
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)~~15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2008 OR

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

Commission File Number _______________		Exact Name of Registrant as specified in its charter _______________			State or other Jurisdiction of Incorporation ______________			IRS Employer Identification Number ___________

1-12609		PG&E Corporation			California			94-3234914
1-2348		Pacific Gas and Electric Company			California			94-0742640

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177					PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105
Address of principal executive offices, including zip code

Pacific Gas and Electric Company (415) 973-7000					PG&E Corporation (415) 267-7000
Registrant's telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. [X] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 ~~August 1,~~October 31, 2008:

PG&E Corporation					~~358,556,042 shares (excluding 24,665,500 shares held by a wholly owned subsidiary)~~360,983,933
Pacific Gas and Electric Company					~~283,856,022~~264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~JUNE~~SEPTEMBER 30, 2008

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		7
		Condensed Consolidated Balance Sheets		8
		Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	11
	NOTE 2:		New and Significant Accounting Policies	1112
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	14
	NOTE 4:		Debt	17
	NOTE 5:		Shareholders' Equity	1819
	NOTE 6:		Earnings Per Common Share	1920
	NOTE 7:		Derivatives and Hedging Activities	2021
	NOTE 8:		Fair Value Measurements	2122
	NOTE 9:		Related Party Agreements and Transactions	2527
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	2628
	NOTE 11:		Commitments and Contingencies	2629

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			3336
	Forward-Looking Statements			3538
	Results of Operations			3739
	Liquidity and Financial Resources			4346
	Contractual Commitments			47
	~~Capital Expenditures~~			48
	~~Off-Balance Sheet Arrangements~~			50
	~~Contingencies~~			51
	~~Regulatory Matters~~Capital Expenditures			51
	~~Risk Management Activities~~Off-Balance Sheet Arrangements			53
	~~Critical Accounting Policies~~Contingencies			5554
	~~New Accounting Policies~~Regulatory Matters			54
	Risk Management Activities			56
	Critical Accounting Policies			58
	New Accounting Policies			58
	Accounting Pronouncements Issued But Not Yet Adopted			57
	~~Environmental Matters~~			57
	~~Tax Matters~~			59
	~~Legal Matters~~			5960

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			6061
ITEM 4.	CONTROLS AND PROCEDURES			6061

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			6062
ITEM 1A.	RISK FACTORS			6062
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			6162
~~ITEM 4~~.	~~SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~			61
ITEM 5.	OTHER INFORMATION			6362
ITEM 6.	EXHIBITS			64
~~SIGNATURES~~				6563

PART I. FINANCIAL INFORMATION

ITEM 1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION	PG&E CORPORATION													PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	CONDENSED CONSOLIDATED STATEMENTS OF INCOME													CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		(Unaudited)													(Unaudited)
		Three Months Ended						Six Months Ended							Three Months Ended						Nine Months Ended
		June 30,						June 30,							September 30,						September 30,
(in millions, except per share amounts)		2008			2007			2008			2007				2008			2007			2008			2007
Operating Revenues
Electric		$	2,645		$	2,359		$	5,159		$	4,534			$	2,880		$	2,574		$	8,039		$	7,107
Natural gas			933			828			2,152			2,009				794			705			2,946			2,714
Total operating revenues			3,578			3,187			7,311			6,543				3,674			3,279			10,985			9,821
Operating Expenses
Cost of electricity			1,097			884			2,124			1,607				1,282			998			3,406			2,606
Cost of natural gas			487			396			1,262			1,150				351			281			1,613			1,431
Operating and maintenance			991			922			2,027			1,842				983			953			3,010			2,794
Depreciation, amortization, and decommissioning			419			430			821			860				419			465			1,240			1,325
Total operating expenses			2,994			2,632			6,234			5,459				3,035			2,697			9,269			8,156
Operating Income			584			555			1,077			1,084				639			582			1,716			1,665
Interest income			33			37			59			89				23			36			82			125
Interest expense			(185	)		(185	)		(372	)		(375	)			(178	)		(196	)		(550	)		(571	)
Other income, net			1			10			3			14
Other income (expense), net																(17	)		7			(14	)		22
Income Before Income Taxes			433			417			767			812				467			429			1,234			1,241
Income tax provision			140			148			250			287				163			151			413			438
Net Income		$	293		$	269		$	517		$	525			$	304		$	278		$	821		$	803
Weighted Average Common Shares Outstanding, Basic			356			350			355			350				357			352			356			350
Weighted Average Common Shares Outstanding, Diluted			357			352			356			352				358			353			357			352
Net Earnings Per Common Share, Basic		$	0.80		$	0.75		$	1.42		$	1.46			$	0.83		$	0.77		$	2.25		$	2.23
Net Earnings Per Common Share, Diluted		$	0.80		$	0.74		$	1.42		$	1.45			$	0.83		$	0.77		$	2.24		$	2.22
Dividends Declared Per Common Share		$	0.39		$	0.36		$	0.78		$	0.72			$	0.39		$	0.36		$	1.17		$	1.08

