	63	$	102
Other Noncurrent Assets – Other		120			(40	)		21		101
Current Liabilities – Other		(253	)		9			84		(160	)
Noncurrent Liabilities – Other		(379	)		40			29		(310	)
Total commodity risk	$	(464	)	$	-		$	197	$	(267	)

Other Risk Instruments (3) (PG&E Corporation Only)
Current Liabilities – Other	$	(20	)	$	-		$	-	$	(20	)
Total derivatives	$	(484	)	$	-		$	197	$	(287	)

(1) See Note 8 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the valuation techniques used to calculate the fair value of these instruments.
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

Expenses related to the dividend participation rights are not recoverable in customers’ rates. Therefore, changes in the fair value of these instruments are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income.

For the nine month period ended September 30, 2009, the gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:

(in millions)
Commodity Risk (PG&E Corporation and Utility)
Unrealized gain/(loss) - Regulatory assets andliabilities (1)	$	32
Realized gain/(loss) - Cost of electricity(2)		(558	)
Realized gain/(loss)- Cost of natural gas (2)		(30	)
Total commodity risk instruments	$	(556	)
Other Risk Instruments(3) (PG&E Corporation Only)
Other income, net	$	1
Total other risk instruments	$	1

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
(3) This category relates to dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

Cash inflows and outflows associated with the settlement of all derivative instruments are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At September 30, 2009, the additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered was as follows:

(in millions)
Derivatives in a liability position with credit-risk-relatedcontingencies that are not fully collateralized	$	(541	)
Related derivatives in an asset position		57
Collateral posting in the normal course of business relatedto these derivatives		70
Net position of derivative contracts/additional collateral posting requirements (1)	$	(414	)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit-risk-related contingencies.

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility determine the fair value of certain assets and liabilities based on assumptions that market participants would use in pricing the assets or liabilities. PG&E Corporation and the Utility utilize a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value and give precedence to observable inputs in determining fair value. An instrument’s level within the hierarchy is based on the lowest level of any significant input to the fair value measurement. See Note 12 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report for further discussion of fair value measurements.

The following table sets forth the fair value hierarchy by level of PG&E Corporation’s and the Utility’s recurring fair value financial instruments at September 30, 2009. PG&E Corporation’s and the Utility’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PG&E Corporation
Fair Value Measurements at September 30, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments (held by PG&E Corporation)	$	185	$	-	$	5	$	190
Nuclear decommissioning trusts
Equity securities		1,081		-		6		1,087
U.S. government and agency issues		661		52		-		713
Municipal bonds and other		-		183		-		183
Total nuclear decommissioning trusts (1)		1,742		235		6		1,983
Rabbi trusts-equity securities		76		-		-		76
Long-term disability trust
Equity securities		8		-		20		28
Corporate debt securities		-		-		101		101
Total long-term disability trust		8		-		121		129
Total assets	$	2,011	$	235	$	132	$	2,378
Liabilities:
Dividend participation rights	$	-	$	-	$	20	$	20
Price risk management instruments(2)		25		85		157		267
Other		-		-		4		4
Total liabilities	$	25	$	85	$	181	$	291

(1) Excludes deferred taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments of $76 million to Level 1, $33 million to Level 2, and $88 million to Level 3.

Utility
Fair Value Measurements at September 30, 2009
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts
Equity securities	$	1,081	$	-	$	6	$	1,087
U.S. government and agency issues		661		52		-		713
Municipal bonds and other		-		183		-		183
Total nuclear decommissioning trusts(1)		1,742		235		6		1,983
Long-term disability trust
Equity securities		8		-		20		28
Corporate debt securities		-		-		101		101
Total long-term disability trust		8		-		121		129
Total assets	$	1,750	$	235	$	127	$	2,112
Liabilities:
Price risk management instruments (2)	$	25	$	85	$	157	$	267
Other		-		-		4		4
Total liabilities	$	25	$	85	$	161	$	271

(1) Excludes deferred taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments of $76 million to Level 1, $33 million to Level 2, and $88 million to Level 3.

PG&E Corporation’s and the Utility’s fair value measurements incorporate various factors, such as nonperformance and credit risk adjustments. At September 30, 2009, the nonperformance and credit risk adjustment represented 1% of the net price risk management value. PG&E Corporation and the Utility utilize a mid-market pricing convention (the midpoint between bid and ask prices) as a practical expedient in valuing the majority of its derivative assets and liabilities at fair value.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating the fair value of financial instruments:

·	The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, price risk management assets and liabilities, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2009 and December 31, 2008.

·	The fair values of the Utility’s fixed rate senior notes, fixed rate pollution control bond loan agreements, PG&E Corporation’s Convertible Subordinated Notes, PG&E Corporation’s fixed rate senior notes, and the ERBs issued by PERF were based on quoted market prices at September 30, 2009 and December 31, 2008.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s financial instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At September 30,				At December 31,
	2009				2008
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4):
PG&E Corporation	$	597	$	1,061	$	280	$	739
Utility		8,690		9,528		8,740		9,134
Energy recovery bonds (Note 4)		1,310		1,357		1,583		1,564

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility is unable to assert that it has the intent and ability to hold investments to maturity. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of asset retirement obligations. There is no impact on the Utility’s earnings or accumulated other comprehensive income. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.)

The following table provides a summary of the fair value of the investments held in the Utility’s nuclear decommissioning trusts:

	Maturity Date		Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated (1) Fair Value
(in millions)
Nine months ended September 30, 2009
U.S. government and agency issues		2009-2038	$	648	$	66	$	(1	)	$	713
Municipal bonds and other		2009-2049		179		6		(2	)		183
Equity securities				546		543		(2	)		1,087
Total			$	1,373	$	615	$	(5	)	$	1,983

(1) Excludes deferred taxes on appreciation of investment value.

The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of the activity for the debt and equity securities:

	Nine Months Ended September 30,			Year Ended December 31,
	2009			2008
(in millions)
Gross realized gains on sales of securities held as available-for-sale	$	24		$	30
Gross realized losses on sales of securities held as available-for-sale		(52	)		(142	)

In general, investments held in the nuclear decommissioning trust are exposed to various risks, such as interest rate, credit, and market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.

Level 3 Rollforward

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the nine month period ended September 30, 2009:

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission-ing Trusts Equity Securities (1)		Long-Term Disability Equity Securities			Long-Term Disability Corp. Debt Securities		Other			Total
Asset (Liability) Balance as of January 1, 2009	$	12		$	(42	)	$	(156	)	$	5	$	54		$	24	$	(2	)	$	(105	)
Realized and unrealized gains (losses):
Included in earnings		-			1			-			-		11			3		-			15
Included in regulatory assets and liabilities or balancing accounts		-			-			(1	)		1		-			-		(2	)		(2	)
Purchases, issuances, and settlements		(7	)		21			-			-		(45	)		74		-			43
Transfers in to Level 3		-			-			-			-		-			-		-			-
Asset (Liability) Balance as of September 30, 2009	$	5		$	(20	)	$	(157	)	$	6	$	20		$	101	$	(4	)	$	(49	)

(1) Excludes deferred taxes on appreciation of investment value.

Earnings for the period were impacted by a $15 million unrealized gain relating to assets or liabilities still held at September 30, 2009.

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the three month period ended September 30, 2009:

	PG&E Corporation Only					PG&E Corporation and the Utility
(in millions)	Money Market		Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission-ing Trusts Equity Securities (1)		Long-term Disability Equity Securities			Long-term Disability Corp. Debt Securities		Other			Total
Asset (Liability) Balance as of July 1, 2009	$	5	$	(27	)	$	(189	)	$	5	$	57		$	24	$	(3	)	$	(128	)
Realized and unrealized gains (losses):
Included in earnings		-		-			-			-		8			2		-			10
Included in regulatory assets and liabilities or balancing accounts		-		-			32			1		-			-		(1	)		32
Purchases, issuances, and settlements		-		7			-			-		(45	)		75		-			37
Transfers in to Level 3		-		-			-			-		-			-		-			-
Asset (Liability) Balance as of September 30, 2009	$	5	$	(20	)	$	(157	)	$	6	$	20		$	101	$	(4	)	$	(49	)

(1) Excludes deferred taxes on appreciation of investment value.

Earnings for the period were impacted by a $10 million unrealized gain relating to assets or liabilities still held at September 30, 2009.

PG&E Corporation and the Utility did not have any nonrecurring financial measurements requiring disclosure at September 30, 2009.

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are generally priced at the higher of fully loaded cost (i.e., direct cost of goods or services and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2009		2008		2009		2008
Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	-	$	4	$	2
Utility expenses from:
Administrative services received from PG&E Corporation	$	14	$	34	$	47	$	86
Utility employee benefit due to PG&E Corporation		4		5		13		16

At September 30, 2009 and December 31, 2008, the Utility had a receivable of $28 million and $29 million, respectively, from PG&E Corporation included in Accounts receivable – Related parties and Other Noncurrent Assets – Related parties receivable on the Utility’s Condensed Consolidated Balance Sheets, and a payable of $14 million and $25 million, respectively, to PG&E Corporation included in Accounts payable – Related parties on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001.

In connection with the Utility’s proceeding under Chapter 11, the Utility established an escrow account to fund future settlements and for the payment of disputed claims, which is included within Restricted cash on the Condensed Consolidated Balance Sheets. At September 30, 2009 and December 31, 2008, the Utility held $515 million and $1,212 million, respectively, in escrow, including interest earned, for payment of the remaining net disputed claims.

While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in 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 through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be credited to customers.