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.													See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
		(Unaudited)							(Unaudited)
		Balance At							Balance At
(in millions)		June 30, 2008			December 31, 2007				September 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	297		$	345			$	251		$	345
Restricted cash			1,322			1,297				1,325			1,297
Accounts receivable:
Customers (net of allowance for doubtful accounts of $59 million in 2008 and $58 million in 2007)			2,417			2,349
Customers (net of allowance for doubtful accounts of $75 million in 2008 and $58 million in 2007)										2,530			2,349
Regulatory balancing accounts			1,357			771				1,117			771
Inventories:
Gas stored underground and fuel oil			251			205				333			205
Materials and supplies			177			166				172			166
Income taxes receivable			52			61				-			61
Prepaid expenses and other			469			255				580			255
Total current assets			6,342			5,449				6,308			5,449
Property, Plant, and Equipment
Electric			26,693			25,599				27,146			25,599
Gas			9,860			9,620				10,016			9,620
Construction work in progress			1,432			1,348				1,668			1,348
Other			17			17				16			17
Total property, plant, and equipment			38,002			36,584				38,846			36,584
Accumulated depreciation			(13,297	)		(12,928	)			(13,422	)		(12,928	)
Net property, plant, and equipment			24,705			23,656				25,424			23,656
Other Noncurrent Assets
Regulatory assets			4,300			4,459				4,233			4,459
Nuclear decommissioning funds			1,914			1,979				1,819			1,979
Other			1,351			1,089				1,094			1,089
Total other noncurrent assets			7,565			7,527				7,146			7,527
TOTAL ASSETS		$	38,612		$	36,632			$	38,878		$	36,632

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.							See accompanying Notes to the Condensed Consolidated Financial Statements.

Long-term debt repurchased

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities, ~~and~~ the disclosure of ~~contingencies.~~contingencies, and include, but are not limited to, estimates and assumptions used in determining the Utility's regulatory asset and liability balances based on probability assessments of regulatory recovery, revenues earned but not yet billed, the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”) and customer refunds, asset retirement obligations (“ARO”), allowance for doubtful accounts receivable, provisions for losses that are deemed probable from environmental remediation liabilities, pension and other employee benefit plan assets and liabilities, liabilities for future severance costs, accounting for derivatives under Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), fair value measurements under SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”), income tax-related assets and liabilities, and accruals for legal matters. In addition, the Utility uses estimates and assumptions when it reviews long-lived assets and certain identifiable intangibles that are held and used in operations for impairment. (A review is triggered whenever events or changes in circumstances indicate that the carrying amount of these assets might not be recoverable.) A change in management's estimates or assumptions could have a material impact on PG&E Corporation and the Utility's financial condition and results of operations during the period in which such change occurred. As these estimates and assumptions involve judgments on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict, actual results may differ materially from these estimates. PG&E Corporation and the Utility's Condensed Consolidated Financial Statements reflect all adjustments management believes are necessary for the fair presentation of their financial condition and results of operations for the periods presented. Interim period results of operations are not necessarily indicative of the results of operations for the full year.

Fair Value Measurements

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of ~~Statement of Financial Accounting Standards (“SFAS”)~~SFAS No. 157, ~~“Fair Value Measurements” (“SFAS No. 157”),~~ which defines fair value, establishes criteria when measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date,” or the “exit price.” Accordingly, an entity must now determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. Additionally, SFAS No. 157 establishes a fair value hierarchy, which gives precedence to fair value measurements, calculated using observable inputs to those using unobservable inputs. SFAS No. 157 requires entities to disclose fair-valued financial

~~fair-valued~~ instruments according to the hierarchy in each reporting period after implementation. The provisions of SFAS No. 157 have been deferred to fiscal years beginning after November 15, 2008 for nonrecurring, nonfinancial instruments shown at fair value.

See Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion and ~~the~~financial statement impact toof the ~~financial statements of~~ implementation of SFAS No. ~~157 and fair value measurements.~~157.

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value with changes in fair value recognized in earnings. PG&E Corporation and the Utility ~~did~~have not ~~elect~~elected the fair value option for any assets or liabilities as of ~~June~~and during the three and nine months ended September 30, 2008; therefore, the adoption of SFAS No. 159 did not impact the Condensed Consolidated Financial Statements.

Amendment of Financial Accounting Standards Board Interpretation No. 39

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board (“FASB”) Staff Position on Interpretation 39, “Amendment of FASB Interpretation No. 39” (“FIN 39-1”). Under FIN 39-1, a reporting entity is ~~permitted~~required to offset the cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting ~~arrangement.~~arrangement when reporting those amounts on a net basis. The provisions of FIN 39-1 are applied retrospectively. See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion and financial statement impact of the implementation of FIN 39-1.

Share-Based Compensation

PG&E Corporation and the Utility account for share-based compensation awards in accordance with the provisions of SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”), using the modified prospective application method, which requires that compensation cost be recognized for all share-based payment awards, including unvested stock options, based on the grant date fair value. SFAS No. 123R requires that an estimate of future forfeitures be made and that compensation cost be recognized only for share-based payment awards that are expected to vest.

PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2.5%, based on historic forfeiture rates, for purposes of determining compensation expense for share-based incentive awards. The following table provides a summary of total compensation expense ~~(reduction to compensation expense)~~ for PG&E Corporation (consolidated) and the Utility (stand-alone) for share-based incentive awards for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007:

Three Months Ended

September 30,

Three Months Ended

September 30,

	PG&E Corporation				Utility
	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2008		2007		2008		2007
Stock options	$	2	$	6	$	1	$	3
Restricted stock		19		19		13		12
Performance shares		8		15		5		9
Total compensation expense (pre-tax)	$	29	$	40	$	19	$	24
Total compensation expense (after-tax)	$	17	$	24	$	11	$	14

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 ~~of their~~ plans.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 are as follows:

	Pension Benefits						Other Benefits							Pension Benefits						Other Benefits
	Three Months Ended June 30,						Three Months Ended June 30,							Three Months Ended September 30,						Three Months Ended September 30,
(in millions)	2008			2007			2008			2007				2008			2007			2008			2007
Service cost for benefits earned	$	59		$	59		$	7		$	7			$	59		$	55		$	7		$	7
Interest cost		144			135			20			20				148			139			21			20
Expected return on plan assets		(175	)		(177	)		(24	)		(24	)			(173	)		(178	)		(22	)		(23	)
Amortization of transition obligation (1)		-			-			7			6				-			-			6			7
Amortization of prior service cost (1)		12			12			4			4				12			12			4			3
Amortization of unrecognized gain (1)		-			-			(4	)		(3	)
Amortization of unrecognized gain/(loss) (1)															1			1			(3	)		(1	)
Net periodic benefit cost	$	40		$	29		$	10		$	10			$	47		$	29		$	13		$	13


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

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost for benefits earned	$	177		$	173		$	22		$	22
Interest cost		436			408			61			59
Expected return on plan assets		(522	)		(533	)		(70	)		(72	)
Amortization of transition obligation (1)		-			-			19			19
Amortization of prior service cost (1)		35			37			12			12
Amortization of unrecognized gain/(loss) (1)		1			2			(11	)		(7	)
Net periodic benefit cost	$	127		$	87		$	33		$	33


(1) In 2007, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71.

Pension Benefits
Six Months Ended
June 30,

Other Benefits
Six Months Ended
June 30,

(in millions)
2008

2007

2008

2007

Service cost for benefits earned $ 118 $ 118 $ 15 $ 14
Interest cost 287 270 40 40
Expected return on plan assets (349 ) (354 ) (47 ) (48 )
Amortization of transition obligation (1)
- - 12 12
Amortization of prior service cost (1)
24 24 8 8
Amortization of unrecognized gain (1)
- - (8 ) (6 )
Net periodic benefit cost $ 80 $ 58 $ 20 $ 20

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

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

Accounting Pronouncements Issued But Not Yet Adopted

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

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging ~~Activities, an~~Activities-an amendment of ~~SFAS~~FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. ~~133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).~~133. An entity is required to provide qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures on fair value

amounts of and gains and losses on derivative instruments, and disclosures relating to credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective prospectively for fiscal years beginning after November 15, 2008. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 161.