On August 26, 2009, following the approval by the FERC, the bankruptcy court presiding over the PX’s bankruptcy case, and the bankruptcy court that retains jurisdiction over the Utility’s Chapter 11 proceeding, the Utility paid $700 million to the PX from the Utility’s escrow account to reduce the Utility’s liability for the remaining net disputed claims. The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 2008 to September 30, 2009:

(in millions)
Balance at December 31, 2008	$	1,750
Interest accrued		45
Less: Supplier Settlements		(90	)
Less: August 26, 2009 payment		(700	)
Balance at September 30, 2009	$	1,005

At September 30, 2009, the Utility’s net disputed claims liability was $1,005 million, consisting of $816 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within Accounts payable – Disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $683 million (classified on the Condensed Consolidated Balance Sheets within Interest payable) offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within Accounts receivable – Customers).

Interest accrues on the liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims.

PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that the Utility will be required to pay.

NOTE 11: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental compliance and remediation, tax matters, 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 power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase. Forward prices at September 30, 2009 are used to determine the undiscounted future expected payments for contracts with variable pricing terms. At September 30, 2009, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)
2009	$	535
2010		2,165
2011		2,111
2012		2,211
2013		2,209
Thereafter		36,141
Total	$	45,372

Payments made by the Utility under power purchase agreements amounted to $1,809 million and $3,631 million for the nine months ended September 30, 2009 and September 30, 2008, respectively. The amounts above do not include payments related to the DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (“QFs”) are treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as capital leases. (These amounts are also included in the third-party power purchase agreements table above.) The fixed capacity payments are discounted to their present value 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)
2009	$	11
2010		50
2011		50
2012		50
2013		50
Thereafter		206
Total fixed capacity payments		417
Less: Amount representing interest		95
Present value of fixed capacity payments	$	322

Minimum lease payments associated with the lease obligation are included in Cost of electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. 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 are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF exceeds or fails to meet performance requirements specified in the applicable power purchase agreement.

Natural Gas Supply and Transportation Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation to transport natural gas from the points at which the Utility takes delivery (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.

At September 30, 2009, the Utility’s undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2009	$	341
2010		610
2011		124
2012		49
2013		42
Thereafter		157
Total	$	1,323

Payments for natural gas purchases and gas transportation services amounted to $959 million and $2,227 million for the nine months ended September 30, 2009 and September 30, 2008, respectively.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 16 years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2013, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2011. 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 are also diversified, ranging from 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, 2009, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2009	$	153
2010		108
2011		100
2012		90
2013		118
Thereafter		1,226
Total	$	1,795

Payments for nuclear fuel amounted to $67 million and $96 million for the nine months ended September 30, 2009 and September 30, 2008, 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. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

Utility

Application to Recover Hydroelectric Facility Divestiture Costs

On April 16, 2009, the CPUC approved a decision to authorize the Utility to recover $47 million of costs, including $12 million of interest, that the Utility incurred in connection with its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken as required by the CPUC in connection with the proposed divestiture of the facilities to further the development of a competitive generation market in California. The CPUC subsequently withdrew this requirement. The Utility continues to own its hydroelectric generation assets. The Utility expects that the rate adjustments necessary to recover these authorized costs will be combined with other rate adjustments in the Utility’s annual electric rate true-up proceeding. These rate changes are expected to become effective in January 2010.

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 dispose of nuclear waste from the Utility’s two nuclear generating units at 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.

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. Because the DOE failed to develop a permanent storage site, the Utility obtained 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. The construction of the dry cask storage facility is complete and the movement of spent nuclear fuel to dry cask storage began in June 2009.

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 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.

In October 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit. On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding. The Utility’s brief on appeal was filed on April 8, 2009. No date has been set for oral argument.

As a result of the DOE’s failure to build a national repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility seeks to recover $92 million of costs that it incurred through 2004. After several years of litigation, the DOE now concedes that the Utility is entitled to recover approximately $82 million of these costs, but the DOE continues to dispute the remaining amount. The trial to determine the appropriate method to calculate the amounts owed to the Utility began on October 15, 2009. The Utility also will seek to recover costs incurred after 2004 to build on-site storage facilities.

PG&E Corporation and the Utility are unable to predict the amount and timing of any recoveries that the Utility will receive from the DOE. Amounts recovered from the DOE will be credited to customers.

Energy Efficiency Programs and Incentive Ratemaking

The CPUC previously established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. On December 18, 2008, based on their first interim claims, the CPUC awarded interim incentive earnings to the utilities for their 2006-2007 program performance. In the fourth quarter of 2008, the Utility recognized a CPUC award of $41.5 million for the Utility’s energy efficiency program performance in 2006-2007. Under the existing incentive ratemaking mechanism, the maximum amount of revenue that the Utility could earn and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.

On January 29, 2009, the CPUC established a new rulemaking proceeding to modify the existing incentive ratemaking mechanism for programs beginning in 2009 and future years, to adopt a new framework to review the utilities’ 2006-2008 program performance for the second interim claim, and to conduct a final review of the utilities’ performance over the 2006-2008 program period. On May 21, 2009, the Utility, San Diego Gas & Electric Company, Southern California Gas Company, and the Natural Resources Defense Council jointly requested that the CPUC approve a proposed settlement to resolve the utilities’ second interim claims and their final 2006-2008 true-up incentive claims. On July 10, 2009, the Utility submitted calculations, based on the methodology included in the proposed settlement, indicating that the Utility would be entitled to earn the remaining amount of the maximum incentives that could be earned for the 2006-2008 period. Based on the holdback amount proposed in the settlement, the Utility would be entitled to receive $76.6 million in incentive earnings and an additional $61.9 million would be held back and subject to verification in the final 2006-2008 true-up process to be completed in 2010. The assigned administrative law judge has ruled that there will be no hearings on the settlement proposal.

In accordance with the process established by the current incentive ratemaking mechanism, on October 15, 2009, the CPUC approved a second verification report issued by the CPUC’s Energy Division relating to the second interim claims for the utilities’ 2006-2008 program performance. The report calculates potential incentive amounts for the Utility, based on different energy savings assumptions and measurement methods, that range up to $20.6 million with up to an additional $33.4 million to be held back pending completion of the 2006-2008 true-up process in 2010. In addition, on September 3 and October 1, 2009, the CPUC’s Energy Division released additional incentive award scenarios, including scenarios based on the proposed settlement, that result in a wide range of potential financial outcomes. It is uncertain what effect, if any, the issuance of the verification report or the scenarios will have on the likelihood of the proposed settlement becoming effective. Whether the proposed settlement will be approved and the amounts of any interim and final claims that may be awarded to the Utility are uncertain at this time.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at 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 $39.7 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Under the Terrorism Risk Insurance Program Reauthorization Act of 2007 (“TRIPRA”), acts of terrorism may be “certified” by the Secretary of the Treasury. For a certified act of terrorism, NEIL can obtain compensation from the federal government and will provide up to the full policy limits to the Utility for an insured loss. If one or more non-certified acts of 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. (TRIPRA extends the Terrorism Risk Insurance Act of 2002 through December 31, 2014.)

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $12.5 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 $12.5 billion of liability protection is covered by a loss-sharing program among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $117.5 million per reactor, with payments in each year limited to a maximum of $17.5 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 $235 million per incident, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

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.

Severance Costs

As of September 30, 2009, the Utility has recorded a liability of $76 million related to severance costs. The following table presents the changes in the liability from December 31, 2008:

(in millions)
Balance at December 31, 2008	$	27
Additional severance costs accrued		72
Less: Payments		(23	)
Balance at September 30, 2009	$	76

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 possible 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, and considering 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 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 and gross environmental remediation liability of $597 million at September 30, 2009 and $568 million at December 31, 2008. The $597 million accrued at September 30, 2009 consists of:

·		$49 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

·		$156 million for remediation at the Utility’s natural gas compressor site located in Topock, Arizona, near the California border;

·		$86 million related to remediation at divested generation facilities;

·		$246 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); and

·		$60 million related to remediation costs for fossil decommissioning sites.

Of the $597 million environmental remediation liability, $146 million has been included in prior rate setting proceedings and the Utility expects that an additional amount of $366 million will be recoverable 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. Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable from customers.

The Utility’s undiscounted future costs could increase to as much as $1 billion 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, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

Diablo Canyon and other generating facilities the Utility purchases electricity from uses a process known as “once-through cooling” that takes in water from the ocean to cool the generating facility and discharges the heated water back into the ocean. There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the U.S. Environmental Protection Agency (“EPA”) issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases.

Various parties separately challenged the EPA’s regulations, and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test could not be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court granted review of the cost-benefit question and in April 2009 issued a decision reversing the Second Circuit and finding permissible the EPA’s use of cost-benefit analysis to set national compliance standards for cooling water intake systems and variances to those standards. The EPA is currently revising its regulations regarding cooling water intake systems. In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued an initial proposed policy to address once-through cooling in June 2006. Since that time, the Water Board reviewed and revised its proposal in response to comments from various California agencies and concerned stakeholders. The Water Board’s current draft proposal, issued in June 2009, requires fossil and nuclear plants to either retrofit to closed cycle cooling or install operational and structural controls to achieve a similar reduction and provides a compliance timeframe for each once-through-cooled facility. The proposal also requires the development of a once-through cooling alternatives study for nuclear plants and requires that Diablo Canyon be in compliance with the policy by December 31, 2021, unless compliance would conflict with a nuclear safety requirement or the cost of compliance is wholly disproportionate to the benefits.

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 of the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.

Tax Matters

In March 2009, PG&E Corporation received a cash refund of $294 million, in accordance with the settlement reached with the Internal Revenue Service (“IRS”) to resolve the IRS’ audits of tax years 2001 through 2004. (PG&E Corporation applied $80 million of the refund it otherwise would have received in cash to make an estimated income tax payment for tax year 2008.) Currently, PG&E Corporation has approximately $65 million of federal capital loss carry forwards based on tax returns as filed and the resolution of the IRS audit of tax years 2001 through 2004. Of the $65 million federal capital loss carry forwards, approximately $25 million will expire if not used by the end of 2009.

On June 8, 2009, the IRS agreed to settle refund claims related to the 1998 and 1999 tax years. As a result of this settlement, PG&E Corporation and the Utility recognized after tax income of $56 million in the second quarter of 2009. In the third quarter of 2009, PG&E Corporation and the Utility received cash refunds of tax and interest totaling $311 million in accordance with this settlement.

During the three months ended September 30, 2009, PG&E Corporation recognized $12 million in California tax and related interest benefits attributable to the two IRS settlements discussed above.

The IRS is currently auditing PG&E Corporation’s consolidated income tax returns for tax years 2005 through 2007. The IRS has not proposed any material adjustments for the 2005 through 2007 audit. On September 16, 2009, the IRS released standards for the resolution of an issue involved in the 2005-2007 audit, enabling PG&E Corporation to recognize net tax benefit of $17 million.

PG&E Corporation is participating in the IRS’s Compliance Assurance Process (“CAP”), a real-time audit process intended to expedite the resolution of issues raised during audits, for tax years 2008 and 2009. The IRS has not proposed any material adjustments for tax years 2008 or 2009, except for adjustments to reflect the rollover impact of audit settlements involving prior tax years. In September 2009, the IRS gave its consent for PG&E Corporation to change a tax method for 2008. This allowed PG&E Corporation to record a net benefit of $2 million, including interest, due to this change.

As a result of the events described above, PG&E Corporation’s forecasted effective tax rate for 2009 has decreased by 1.6%. In addition, the primary impact to PG&E Corporation and the Utility’s balance sheets is an increase of regulatory asset by $37 million, an increase of noncurrent income tax receivable by $522 million, and an increase of noncurrent deferred tax liabilities by $543 million in the third quarter 2009.

The California Franchise Tax Board is currently auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns. To date, no material adjustments have been proposed. In addition to the federal capital loss carry forwards, PG&E Corporation has approximately $200 million of California capital loss carry forwards based on tax returns as filed, the majority of which will expire if not used by the end of 2009.

For a discussion of unrecognized tax benefits, see Note 10 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report. During the three months ended September 30, 2009, PG&E Corporation increased the gross amount of unrecognized tax benefits by $531 million due to the events described above. If the full amount were recognized, approximately $50 million would reduce PG&E Corporation’s effective tax rate with the remaining balance representing the probable deferral of taxes to later years. Further, it is reasonably possible that unrecognized tax benefits could decrease in the next 12 months by an amount ranging from $0 to $30 million for PG&E Corporation and the Utility.

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.

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 accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, 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 $51 million at September 30, 2009 and $72 million at December 31, 2008. After consideration of these accruals, PG&E Corporation and the Utility do not expect that losses associated with legal matters would have a material adverse impact on their financial condition and results of operations.

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 (“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 5.1 million electricity distribution customers and 4.3 million natural gas distribution customers at September 30, 2009. The Utility had $42.3 billion in assets at September 30, 2009 and generated revenues of $9.9 billion in the nine months ended September 30, 2009.

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”). 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, 2008, which, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2008 Annual Report.” Significant developments that have occurred since the 2008 Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed in this Quarterly Report on Form 10-Q.

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, as well as the accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain. 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 the Notes to the Condensed Consolidated Financial Statements included in this quarterly report, as well as the MD&A, the audited Consolidated Financial Statements, and the Notes to the Consolidated Financial Statements incorporated by reference in the 2008 Annual Report.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Nine Months Ended September 30, 2009

PG&E Corporation’s diluted earnings per common share (“EPS”) was $0.83 for each of the three months ended September 30, 2009 and 2008. For the nine months ended September 30, 2009, PG&E Corporation’s diluted EPS was $2.49 compared to $2.24 for the same period in 2008. PG&E Corporation’s income available for common shareholders for the three months ended September 30, 2009 increased by $14 million, or 5%, to $318 million, compared to $304 million for the same period in 2008. For the nine months ended September 30, 2009, income available for common shareholders increased by $126 million, or 15%, to $947 million, compared to $821 million for the same period in 2008.

The increase in income available for common shareholders for the three months ended September 30, 2009, as compared to the same period in 2008, is attributable to (1) an increase of $24 million, after tax, due to the Utility’s return on equity (“ROE”) earned on higher authorized capital investments, (2) a tax benefit of $10 million associated with the settlement of tax refund claims involving the 1998 and 1999 tax years, (3) a benefit of $11 million, after-tax, as compared to the same period in the prior year when the Utility incurred costs to oppose certain legislation and municipalization efforts, and (4) an increase of $12 million, after tax, reflecting the sum of incentives earned for managing natural gas procurement costs and lower accrual levels for uncollectibles and environmental costs. These increases were partially offset by (1) a $30 million, after tax, decrease attributable to employee severance costs, and (2) a $16 million, after tax, decrease attributable to costs to perform accelerated natural gas leak surveys and associated remedial work.

The increase in diluted EPS and income available for common shareholders for the nine months ended September 30, 2009, as compared to the same period in 2008, is attributable to (1) an increase of $73 million, after tax, representing the Utility’s ROE earned on higher authorized capital investments, (2) an increase of $28 million, after tax, due to the recovery of previously incurred costs related to the Utility’s hydroelectric generation facilities, (3) a benefit of $11 million, after-tax, as compared to the same period in the prior year when the Utility incurred costs to oppose certain legislation and municipalization efforts, (4) a tax benefit of $66 million associated with the settlement of tax refund claims involving the 1998 and 1999 tax years, and (5) a benefit of $24 million, after tax, as compared to the same period in the prior year when the Utility incurred higher storm and outage expenses. These increases were partially offset by (1) a $39 million, after tax, decrease attributable to employee severance costs, and (2) a $32 million, after tax, decrease attributable to costs to perform accelerated natural gas leak surveys and associated remedial work.

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, recover its authorized costs timely, 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 and the Impact of Ratemaking Mechanisms. Most of the Utility’s revenue requirements are set based on its costs of service in proceedings such as the General Rate Case (“GRC”) filed with the CPUC and transmission owner (“TO”) rate cases filed with the FERC. (See “Regulatory Matters” below.) The Utility intends to file its 2011-2013 GRC application with the CPUC before the end of 2009 to request an increase in authorized electric distribution, gas distribution, and electric generation revenue requirements. On September 18, 2009, the Utility requested the CPUC to determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011. The Utility also files separate applications requesting the CPUC or the FERC to authorize additional revenue requirements for specific capital expenditure projects, such as new power plants, gas or electric transmission facilities, installation of an advanced metering infrastructure, and reliability or system infrastructure improvements. (See “Capital Expenditures” below.) The Utility’s revenues will also be affected by incentive ratemaking, such as the CPUC’s customer energy efficiency shareholder incentive mechanism. In addition, the CPUC has authorized the Utility to recover 100% of its reasonable electric fuel and energy procurement costs and has established a timely rate adjustment mechanism to recover such costs. As a result, the Utility’s revenues and costs can be affected by volatility in the prices of natural gas and electricity. (See “Risk Management Activities” below.)

·	Capital Structure and Return on Common Equity. The Utility’s current CPUC-authorized capital structure includes a 52% common equity component, which will remain in effect through 2012. The CPUC has authorized the Utility to set rates targeted to earn an ROE of 11.35% on the equity component of its electric and natural gas distribution and electric generation rate base through 2010. The Utility’s cost of capital for 2011 and 2012 will change only if the annual adjustment mechanism established by the CPUC is triggered. If the adjustment is triggered, the Utility’s authorized cost of capital would be adjusted effective January 1 of the following year. The Utility can also apply for an adjustment to either its capital structure or its cost of capital at any time in the event of extraordinary circumstances. (See “Regulatory Matters” below.)

·	The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses, as well as to earn an ROE and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. The Utility also seeks to make the amount and timing of its capital expenditures consistent with budgeted amounts and timing. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense but does not recover revenues to fully offset these expenses or earn an ROE until the increased capital expenditures are added to rate base in future rate cases. Items that could cause higher expenses than provided for in the last GRC primarily relate to the Utility’s efforts to maintain its aging electric and natural gas systems infrastructure, to improve the reliability and safety of its electric and natural gas system, and to improve its information technology infrastructure, support, and security. The Utility continually seeks to achieve operational efficiencies and improve reliability while creating future sustainable cost savings to offset these higher anticipated expenses. In connection with these efforts, the Utility has accrued severance costs, including severance costs related to the reduction of approximately 2% of the Utility’s workforce, in the three months ended September 30, 2009. (See “Results of Operations” below.)

·	Timing and Amount of Debt and Equity Financing. The timing and amount of the Utility’s future financing needs will depend on various factors, including the conditions in the capital markets, the amount and timing of scheduled principal and interest payments on long-term debt, the amount and timing of planned capital expenditures, and the amount and timing of interest payments related to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) The amount of the Utility’s short-term financing will vary depending on the level of operating cash flows, seasonal demand for electricity and natural gas, volatility in electricity and natural gas prices, and collateral requirements related to price risk management activities, among other factors. In order to maintain the Utility’s CPUC-authorized capital structure, PG&E Corporation contributed $688 million of equity to the Utility during 2009. The timing and amount of future equity contributions to the Utility will affect the timing and amount of any future equity or debt issuances by PG&E Corporation. (See “Liquidity and Financial Resources” below.)