Long-term regulatory assets are comprised of the following:

The energy recovery bond (“ERB”) regulatory asset represents the refinancing of the settlement regulatory asset established under the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s ~~proceeding under~~ Chapter 11 ~~of the U.S. Bankruptcy Code (the “Chapter~~proceeding (“Chapter 11 Settlement Agreement”). ~~During the six months ended June 30, 2008, the Utility recorded amortization of the ERB regulatory asset of approximately $165 million.~~ The Utility expects to fully recover this asset by the end of 2012.

Unamortized loss, net of gain, on reacquired debt represents costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over periods ranging from 1 to 18 years.

Regulatory assets associated with the Utility’s ~~Chapter 11 Settlement Agreement~~plan of reorganization include costs incurred in financing the Utility’s plan of reorganization under Chapter 11 ~~of the U.S. Bankruptcy Code (“Chapter 11”)~~ and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization. The Utility expects to recover these costs over periods ranging from 5 to 30 years.

Contract termination costs represent amounts that the Utility incurred in terminating a 30-year power purchase agreement. This regulatory asset will be amortized and collected in rates on a straight-line basis through the end of September 2014, the power purchase agreement’s original termination date.

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

~~Finally, “Other”~~“Other” is primarily related to price risk management regulatory ~~assets, with contract terms in excess of one year,~~assets. The Utility enters into contracts to procure electricity and natural gas that are designed to reduce commodity price risks. ~~These~~Some of these price risk management contracts are accounted for as derivative instruments under SFAS No. ~~133.~~133 (see Note 7 of the Notes to the Condensed Consolidated Financial Statements). Changes in the fair value of derivative instruments are recognized as price risk management assets or liabilities. The unrealized gain or loss associated with changes in the fair value of these derivative instruments is deferred and recorded in regulatory accounts ~~because they are~~to be recovered or refunded through regulated rates. ~~Additionally, “Other” includes~~Price risk management regulatory assets ~~that~~ represent ~~timing differences between~~ the ~~recognition~~deferral of ~~asset retirement obligation (“ARO”)~~unrealized losses related to price risk management derivative instruments with terms in ~~accordance with GAAP and the amounts recognized for ratemaking purposes.~~excess of one year.

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

Current Regulatory Assets

At ~~June~~September 30, 2008 and December 31, 2007, the Utility had current regulatory assets of approximately ~~$93~~$317 million and $131 million, respectively, consisting primarily of price risk management regulatory assets and the current portion of long-term 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. Price risk management regulatory assets relate to contracts, with terms less than one year, to procure electricity and natural gas that are designed to reduce commodity price risks. These contracts are accounted for as derivative instruments under SFAS No. 133. Changes in the fair value of derivative instruments are deferred and recorded in regulatory accounts because they will be recovered or refunded through regulated rates in the future. Current regulatory assets are included in Prepaid ~~Expenses~~expenses and ~~Other~~other in the Condensed Consolidated Balance Sheets.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance At				Balance At
(in millions)	June 30, 2008		December 31, 2007		September 30, 2008		December 31, 2007
Cost of removal obligation	$	2,650	$	2,568	$	2,694	$	2,568
Price risk management		803		124
Employee benefit plans		621		578		626		578
Asset retirement costs		455		573		335		573
Public purpose programs		285		264		318		264
California Solar Initiative		200		159		206		159
Price risk management						105		124
Other		171		182		172		182
Total regulatory liabilities	$	5,185	$	4,448	$	4,456	$	4,448

Cost of removal liabilities represent revenues collected for asset removal costs that the Utility expects to incur in the future.

~~Price risk management regulatory liabilities relate to contracts, with terms in excess of one year, to procure~~

electricity and natural gas that are designed to reduce commodity price risks. These contracts are accounted for as derivative instruments under SFAS No. 133. Changes in the fair value of derivative instruments are deferred and recorded in regulatory accounts because they are recovered or refunded through regulated rates.

Employee benefit plan expenses represent the cumulative differences between amounts recognized in accordance with GAAP and amounts recognized for ratemaking purposes, which also includes amounts that otherwise would be fully recorded to ~~accumulated~~Accumulated other comprehensive income in the Condensed Consolidated Balance Sheets in accordance with SFAS No. 158. (See Note 2 of the Notes to the Condensed Consolidated Financial Statements and the 2007 Annual Report for further discussion.) These balances will be charged against expense to the extent that future expenses exceed amounts recoverable for regulatory purposes.