FORWARD-LOOKING STATEMENTS

This combined quarterly report on Form 10-Q contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, estimated 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,” “target,” “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 manage capital expenditures and its operating and maintenance expenses within authorized levels;

·	the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;

·	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, including the ability of the Utility and its counterparties to post or return collateral;

·	explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and computer systems, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions, that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

·	the impact of storms, earthquakes, floods, drought, wildfires, disease and similar natural disasters, or acts of terrorism, that affect customer demand, or that damage or disrupt the facilities, operations, or information technology and computer systems owned by the Utility, its customers, or 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 two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

·	whether the Utility can maintain the cost savings that it has recognized from operating efficiencies that it has achieved and identify and successfully implement additional sustainable cost-saving measures;

·	whether the Utility incurs substantial expense to improve the safety and reliability of its electric and natural gas systems;

·	whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives that the Utility may earn in a timely manner;

·	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 the impact of future FERC-ordered changes that will be incorporated into the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by 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 from other third parties;

·	the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

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

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

·	the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

For more information about the 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 in the section entitled “Risk Factors” in the 2008 Annual Report and the discussion below under Part II. Other Information, Item 1A. Risk Factors. 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 months ended September 30, 2009 and 2008:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2009			2008			2009			2008
Utility
Electric operating revenues	$	2,630		$	2,880		$	7,610		$	8,039
Natural gas operating revenues		605			794			2,250			2,946
Total operating revenues		3,235			3,674			9,860			10,985
Cost of electricity		997			1,282			2,763			3,406
Cost of natural gas		134			351			879			1,613
Operating and maintenance		1,047			982			3,143			3,009
Depreciation, amortization, and decommissioning		450			419			1,298			1,239
Total operating expenses		2,628			3,034			8,083			9,267
Operating Income		607			640			1,777			1,718
Interest income		3			20			29			77
Interest expense		(162	)		(170	)		(501	)		(528	)
Other income (expense), net		16			(2	)		52			24
Income Before Income Taxes		464			488			1,357			1,291
Income tax provision		111			167			374			421
Net Income		353			321			983			870
Preferred stock dividend requirement		3			3			10			10
Income Available for Common Stock	$	350		$	318		$	973		$	860
PG&E Corporation, Eliminations, and Other(1)
Operating revenues	$	-		$	-		$	-		$	-
Operating expenses		-			1			1			2
Operating Loss		-			(1	)		(1	)		(2	)
Interest income		(2	)		3			(2	)		5
Interest expense		(12	)		(8	)		(32	)		(22	)
Other income (expense), net		7			(12	)		11			(28	)
Loss Before Income Taxes		(7	)		(18	)		(24	)		(47	)
Income tax provision (benefit)		25			(4	)		2			(8	)
Net Income (Loss)	$	(32	)	$	(14	)	$	(26	)	$	(39	)
Consolidated Total
Operating revenues	$	3,235		$	3,674		$	9,860		$	10,985
Operating expenses		2,628			3,035			8,084			9,269
Operating Income		607			639			1,776			1,716
Interest income		1			23			27			82
Interest expense		(174	)		(178	)		(533	)		(550	)
Other income (expense), net		23			(14	)		63			(4	)
Income Before Income Taxes		457			470			1,333			1,244
Income tax provision		136			163			376			413
Net Income		321			307			957			831
Preferred stock dividend requirement of subsidiary		3			3			10			10
Income Available for Common Shareholders	$	318		$	304		$	947		$	821

(1) 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, 2009 and 2008.

Electric Operating Revenues

The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, the Utility relies on electricity provided under long-term contracts entered into by the California Department of Water Resources (“DWR”) to meet a material portion of the Utility’s customers’ demand for electricity (“load”). The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and procurement and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of public purpose, energy efficiency, and demand response programs.

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)	2009			2008			2009			2008
Electric revenues	$	3,233		$	3,255		$	9,066		$	9,044
DWR pass-through revenues(1)		(603	)		(375	)		(1,456	)		(1,005	)
Total electric operating revenues	$	2,630		$	2,880		$	7,610		$	8,039

(1)These are revenues collected on behalf of the 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 total electric operating revenues decreased by $250 million, or 9%, in the three months ended September 30, 2009 and $429 million, or 5%, in the nine months ended September 30, 2009, compared to the same period in 2008, due to the following factors:

·	Electricity costs passed through to customers decreased by $285 million in the three months ended September 30, 2009 and $643 million in the nine months ended September 30, 2009. (See “Cost of Electricity” below.)

·	Public purpose program costs passed through to customers decreased by $2 million in the three months ended September 30, 2009 and $46 million in the nine months ended September 30, 2009 due to the timing of program spending. (See “Operating and Maintenance” below.)

·	CAISO collateral costs, passed through to customers, related to the new day-ahead market decreased by $20 million in the three months ended September 30, 2009. (See “Operating and Maintenance” below.)

·	Other miscellaneous electric operating revenues decreased by $13 million in the three months ended September 30, 2009.

These decreases were partially offset by the following:

·	Base revenues increased by $26 million in the three months ended September 30, 2009 and $77 million in the nine months ended September 30, 2009, as previously authorized in the 2007 GRC.

·	Revenues associated with separately funded projects placed in service, including the Gateway Generating Station and the new steam generators at Diablo Canyon, increased by $44 million in the three months ended September 30, 2009 and $137 million in the nine months ended September 30, 2009.

·	Electric operating revenues increased by $35 million in the nine months ended September 30, 2009 for the recovery of previously incurred costs related to hydroelectric generation facilities. (See “Regulatory Matters” below.)

·	Other miscellaneous electric operating revenues increased by $11 million in the nine months ended September 30, 2009.

The Utility’s electric operating revenues for the remainder of 2009 and 2010 are expected to increase, as authorized by the CPUC in the 2007 GRC. The Utility’s electric operating revenues for future years are also expected to increase, as authorized by the FERC in the TO rate cases and by the CPUC in the 2011 GRC. (See “Regulatory Matters” below.)

In addition, the Utility expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including capital expenditures for the new Utility-owned generation projects and the SmartMeterTM advanced metering project. Revenues would also increase to the extent that the CPUC approves the Utility’s proposal for other capital projects. (See “Capital Expenditures” below.)

Revenue requirements associated with new or expanded public purpose, energy efficiency, and demand response programs will also result in increased electric operating revenues. In addition, future electric operating revenues are affected by changes in the Utility’s electricity procurement costs, as discussed under “Cost of Electricity” below. Finally, the Utility may recognize additional incentive revenues to the extent that it achieves the CPUC’s energy efficiency goals. (See “Regulatory Matters” below.)

Cost of Electricity

The Utility’s cost of electricity includes purchased power costs, certain transmission costs, the cost of fuel used in its generation facilities, and the cost of fuel supplied to other facilities under tolling agreements. These costs are passed through to customers. The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See Notes 7 and 8 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of electricity excludes non-fuel costs associated with the Utility’s own generation facilities, which are included in Operating and maintenance expense in the Condensed Consolidated Statements of Income. The cost of electricity provided under power purchase agreements between the DWR and various power suppliers is also excluded from the Utility’s cost of electricity.

The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2009		2008		2009		2008
Cost of purchased power	$	947	$	1,244	$	2,620	$	3,286
Fuel used in own generation		50		38		143		120
Total cost of electricity	$	997	$	1,282	$	2,763	$	3,406
Average cost of purchased power per kWh (1)	$	0.076	$	0.092	$	0.081	$	0.090
Total purchased power (in millions of kWh)		12,524		13,561		32,238		36,553

(1) Kilowatt-hour.

The Utility’s total cost of electricity decreased by $285 million, or 22%, in the three months ended September 30, 2009 and by $643 million, or 19%, in the nine months ended September 30, 2009, compared to the same periods in 2008. This was primarily due to a decrease in the average cost of purchased power of 17% for the three months ended September 30, 2009 and 10% for the nine months ended September 30, 2009, as well as a decrease in the total volume of purchased power of 8% for the three months ended September 30, 2009 and 12% for the nine months ended September 30, 2009. The decrease in the average cost of purchased power was primarily driven by lower market prices for electricity and gas. The decrease in the volume of purchased power was primarily the result of milder weather and a decrease in residential, commercial, and industrial demand due to the continued economic downturn as compared to the same periods in 2008.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power that the Utility produces, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or renegotiated. The Utility will incur higher costs to purchase power during the extended scheduled outage that began at Diablo Canyon Unit 2 in October 2009 to refuel and replace the unit’s reactor vessel head. In addition, the output from the Utility’s hydroelectric generation facilities is dependent on levels of precipitation and could impact the volume of purchased power.

The Utility’s future cost of electricity also may be affected by federal or state legislation or rules that 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. In particular, costs are likely to increase in the future when California’s statewide greenhouse gas emissions reduction law is implemented.

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 and a distribution system. The transmission system transports gas throughout its service territory 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. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2009		2008		2009		2008
Bundled natural gas revenues	$	525	$	709	$	2,003	$	2,699
Transportation service-only revenues		80		85		247		247
Total natural gas operating revenues	$	605	$	794	$	2,250	$	2,946
Average bundled revenue per Mcf(1) of natural gas sold	$	15.91	$	20.85	$	10.77	$	13.36
Total bundled natural gas sales (in millions of Mcf)		33		34		186		202

(1) One thousand cubic feet.

The Utility’s total natural gas operating revenues decreased by $189 million, or 24%, in the three months ended September 30, 2009 and by $696 million, or 24%, in the nine months ended September 30, 2009, compared to the same periods in 2008, primarily due to decreases in the total cost of natural gas of $217 million in the three months ended September 30, 2009 and $734 million in the nine months ended September 30, 2009. (See “Cost of Natural Gas” below.) This decrease was partially offset by the following:

·	Natural gas operating revenues increased by $8 million and $24 million in the three and nine months ended September 30, 2009, respectively, due to previously authorized increases in the Utility’s base revenue requirements for natural gas transportation, storage, and distribution services.

·	Public purpose program costs passed through to customers increased by $10 million in the three months ended September 30, 2009 and $5 million in the nine months ended September 30, 2009 primarily due to increased energy efficiency measures and rebates. (See “Operating and Maintenance” below.)

·	Other miscellaneous natural gas operating revenues increased by $10 million in the three months ended September 30, 2009 and $9 million in the nine months ended September 30, 2009.

The Utility’s future natural gas operating revenues will be affected by changes in the cost of natural gas, natural gas throughput volume, previously authorized increases in 2010 revenue requirements, and the amount of incentive revenues that the Utility may receive to the extent that it achieves the CPUC’s energy efficiency goals. The Utility’s future natural gas operating revenues will also be affected by the outcome of the Utility’s application in its Gas Transmission and Storage rate case in which the Utility has requested the CPUC to establish revenue requirements for natural gas transmission and storage services for 2011 through 2014. (See “Regulatory Matters” below.)

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines and intrastate pipelines, and gas storage costs, but excludes the transportation costs for large commercial and industrial (or “non-core”) customers, which are included in Operating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Notes 7 and 8 of the Notes to the Condensed Consolidated Financial Statements.)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2009		2008		2009		2008
Cost of natural gas sold	$	96	$	314	$	760	$	1,517
Transportation cost of natural gas sold		38		37		119		96
Total cost of natural gas	$	134	$	351	$	879	$	1,613
Average cost per Mcf of natural gas sold	$	2.91	$	9.24	$	4.09	$	7.51
Total natural gas sold (in millions of Mcf)		33		34		186		202

The Utility’s total cost of natural gas decreased in the three and nine months ended September 30, 2009 by $217 million, or 62%, and by $734 million, or 46%, respectively, compared to the same periods in 2008, primarily due to decreases in the market price of natural gas.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility’s future cost of gas may be affected by federal or state legislation or rules to regulate the emissions of greenhouse gases from the Utility’s natural gas transportation and distribution facilities and from natural gas consumed by the Utility’s customers.

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. Operating and maintenance expenses are influenced by wage inflation; employee benefits; property taxes; the timing and length of Diablo Canyon refueling outages; storms, wild fires, and other events causing outages and damages in the Utility’s service territory; environmental remediation costs; legal costs; materials costs; the level of uncollectible customer accounts; and various other administrative and general expenses. The Utility seeks to recover these expenses through authorized revenue requirements collected in rates. The CPUC authorizes the majority of the Utility’s revenue requirements intended to recover these expenses in GRCs. Revenue requirements are typically based on a forecast of costs for the first (or “test”) year of a GRC cycle followed by annual attrition increases until the first year of the next GRC. The Utility’s next GRC will set revenue requirements beginning January 1, 2011. (See “Regulatory Matters” below.) In addition to authorized attrition increases in revenue requirements for 2009 and 2010 that help to offset increased expenses, the Utility seeks to achieve operational efficiencies and implement other anticipated cost-saving measures to manage expenses.

The Utility’s operating and maintenance expenses increased by $65 million, or 7%, in the three months ended September 30, 2009, primarily due to a net increase in employee severance costs of $50 million. (This amount includes an accrual of $57 million for severance costs related to the reduction of approximately 2% of the Utility’s workforce.) In addition, the Utility incurred a $27 million increase in costs to perform accelerated natural gas leak surveys and associated remedial work, as compared to the same period in 2008. (The Utility targets completing the accelerated portion of this survey work by the second quarter of 2010.) The Utility also incurred a $20 million increase in employee benefit costs (primarily driven by rising healthcare costs) and a $6 million increase in property taxes. These increases were partially offset by a $20 million decrease in CAISO collateral costs, which are passed through to customers, related to the new day-ahead market, an $8 million decrease in public purpose program expenses, a $4 million decrease in uncollectible customer accounts, and a $6 million decrease in other miscellaneous operating and maintenance expenses.

The Utility’s operating and maintenance expenses increased by $134 million, or 4%, in the nine months ended September 30, 2009 compared to the same period in 2008, primarily due to a net increase in employee severance costs of $65 million, a $54 million increase in costs to perform accelerated natural gas leak surveys and associated remedial work, a $46 million increase in employee benefit costs (primarily driven by rising healthcare costs), and an increase of $20 million in the accrual for employee vacation pay, as compared to the same period in 2008. In addition, there was a $15 million increase in property taxes, an increase of $8 million in the Utility’s uncollectible customer accounts as a result of economic conditions and rising unemployment in the Utility’s service territory, and a $23 million increase in other miscellaneous operating and maintenance expenses. These increases were partially offset by decreases in public purpose program expenses of $59 million, and decreases in labor costs of $38 million compared to those incurred in 2008 as a result of the January 2008 winter storm.

The Utility anticipates that it will incur higher costs in the future to improve the safety and reliability of its electric and natural gas system infrastructure and to maintain its aging electric distribution system. The Utility also expects that it will incur higher expenses in future periods to obtain permits or comply with permitting requirements, including costs associated with renewing FERC licenses for the Utility’s hydroelectric generation facilities. To help offset these increased costs, the Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable cost savings.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased by $31 million, or 7%, in the three months ended September 30, 2009 and $59 million, or 5%, in the nine months ended September 30, 2009, as compared to the same periods in 2008. Depreciation expense increased by $25 million and $82 million in the three and nine months ended September 30, 2009, respectively, primarily due to authorized capital additions and depreciation rate changes. In addition, amortization expense related to the energy recovery bonds (“ERBs”) increased by $6 million in the three and nine months ended September 30, 2009 compared to the same periods in 2008 primarily due to increased recovery rates. These increases were partially offset by a decrease in decommissioning expense of $22 million in the nine months ended September 30, 2009, as compared to the same period in 2008. In addition, miscellaneous amortization and decommissioning expenses decreased $7 million in the nine months ended September 30, 2009, as compared to the same period in 2008.

The Utility’s depreciation expense for the remainder of 2009 and 2010 is expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the CPUC. Depreciation expenses in subsequent years will be determined based on rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case, and by the FERC in future TO rate cases.

Interest Income

In the three and nine months ended September 30, 2009, the Utility’s interest income decreased $17 million, or 85%, and $48 million, or 62%, respectively, as compared to the same periods in 2008 primarily due to the following factors:

·	Interest income decreased by $6 million in the three months ended September 30, 2009, and $34 million in the nine months ended September 30, 2009, due to lower interest rates affecting various balancing accounts and regulatory assets.

·	Interest income decreased by $6 million in the three months ended September 30, 2009, and $19 million in the nine months ended September 30, 2009, due to lower interest rates earned on restricted cash held in escrow related to Chapter 11 disputed claims. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

·	Interest income decreased by $5 million in the three months ended September 30, 2009, and $7 million in the nine months ended September 30, 2009, due to decreases in other interest income.

The decrease in the nine months ended September 30, 2009 compared to the same period in 2008 was partially offset by an increase of $12 million in the nine months ended September 30, 2009 for the recovery of interest on previously incurred costs related to the hydroelectric generation facilities. (See “Regulatory Matters” below.)

The Utility’s interest income in 2009 and future periods will be primarily affected by changes in the balance of restricted cash held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates.

Interest Expense

In the three and nine months ended September 30, 2009, interest expense decreased $8 million, or 5%, and $27 million, or 5%, respectively, as compared to the same periods in 2008 primarily due to the following factors:

·	Interest expense accrued on the liability for Chapter 11 disputed claims decreased by $12 million in the three months ended September 30, 2009, and $40 million in the nine months ended September 30, 2009, as the FERC-mandated interest rates declined.

·	Interest expense decreased by $9 million in the three months ended September 30, 2009, and $26 million in the nine months ended September 30, 2009, due to lower interest rates affecting various balancing accounts.

·	Interest expense decreased by $4 million in the three months ended September 30, 2009, and $12 million in the nine months ended September 30, 2009, due to the reduction of the outstanding balance of ERBs.

·	Interest expense on pollution control bonds decreased by $2 million in the three months ended September 30, 2009, and $10 million in the nine months ended September 30, 2009, primarily due to the repurchase of auction rate pollution control bonds in March and April 2008, which the Utility partially refunded, though at lower interest rates, in September and October 2008.

·	Interest expense decreased by $9 million in the nine months ended September 30, 2009, due to an increase in interest expense in 2008 related to previously incurred scheduling coordinator costs.

·	Interest expense decreased by $5 million in the three months ended September 30, 2009, and $6 million in the nine months ended September 30, 2009, due to lower interest rates on the Utility’s short-term debt.

·	Interest expense decreased by $2 million in the three months ended September 30, 2009, and $5 million in the nine months ended September 30, 2009, due to decreases in other interest expense.

These decreases were partially offset by additional interest expense of $26 million in the three months ended September 30, 2009, and $81 million in the nine months ended September 30, 2009, primarily related to $1.8 billion in senior notes that were issued in the fourth quarter of 2008 and March 2009.

The Utility’s interest expense in 2009 and future periods will be impacted by changes in interest rates, changes in the balance of the liability for disputed claims, changes in regulatory balancing accounts, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued. (See “Liquidity and Financial Resources” below.)

Other Income (Expense), Net

The Utility’s other income (expense), net increased by $18 million, or 900%, in the three months ended September 30, 2009 and $28 million, or 117%, in the nine months ended September 30, 2009, compared to the same periods in 2008 when the Utility incurred costs to oppose certain legislation and municipalization efforts. In addition, there was an increase in the Utility’s allowance for funds used during construction primarily due to an increase in spending related to various projects, including the Colusa and Humboldt Bay Generating Stations. This increase was partially offset when the Gateway Generating Station and Diablo Canyon steam generators replacement projects became operative in 2009 and 2008, respectively.

Income Tax Provision

The Utility’s income tax provision decreased by $56 million, or 34%, for the three months ended September 30, 2009, and $47 million, or 11%, for the nine months ended September 30, 2009, as compared to the same periods in 2008. The effective tax rates for the three months ended September 30, 2009 and 2008 were 23.8% and 34.1%, respectively. The effective tax rates for the nine months ended September 30, 2009 and 2008 were 27.6% and 32.6%, respectively. The lower effective tax rates for the three and nine months ended September 30, 2009 were primarily due to an increase in the amount of tax benefits recognized in 2009 as compared to the amount of tax benefits recognized during the three and nine months ended September 30, 2008. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)

PG&E Corporation, Eliminations, and Other

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. PG&E Corporation’s interest expense relates to its 9.50% Convertible Subordinated Notes and 5.75% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three and nine months ended September 30, 2009, as compared to the same periods in 2008.