Asset retirement costs represent timing differences between the recognition of ARO in accordance with GAAP and the amounts recognized for ratemaking purposes.

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

California Solar Initiative liabilities represent revenues ~~designated~~collected from customers to pay for costs the Utility expects to incur in the future to promote the use of solar energy in residential homes and commercial, industrial, and agricultural ~~properties that are expected to be incurred in the future.~~properties.

~~Finally, “Other”~~Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year.

“Other” is primarily related to amounts received from insurance companies to pay for hazardous substance remediation costs. The insurance recoveries are refunded to customers as a reduction to rates until customers are fully reimbursed for the ~~amount of the costs~~cost of hazardous substance remediation that has been collected in rates. Additionally, “Other” includes regulatory liabilities that represent future customer benefits associated with the Gateway Generating Station (“Gateway”). Gateway was acquired as part of a settlement with Mirant Corporation and the associated liability will be amortized over 30 years beginning in January 2009 when Gateway is anticipated to be placed in service.

Current Regulatory Liabilities

As of ~~June~~September 30, 2008, the Utility had current regulatory liabilities of approximately ~~$1,016~~$310 million, consisting primarily of price risk management regulatory liabilities representing the deferral of unrealized gains related to price risk management derivative instruments with terms of less than one year. As of December 31, 2007, the Utility had current regulatory liabilities of approximately $280 million, primarily consisting of 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 revenue regulatory balancing accounts to accumulate differences between revenues and the Utility's authorized revenue requirements and cost regulatory balancing accounts to accumulate differences between incurred costs and costs recovered, or collected (primarily commodity cost). Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.

The Utility's current regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility's customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in Other Noncurrent Assets – Regulatory ~~Assets~~assets and Noncurrent Liabilities – Regulatory ~~Liabilities.~~liabilities in the Condensed Consolidated Balance Sheet. The CPUC does not allow the Utility to offset regulatory balancing account assets against regulatory balancing account liabilities.

Current Regulatory Balancing Account Assets

Current Regulatory Balancing Account Liabilities

During the nine months ended September 30, 2008, the under-collection in the Utility's electricity revenue and cost balancing accounts increased from December 31, 2007. This change is primarily due to higher than forecasted procurement costs. During the nine months ended September 30, 2008, the over-collection in the Utility’s natural gas revenue and cost balancing accounts increased from December 31, 2007 mainly due to seasonal demand changes.

Convertible Subordinated Notes

At ~~June~~September 30, 2008, PG&E Corporation had outstanding approximately $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. Interest is payable semi-annually in arrears on June 30 and December 31. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,059 shares of PG&E Corporation common stock, at a conversion price of $15.09 per share. The conversion price is subject to adjustment for significant changes in the number of outstanding shares of PG&E Corporation’s common stock. In addition, holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion price. Since January 1, 2008, PG&E Corporation has paid “pass-through dividends” totaling approximately ~~$21~~$28 million, including $7 million paid on ~~July~~October 15, 2008.

In accordance with SFAS No. 133, the dividend participation rights of the Convertible Subordinated Notes are considered to be 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. Dividend participation rights are recognized as operating cash flows in PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. Changes in the fair value are recognized (in Other ~~Income, Net)~~income (expense), net) in PG&E Corporation's Condensed Consolidated Statements of Income as a non-operating expense or income. At ~~June~~September 30, 2008, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately ~~$55~~$49 million, of which ~~$27~~$28 million was classified in Current Liabilities - Other and ~~$28~~$21 million was classified in Noncurrent Liabilities - Other in the accompanying Condensed Consolidated Balance Sheets. At December 31, 2007, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $62 million, of which $25 million was classified ~~as a current liability~~ in Current Liabilities - Other and $37 million was classified ~~as a noncurrent liability~~ in Noncurrent Liabilities - Other in the accompanying Condensed Consolidated Balance Sheets. The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157, resulting in a $6 million increase in fair value. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion of the implementation of SFAS No. 157.)

On March 3, 2008, the Utility issued $200 million principal amount of 5.625% Senior Notes due on November 30, 2017, increasing the total outstanding amount of 5.625% Senior Notes to $700 million. The Utility received proceeds of approximately $202 million from the offering, including a $3 million premium and net of $1 million in issuance costs. In addition, the Utility received approximately $3 million relating to accrued interest (the interest that has accumulated since the original issuance). Also on March 3, 2008, the Utility issued $400 million principal amount of 6.35% Senior Notes due on February 15, 2038. The Utility received proceeds of approximately $396 million from the offering, net of a $1 million discount and $3 million in issuance costs. The proceeds from the sale of the March 3, 2008 Senior Notes offerings were used to repay outstanding commercial paper, for working capital purposes, and to fund capital expenditures.

At ~~June~~September 30, 2008, there were $6.9 billion of senior notes outstanding.

On October 21, 2008, the Utility issued $600 million principal amount of 8.25% 10-year Senior Notes ~~outstanding.~~due on October 15, 2018.

Pollution Control Bonds

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

In 2005, the Utility purchased financial guaranty insurance policies to insure the regularly scheduled payments on $454 million of pollution control bonds series 2005 A-G (“PC2005 bonds”) issued by the ~~California Infrastructure and Economic Development Bank.~~CIEDB. Interest rates on these bonds were set at auction every 7 or 35 days. In January 2008, the insurer’s credit rating was downgraded and/or put on review for possible downgrade by several credit agencies. This, in addition to credit issues ~~which~~that impacted the auction rate securities markets, resulted in increases in interest rates for the PC2005 bonds. To eliminate this interest rate risk, the Utility repurchased $300 million of the PC2005 bonds in March 2008 and the remaining $154 million in April 2008. ~~The repurchased~~

On September 22, 2008, the CIEDB issued $50 million principal amount of pollution control bonds ~~are held in treasury pending resale~~series F due on November 1, 2026 and $45 million principal amount of pollution control bonds series G due on December 1, 2018 for the benefit of the Utility. These series of bonds ~~which depends~~refunded the corresponding related series of PC2005 bonds. Each series of bonds will bear interest at 3.75% per year through September 19, 2010 and is subject to mandatory tender on ~~conditions~~September 20, 2010 at a price of 100% of the principal amount plus accrued interest. Thereafter, these series of bonds may be remarketed in ~~the tax-exempt bond market~~a fixed or variable rate mode. Interest is payable semi-annually in arrears on March 1 and ~~liquidity needs at the Utility.~~September 1.

At ~~June~~September 30, 2008, there were ~~$1.2~~$1.3 billion of pollution control bonds outstanding.

~~Working Capital Facility~~On October 29, 2008, the CIEDB issued four series of tax-exempt pollution control bonds in the principal amount of $309 million for the benefit of the Utility. These series of bonds refunded the corresponding related series of PC2005 bonds. The bonds bear interest at variable interest rates not to exceed 12% per year. The initial interest rate on the bonds is 1.75%. The interest rate payable on the bonds will initially be reset weekly. Bonds in the principal amount of $160 million will mature in 2016 and bonds in the principal amount of $149 million will mature in 2026.

Each series of bonds issued in October is supported by a direct-pay letter of credit issued by Wells Fargo Bank National Association that expires on October 29, 2011, unless extended. All payments on the bonds are made through draws on the letters of credit. The Utility has entered into a reimbursement agreement with respect to each letter of credit under which the Utility is obligated to reimburse amounts drawn under such letter of credit. If the Utility does not reimburse the issuing lender for a draw on a letter of credit to pay the purchase price of tendered bonds, the Utility is deemed to have requested a loan, which loan is generally payable upon the earlier of the successful remarketing of the tendered bonds or the expiration of the letter of credit. The Utility anticipates that the refinancing of the remaining $50 million of PC2005 bonds will occur by the end of 2008, subject to conditions in the tax-exempt bond market and the liquidity needs of the Utility.

Credit Facilities and Short-Term Borrowings

At ~~June~~September 30, 2008, there were approximately ~~$281~~$273 million of letters of credit and no$533 million of borrowings outstanding at a yield of 3.38% under the Utility’s $2.0 billion working capital facility.

~~Commercial Paper Program~~

In addition, the working capital facility provides liquidity support for commercial paper offerings. At ~~June~~September 30, 2008, the Utility had ~~$156~~$802 million of commercial paper outstanding at an average yield of approximately ~~2.94%~~5.75%.

Energy Recovery Bonds

In furtherance of the Chapter 11 Settlement Agreement, PG&E Energy Recovery Funding LLC (“PERF”), 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 ~~$1.8~~$1.7 billion at ~~June~~September 30, 2008.