Other Income (Expense), Net

PG&E Corporation’s other income (expense), net increased by $19 million, or 158%, for the three months ended September 30, 2009, and $39 million, or 139%, for the nine months ended September 30, 2009 primarily due to investment-related gains as a result of improved market performance.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations depends on the levels of its operating cash flow and access to the capital markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal demand for electricity and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. On May 7, 2009, the CPUC increased the Utility’s short-term borrowing authority by $1.5 billion, for an aggregate authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

PG&E Corporation’s ability to fund operations and capital expenditures, make scheduled principal and interest payments, refinance debt, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, and make dividend payments primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital markets.

Credit Facilities

At December 31, 2008, PG&E Corporation had a $200 million revolving credit facility, and the Utility had a $2.0 billion revolving credit facility. Commitments from Lehman Brothers Bank, FSB (“Lehman Bank”) represented $13 million, or 7%, and $60 million, or 3%, of the total borrowing capacity under PG&E Corporation’s and the Utility’s revolving credit facilities, respectively. On April 27, 2009, PG&E Corporation and the Utility amended their revolving credit facilities and removed Lehman Bank as a lender. As a result, PG&E Corporation now has a $187 million revolving credit facility, and the Utility has a $1.94 billion revolving credit facility. The Utility’s revolving credit facility also provides liquidity support for commercial paper issued under the Utility’s $1.75 billion commercial paper program.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding commercial paper and credit facilities at September 30, 2009:

(in millions)			At September 30, 2009
Authorized Borrower	Facility	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	Revolving credit facility	February 2012	$	187	(1)	$	-	$	-	$	-	$	187
Utility	Revolving credit facility	February 2012		1,940	(2)		273		-		-		1,667
Total credit facilities			$	2,127		$	273	$	-	$	-	$	1,854

(1) Includes an $87 million sublimit for letters of credit and $100 million sublimit for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.
(2) Includes a $921 million sublimit for letters of credit and $200 million sublimit for swingline loans.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary covenants for credit facilities of their type, including covenants limiting liens to those permitted under the senior note indenture, mergers, sales of all or substantially all of the Utility’s assets, and other fundamental changes. In addition, both PG&E Corporation and the Utility are required to maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65%, and PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting securities of the Utility. At September 30, 2009, PG&E Corporation and the Utility were in compliance with all covenants.

2009 Financings

In March 2009, PG&E Corporation and the Utility issued $350 million and $550 million, respectively, of senior unsecured notes. Proceeds from the senior notes offerings were used to finance capital expenditures, for general working capital, and to repay outstanding commercial paper that the Utility had issued to pay $600 million of senior unsecured notes that matured on March 1, 2009. On June 11, 2009, the Utility issued $500 million of floating rate senior unsecured notes due June 10, 2010. The net proceeds were used to repay outstanding commercial paper that was issued to satisfy margin calls and collateral requirements related to the Utility’s electric procurement commodity hedging activities. On September 1, 2009, the California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank (“CIEDB”) issued $309 million of tax-exempt pollution control bonds series 2009 A through D for the benefit of the Utility. The Utility used the proceeds it received from the CIEDB to repurchase the corresponding series of 2008 pollution control bonds. The series 2009 bonds, issued at par with an initial rate of 0.20%, are variable rate demand notes with interest resetting daily and backed by direct-pay letters of credit. Unlike the series 2008 bonds, interest earned on the series 2009 bonds is not subject to the alternative minimum tax (“AMT”). A provision in the American Recovery and Reinvestment Act of 2009 allows certain tax-exempt bonds that are subject to AMT to be reissued or refunded in 2009 or 2010 as tax-exempt bonds that are not subject to AMT. As a result, the series 2009 bonds were issued at a lower interest rate, reducing the Utility’s interest expense.

In addition, PG&E Corporation issued 8,569,475 shares of common stock upon exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), generating $211 million of cash through September 30, 2009. Also in 2009, PG&E Corporation contributed $688 million of cash to the Utility to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC.

Future Financing Needs

The amount and timing of the Utility’s future financing needs will depend on various factors, including the conditions in the capital markets, the timing and amount of forecasted capital expenditures, and the amount of cash internally generated through normal business operations, among other factors. The Utility’s future financing needs will also depend on the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund the Utility’s operating expenses and capital expenditures to the extent that internally generated funds are not available. Assuming that PG&E Corporation and the Utility can access the capital markets on reasonable terms, PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures.

Dividends

During the nine months ended September 30, 2009, the Utility paid common stock dividends totaling $468 million to PG&E Corporation.

During the nine months ended September 30, 2009, PG&E Corporation paid common stock dividends totaling $435 million, net of $18 million that was reinvested in additional shares of common stock by participants in the DRSPP. On September 16, 2009, the Board of Directors of PG&E Corporation declared a dividend of $0.42 per share, totaling $156 million, which was paid on October 15, 2009 to shareholders of record on September 30, 2009.

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, 2009 and 2008 were as follows:

	Nine Months Ended
	September 30,
(in millions)	2009			2008
Net income	$	983		$	870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,439			1,388
Allowance for equity funds used during construction		(71	)		(51	)
Deferred income taxes and tax credits, net		274			470
Other changes in noncurrent assets and liabilities		95			55
Effect of changes in operating assets and liabilities:
Accounts receivable		20			(179	)
Inventories		78			(153	)
Accounts payable		(151	)		(85	)
Disputed claims and customer refunds		(700	)		-
Income taxes receivable/payable		534			208
Regulatory balancing accounts, net		226			(94	)
Other current assets		26			(125	)
Other current liabilities		(62	)		(80	)
Other		3			(4	)
Net cash provided by operating activities	$	2,694		$	2,220

In the nine months ended September 30, 2009, net cash provided by operating activities increased by $474 million compared to the same period in 2008, primarily due to the collection of $1.2 billion in rates to recover an under-collection in the Utility’s energy resource recovery balancing account that was incurred in 2008 due to higher than expected energy procurement costs. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.) The increase in operating cash flows also reflects a decline of $224 million in net collateral paid by the Utility related to price risk management activities in 2009. Collateral payables and receivables are included in Other changes in noncurrent assets and liabilities, Other current assets, and Other current liabilities in the table above. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The net collateral paid by the Utility related to price risk management activities fluctuates based on changes in the Utility’s net credit exposure to counterparties, which primarily depends on electricity and gas price movement.

Operating cash flows were also favorably impacted by $297 million due to the timing and amount of tax payments and various tax settlements. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)

Increases in operating cash flows were partially offset by a $700 million payment to the California Power Exchange (“PX”) to reduce the Utility’s liability for the remaining net disputed claims (see Note 10 of the Notes to the Condensed Consolidated Financial Statements), a refund of $230 million received by the Utility in 2008 from the California Energy Commission (“CEC”) with no similar refund in 2009, and the subsequent return of $172 million of the CEC refund to customers through September 30, 2009. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.)

Various factors can affect the Utility’s future operating cash flows, including the timing of cash collateral payments and receipts related to price risk management activity. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure which primarily depends on electricity and gas price movement.

The Utility’s operating cash flows also will be impacted by electricity procurement costs and the timing of rate adjustments authorized to recover these costs. On October 15, 2009, the CPUC authorized the Utility to adjust electric rates to refund $424 million to customers for an over-collection in the Utility’s energy resource recovery balancing account by December 31, 2009. The Utility also will update its forecasted 2010 electricity procurement costs in late November 2009 for inclusion in the annual electric true-up proceeding, which will adjust electric and gas rates on January 1, 2010 to (1) reflect over- and under-collections in the Utility’s major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC and the FERC.

Investing Activities

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals, the occurrence of storms and other events causing outages or damage to the Utility’s infrastructure, and the completion of electricity and natural gas reliability improvements projects. Net cash used in investing activities also include the proceeds of sales of nuclear decommissioning trust assets largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.

The Utility’s cash flows from investing activities for the nine months ended September 30, 2009 and 2008 were as follows:

	Nine Months Ended
	September 30,
(in millions)	2009			2008
Capital expenditures	$	(3,022	)	$	(2,691	)
Decrease (increase) in restricted cash		732			(3	)
Proceeds from nuclear decommissioning trust sales		1,177			1,121
Purchases of nuclear decommissioning trust investments		(1,219	)		(1,161	)
Other		7			21
Net cash used in investing activities	$	(2,325	)	$	(2,713	)

Net cash used in investing activities decreased by $388 million in the nine months ended September 30, 2009 compared to the same period in 2008. This decrease was primarily due to a $700 million decrease in the restricted cash balance that resulted from a payment to the PX to reduce the Utility’s liability for the remaining net disputed claims (see Note 10 of the Notes to the Condensed Consolidated Financial Statements), partially offset by an increase of $331 million in capital expenditures for installing the SmartMeter™ advanced metering infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Future cash flows used in investing activities are largely dependent on the timing and amount of future capital expenditures. (See “Capital Expenditures” below and in the 2008 Annual Report.)

Financing Activities

The Utility’s cash flows from financing activities for the nine months ended September 30, 2009 and 2008 were as follows:

	Nine Months Ended
	September 30,
(in millions)	2009			2008
Net borrowings under revolving credit facility	$	-		$	283
Net (repayment) issuance of commercial paper, net of discount of $3 million in 2009 and $9 million in 2008		(290	)		524
Proceeds from issuance of short-term debt, net of issuance costs of $1 million in 2009		499			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008		847			693
Long-term debt matured or repurchased		(909	)		(454	)
Energy recovery bonds matured		(273	)		(260	)
Preferred stock dividends paid		(10	)		(10	)
Common stock dividends paid		(468	)		(426	)
Equity contribution		688			90
Other		6			(31	)
Net cash provided by financing activities	$	90		$	409

In the nine months ended September 30, 2009, net cash provided by financing activities decreased by $319 million compared to the same period in 2008 mainly due to less net borrowings under the Utility’s revolving credit facility in 2009. No commercial paper was outstanding at September 30, 2009 as the Utility received sufficient positive cash flows from income tax refunds and equity infusions, compared to net borrowings of $283 million in 2008. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

With the exception of dividend payments, interest, common stock issuance, the senior notes issuance of $350 million in March 2009, the receipt of tax refunds of $139 million, and transactions between PG&E Corporation and the Utility, PG&E Corporation had no material cash flows on a stand-alone basis for the nine months ended September 30, 2009 and 2008.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual 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 2008 Annual Report and those arising from normal business activities, PG&E Corporation’s and the Utility’s commitments at September 30, 2009 include $350 million of 5.75% Senior Notes issued by PG&E Corporation due April 1, 2014, $550 million of 6.25% Senior Notes issued by the Utility due March 1, 2039, and $500 million of Floating Rate Senior Notes issued by the Utility due June 10, 2010. (See the 2008 Annual Report and Notes 4, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements.)

CAPITAL EXPENDITURES

Depending on conditions in the capital markets, the Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet already authorized growth. Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC and TO rate cases. The Utility intends to file a GRC application with the CPUC before the end of 2009 to request an increase in authorized revenue requirements to recover capital expenditures forecast to be made in 2011 through 2013. (See “Regulatory Matters” below.) In addition, the Utility requests authorization to collect additional revenue requirements to recover capital expenditures related to specific projects such as new power plants, gas or electric transmission projects, and the SmartMeterTM advanced metering infrastructure.

Proposed Electric Distribution Reliability Program (Cornerstone Improvement Program)

On February 23, 2009, a ruling was issued that establishes a schedule for the CPUC’s consideration of the Utility’s request for approval of a proposed six-year electric distribution reliability improvement program. On March 17, 2009, the Utility filed revised forecasts of proposed capital expenditures totaling $2.0 billion, a decrease from the original forecast of $2.3 billion, and proposed operating and maintenance expenses totaling $59 million, a slight increase from the original forecast of $43 million, over the six-year period of 2010 through 2016. Hearings were completed in August 2009, and a final decision is scheduled to be issued in January 2010.

SmartMeter™ Program

The Utility has been installing an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility’s electric and gas customers. This infrastructure results in substantial cost savings associated with billing customers for energy usage, and enables the Utility to measure usage of electricity on a time-of-use basis and to charge time-differentiated rates. The main goal of time-differentiated rates is to encourage customers to reduce energy consumption during peak demand periods and to reduce procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the majority of the installation throughout its service territory by the end of 2012.

The CPUC has authorized the Utility to recover the $2.2 billion estimated SmartMeter™ project cost, including an estimated capital cost of $1.8 billion. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed $2.2 billion without a reasonableness review by the CPUC. The remaining 10% will not be recoverable in rates. If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review. Through September 30, 2009, the Utility has spent an aggregate of $1.2 billion, including capital costs of $1.0 billion, to install the SmartMeterTM system.

The Utility’s ability to recognize the expected benefits of its SmartMeterTM advanced metering infrastructure remains subject to a number of risks, including whether the Utility incurs additional advanced metering project costs that the CPUC does not find reasonable or that are not recoverable in rates, whether the project is implemented on schedule, whether the Utility can successfully integrate the new advanced metering system with its billing and other computer information systems, and whether the new technology performs as intended.

Diablo Canyon Steam Generator Replacement Project

In November 2005, the CPUC authorized the Utility to replace the steam generators at the two nuclear operating units at Diablo Canyon (Units 1 and 2) and recover costs of up to $706 million from customers without further reasonableness review. The Utility installed four of the new steam generators in Unit 2 during 2008 and completed installation of the remaining new generators for Unit 1 on March 7, 2009. Project costs totaled approximately $690 million.

Proposed New Generation Facilities

Request for Long-Term Generation Resources

On September 30, 2009, the Utility requested that the CPUC approve several agreements executed by the Utility following the completion of its April 1, 2008 request for offers of new long-term generation resources to meet customer demand as forecasted in the Utility’s 2007-2016 long-term electricity procurement plan previously approved by the CPUC. One of the agreements submitted to the CPUC proposes that a 586 megawatt (“MW”) natural gas-fired facility be developed and constructed by a third party and then transferred to the Utility after commercial operation begins. The proposed facility would be operationally flexible, enabling the Utility to increase its use of renewable power by balancing the fluctuating output of wind and solar resources. The facility is expected to be built in Oakley, California and completed in 2014. (The remaining agreements submitted to the CPUC are power purchase agreements.)

Proposed Renewable Energy Development

In its February 24, 2009 application, the Utility has requested that the CPUC approve the Utility’s proposed development and construction of up to 250 MW of Utility-owned generating facilities using solar photovoltaic technology, to be deployed over a period of five years, to help the Utility meet its obligation under California law to increase the amount of electricity provided to customers from renewable generation resources. The CPUC is expected to issue a final decision on the Utility’s application in early 2010.

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies, including Chapter 11 disputed claims, tax matters, and environmental matters, which are discussed in Notes 10 and 11 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 2008 Annual Report and significant new pending regulatory proceedings that were initiated since the 2008 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.

2011 General Rate Case Application

On October 21, 2009, the CPUC’s Division of Ratepayer Advocates (“DRA”) notified the Utility that the DRA had conditionally accepted the Utility’s draft 2011 GRC application that the Utility filed on July 20, 2009. The Utility must wait 60 days before filing the GRC application. Assuming the Utility timely meets the DRA’s conditions, the Utility intends to file the application with the CPUC by the end of 2009. The Utility intends to request that the CPUC issue a final decision by the end of 2010. If the decision is delayed, the Utility will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the revenue requirement changes incorporated in the CPUC’s decision in the case will be effective as of January 1, 2011, even if the decision is issued subsequent to that date.

Unlike the current GRC, which set revenue requirements for a four-year period (2007 through 2010), it is expected that the next GRC will set revenue requirements for the Utility’s electric and natural gas distribution operations and electric generation operations for a three-year period (2011 through 2013). The Utility’s broad goals in this GRC are to fund continued investments in safe and reliable service, meet the economic needs of the communities served by the Utility, and work toward a greener, smarter energy future consistent with state and national goals for long-term environmental sustainability.

The critical driver of the Utility’s request in this GRC will be the need to invest in energy infrastructure to meet customers’ expectations for service quality. Over the three years covered by this rate case (2011-2013), the Utility estimates it will need to spend an average of about $2.7 billion in capital expenditures annually on these infrastructure improvements, especially replacement of gas and electric systems that are reaching the end of their useful lives. The Utility also needs adequate funds to continue to safely operate, maintain, and upgrade generation plants to serve growing demand.

In the 2011 GRC, the CPUC will determine the amount of authorized base revenues that the Utility may collect from its customers to recover its basic business and operational costs for gas and electric distribution and electric generation operations for the period from 2011 through 2013. These revenue requirements are determined based on a forecast of costs for 2011. The draft application indicates that the Utility plans to request a revenue increase for 2011 of $1.1 billion, or 6.5%, above the 2010 total revenue forecast.

The Utility plans to request that the CPUC adopt new flexible cost recovery mechanisms by establishing balancing accounts for several categories of costs that are subject to a high degree of volatility based on economic conditions and other uncontrollable factors, including costs incurred to establish new customer connections, uncollectible accounts, and employee healthcare costs.

The Utility also has indicated that it will seek a ratemaking mechanism for 2012 and 2013 designed to increase the Utility’s authorized revenues in years between GRCs to reflect increases in rate base due to capital investments in infrastructure, and increases in wages and expenses. The proposed mechanism also would require revenue requirements to be adjusted to reflect changes in franchise, payroll, income, or property tax rates, as well as new taxes or fees imposed by governmental agencies. The Utility estimates that this mechanism would result in a revenue requirement increase of $244 million in 2012 and an additional increase of $326 million in 2013. The Utility would advise the CPUC of the actual amount of these proposed increases in October 2011 and October 2012 for years 2012 and 2013, respectively.

PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the period from 2011 through 2013, when a final decision in this proceeding will be received, or how the final decision will impact their financial condition or results of operations.

Electric Transmission Owner Rate Cases

On June 18, 2009, the FERC approved a settlement that sets the Utility’s annual retail transmission base revenue requirement at $776 million, effective March 1, 2009. (For purposes of determining wholesale transmission rates, this retail revenue requirement is adjusted to $763.5 million.) As part of the settlement, the Utility will refund any over-collected amounts to customers, with interest, through an adjustment to rates in 2011.

On July 30, 2009, the Utility filed an application with the FERC requesting an annual retail transmission revenue requirement of $946 million. (For purposes of determining wholesale transmission rates, this retail revenue requirement request has been adjusted to $932 million.) The proposed rates represent an increase of $170 million over current authorized revenue requirements. On September 30, 2009, the FERC accepted the Utility’s application making the proposed rates effective March 1, 2010 subject to refund following the conclusion of hearings and the outcome of judge-supervised settlement discussions.

Energy Efficiency Programs and Incentive Ratemaking

In accordance with the process established by the current incentive ratemaking mechanism, on October 15, 2009, the CPUC approved a second verification report issued by the CPUC's Energy Division relating to the second interim claims for the utilities’ 2006-2008 program performance. The report calculates potential incentive amounts for the Utility, based on different energy savings assumptions and measurement methods, that range up to $20.6 million with up to an additional $33.4 million to be held back pending completion of the 2006-2008 true-up process in 2010. In addition, on September 3 and October 1, 2009, the CPUC’s Energy Division released additional incentive award scenarios, including scenarios based on the proposed settlement, that result in a wide range of potential financial outcomes. It is uncertain what effect, if any, the issuance of the verification report or the scenarios will have on the likelihood of the proposed settlement becoming effective. Whether the proposed settlement will be approved and the amounts of any interim and final claims that may be awarded to the Utility are uncertain at this time.

On July 2, 2009, the utilities re-filed their applications containing their proposed 2009-2011 energy efficiency programs and budgets with the CPUC. On September 24, 2009, the CPUC modified the utilities’ 3-year cycles to cover 2010-2012 energy efficiency programs and authorized funding for these programs. The CPUC authorized the Utility to collect $1.3 billion to fund its programs, a 42% increase over 2006-2008 authorized funding levels. Consequently, the Utility will continue to collect bridge funding of approximately $435 million for the Utility’s 2009 energy efficiency programs, as previously authorized by the CPUC.

Spent Nuclear Fuel

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 dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE failed to develop a permanent storage site by January 31, 1998.

Application to Recover Hydroelectric Facility Divestiture Costs

Retirement Plan Contribution Application

On September 10, 2009, the CPUC approved the all-party settlement among the Utility, the DRA, and the Coalition of California Utility Employees to resolve the Utility’s March 2, 2009 application to allow the Utility to recover amounts necessary for the Utility’s pension plan trust to attain fully funded status. Under the adopted settlement and based on projections to reach fully funded status by 2018, the Utility’s authorized pension-related revenue requirements would be $140.5 million, $177.2 million, and $215.7 million in 2011, 2012, and 2013, respectively. The Utility would request revenue requirements after 2013 in a separate proceeding. In addition, the settlement will allow the Utility to request an increase in revenue requirements if the ratio of trust assets to trust obligations falls below 85%.

The differences between pension benefit costs recognized in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and amounts recognized for ratemaking purposes are recorded as a regulatory asset or liability as amounts are probable of recovery from customers. (See Note 3 of the Notes to the Condensed Consolidated Financial Statements.) Therefore, the settlement is not expected to impact net income in future periods.

Cost of Capital Proceeding

On October 15, 2009, the CPUC approved a decision that maintains the Utility’s authorized cost of capital, including a ROE of 11.35%, through 2010. The decision approves a joint request made by the Utility and the DRA to avoid imposing a rate increase corresponding to an increase in the Utility’s ROE during a time of economic hardship. The Utility believes that this increase may otherwise have been triggered as of January 1, 2010 by the cost of capital adjustment mechanism previously adopted by the CPUC on May 29, 2008. The Utility’s capital structure, including a 52% equity component, will be maintained through 2012.

In addition, as requested by the Utility and the DRA, the CPUC extended the cost of capital adjustment mechanism through 2012. The cost of capital adjustment mechanism will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Services utility bond index increases or decreases by more than 1% as compared to the applicable benchmark. Finally, the CPUC agreed to defer the due date for the Utility’s next full cost of capital application from April 20, 2010 until April 20, 2012, so that any resulting changes would become effective on January 1, 2013.

2011 Gas Transmission and Storage Rate Case

On September 18, 2009, the Utility filed an application with the CPUC to initiate the Utility’s 2011 Gas Transmission and Storage rate case so that the CPUC can determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011. The rates, and terms and conditions of the Utility’s gas transmission and storage services for 2008 through 2010 were set by the terms of a CPUC-approved all-party settlement agreement known as the Gas Accord IV that was approved by the CPUC in September 2007. The Utility proposes to continue a majority of the Gas Accord IV’s terms and conditions of natural gas transportation and storage services.

The Utility has requested that the CPUC approve a 2011 natural gas transmission and storage revenue requirement of $529.1 million, an increase of $67.3 million over the 2010 adopted revenue requirement. The Utility also seeks attrition increases for 2012, 2013, and 2014 of $32.4 million, $30.7 million, and $22.6 million, respectively.

Under the Utility’s proposal, a substantial portion of the authorized revenue requirements, primarily those costs allocated to residential and small commercial customers (called “core” customers) would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility has proposed to simplify the current rate structure by, among other changes, setting rates for core and “non-core” customers based on forecast demand. The Utility’s ability to recover its remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. To reduce the Utility’s financial risk associated with these factors, the Utility has proposed to share equally with customers any under-collection or over-collection of natural gas transmission and storage revenue requirements. The Utility has proposed additional cost recovery mechanisms for costs that are difficult to forecast, such as the cost of electricity used to operate natural gas compressor stations and costs to comply with greenhouse gas regulations.

The Utility has requested that the CPUC issue a final decision by the end of 2010. If the CPUC does not issue a final decision by the end of 2010 to approve new rates effective January 1, 2011, the September 2007 CPUC decision approving the Gas Accord IV provides that the rates and terms and conditions of service in effect as of December 31, 2010, will remain in effect, with an automatic 2% escalation in the rates as of January 1, 2011.

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 categorize market risks as price risk and interest rate risk. The Utility is also exposed to credit risk, which is the risk that counterparties fail to perform their contractual obligations. For a comprehensive discussion of PG&E Corporation’s market risk, see the section entitled “Risk Management Activities” in the 2008 Annual Report.

Price Risk

Electricity Procurement

On April 1, 2009, the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) became operative. Among other features, the MRTU established new day-ahead, hour-ahead, and real-time wholesale electricity markets subject to bid caps that increase over time. The Utility expects to continue to rely on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities to meet customer demand. A relatively small proportion of the Utility’s total customer demand must be met through purchases in the MRTU markets. As a result, exposure to price volatility in the new MRTU markets is minimal. The CAISO must implement additional FERC-ordered changes over the next several years. Market risks, if any, associated with these changes will be assessed as the design and timelines are finalized during the 2009-2010 period.

Natural Gas Transportation and Storage

The Utility uses value-at-risk to measure shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services. 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 95% confidence level, which means that there is a 5% 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 $17 million at September 30, 2009. The Utility’s high, low, and average values-at-risk at September 30, 2009 were $34 million, $9 million, and $17 million, respectively.

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, 2009, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would have an immaterial impact to net income over the next twelve months.

Credit Risk

The Utility manages credit risk associated with its wholesale customers and counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, 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. The Utility executes many energy contracts 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, 2009 and December 31, 2008:

(in millions)	Gross Credit Exposure Before Credit Collateral(1)		Credit Collateral		Net Credit Exposure(2)		Number of Wholesale Customers or Counterparties >10%		Net Exposure to Wholesale Customers or Counterparties >10%
September 30, 2009	$	227	$	45	$	182		3	$	148
December 31, 2008	$	240	$	84	$	156		2	$	107

(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.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with GAAP 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, in part, to their complexity and because their application is relevant and 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 2008 Annual Report. They include:

·	regulatory assets and liabilities;

·	environmental remediation liabilities;

·	asset retirement obligations;

·	accounting for income taxes; and

·	pension and other postretirement plans.

For the period ended September 30, 2009, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and no material changes to the important assumptions underlying the critical accounting estimates.

NEW ACCOUNTING POLICIES

Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133

Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51

Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement

Equity Method Investment Accounting

Subsequent Events

Interim Disclosures about Fair Value of Financial Instruments

Recognition and Presentation of Other-Than-Temporary Impairments

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Employers’ Disclosures about Postretirement Benefit Plan Assets

Accounting for Transfers of Financial Assets - an amendment of FASB Statement No. 140

Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends the Consolidation Topic of the FASB ASC regarding when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”). In addition, SFAS No. 167 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach. Furthermore, SFAS No. 167 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. SFAS No. 167 is effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2010. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 167.

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 activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see “Risk Management Activities” 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, 2009, 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 that the companies file or submit under the Securities Exchange Act of 1934 (“1934 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 1934 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 control over financial reporting that occurred during the quarter ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

The complaint filed by the California Attorney General against PG&E Corporation and several of its present and former directors was dismissed on March 10, 2009 and the similar complaint filed by the City and County of San Francisco was dismissed on April 23, 2009. For more information regarding the resolution of these matters, see “Part I. Item 3. Legal Proceedings” in the 2008 Annual Report and “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, 2009.

ITEM 1A. RISK FACTORS

A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” in the 2008 Annual Report.

The discussion of the potential impact of climate change appearing in the 2008 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors” under the following caption “The Utility’s future operations may be impacted by climate change that may have a material impact on the Utility’s financial condition and results of operations” is updated as follows to reflect new scientific evidence regarding climate change:

A report issued on June 16, 2009 by the U.S. Global Change Research Program (an interagency effort led by the National Oceanic and Atmospheric Administration) states that climate changes caused by rising emissions of carbon dioxide and other heat-trapping gases have already been observed in the United States, including increased frequency and severity of hot weather, reduced runoff from snow pack, and increased sea levels. The impact of events or conditions caused by climate change could range widely, from highly localized to worldwide, and the extent to which the Utility’s operations may be affected is uncertain. For example, if reduced snowpack decreases the Utility’s hydroelectric generation capacity, there will be a need for additional generation capacity from other sources. Under certain conditions, the events or conditions caused by climate change could result in a full or partial disruption of the ability of the Utility, or one or more entities on which it relies, to generate, transmit, transport or distribute electricity or natural gas. The Utility has been studying the potential effects of climate change on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most likely to occur. Events or conditions caused by climate change could have a greater impact on the Utility’s operations than has been forecast and could result in lower revenues or increased expenses, or both. If the CPUC were to fail to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially adversely affected.

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

On July 31, 2009, PG&E Corporation contributed equity of $35 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.

During the quarter ended September 30, 2009, PG&E Corporation issued 331,404 shares of common stock at a conversion price of $15.09 per share in an unregistered offering upon conversion of $5 million 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, 2009, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the third quarter of 2009, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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 nine months ended September 30, 2009 was 3.19. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2009 was 3.13. 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 333-149361 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 2009 was 2.99. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.

ITEM 6. EXHIBITS


3.1	Bylaws of PG&E Corporation amended as of September 16, 2009

3.2	Bylaws of Pacific Gas and Electric Company amended as of September 16, 2009

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

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

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

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

BARBARA L. BARCON

Barbara L. Barcon

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated: October 29, 2009

EXHIBIT INDEX


3.1	Bylaws of PG&E Corporation amended as of September 16, 2009

3.2	Bylaws of Pacific Gas and Electric Company amended as of September 16, 2009

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

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

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.