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: SHAREHOLDERS' EQUITY

PG&E ~~Corporation's~~Corporation and the Utility's changes in shareholders' equity for the ~~six~~nine months ended ~~June~~September 30, 2008 were as follows:

	PG&E Corporation			Utility			PG&E Corporation			Utility
(in millions)	Total Common Shareholders' Equity			Total Shareholders' Equity			Total Common Shareholders' Equity			Total Shareholders' Equity
Balance at December 31, 2007	$	8,553		$	9,125		$	8,553		$	9,125
Net income		517			549			821			870
Common stock issued		82			-			150			-
Share-based compensation amortization		15			-			21			-
Common stock dividends declared and paid		(139	)		(284	)		(279	)		(426	)
Common stock dividends declared but not yet paid		(140	)		-			(140	)		-
Preferred stock dividends		-			(7	)		-			(10	)
Tax benefit from share-based payment awards		4			3			5			4
Other comprehensive income		5			5			8			8
Equity infusion		-			50
Balance at June 30, 2008	$	8,897		$	9,441
Equity contribution								-			90
Balance at September 30, 2008							$	9,139		$	9,661

~~On February 25,~~At December 31, 2007, Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, held 24,665,500 shares of PG&E Corporation common stock. Effective August 29, 2008, Elm Power Corporation was dissolved, and the shares subsequently cancelled.

At December 31, 2007, PG&E Holdings, LLC, a wholly owned subsidiary of the Utility, held approximately 7% of the Utility common stock. Effective August 29, 2008, PG&E Holdings, LLC, was dissolved, and the shares subsequently cancelled.

For the nine month period ended September 30, 2008, PG&E Corporation contributed equity of ~~$50~~$90 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.

~~On February 22, 2008, PG&E Corporation declared its quarterly dividend at $0.39 per share, an increase of $0.03 per share over the previous level of $0.36 per share.~~ During the ~~six~~nine months ended ~~June~~September 30, 2008, PG&E Corporation paid common stock dividends totaling ~~$284~~$433 million, including ~~$18~~$28 million to ~~its wholly owned subsidiary,~~ Elm Power Corporation. On ~~June 18,~~September 17, 2008, the Board of Directors of PG&E Corporation declared a dividend of $0.39 per share, totaling ~~$149~~$140 million, ~~including $10 million to its wholly owned subsidiary, Elm Power Corporation that~~which was paid on ~~July~~October 15, 2008 to shareholders of record on ~~June~~September 30, 2008.

During the ~~six~~nine months ended ~~June~~September 30, 2008, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling $7$10 million. On ~~June 18,~~September 17, 2008, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock payable on ~~August~~November 15, 2008 to shareholders of record on ~~July~~October 31, 2008.

NOTE 6: EARNINGS PER COMMON SHARE

Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, by dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the “two-class” method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation's Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of a participating security. All PG&E Corporation's participating securities participate on a 1:1 basis with shares of common stock.

PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS in accordance with SFAS No. 128, “Earnings Per Share” (“SFAS No. 128”). Under SFAS No. 128 the proceeds from the exercise of options and warrants are assumed to be used to purchase shares of common stock at the average market price during the reported period. The incremental shares (the difference between the number of shares assumed issued upon exercise and the number of shares assumed purchased) must be included in the number of weighted average shares of common stock used for the calculation of diluted EPS.

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

	Three Months Ended				Six Months Ended					Three Months Ended				Nine Months Ended
	June 30,				June 30,					September 30,				September 30,
(in millions, except per share amounts)	2008		2007		2008		2007			2008		2007		2008		2007
Net income	$	293	$	269	$	517	$	525		$	304	$	278	$	821	$	803
Less: distributed earnings to common shareholders		139		127		278		253			140		127		419		379
Undistributed earnings	$	154	$	142	$	239	$	272		$	164	$	151	$	402	$	424
Common shareholders earnings
Basic
Distributed earnings to common shareholders	$	139	$	127	$	278	$	253		$	140	$	127	$	419	$	379
Undistributed earnings allocated to common shareholders		146		135		227		258			156		143		382		402
Total common shareholders earnings, basic	$	285	$	262	$	505	$	511		$	296	$	270	$	801	$	781
Diluted
Distributed earnings to common shareholders	$	139	$	127	$	278	$	253		$	140	$	127	$	419	$	379
Undistributed earnings allocated to common shareholders		146		135		227		258			156		143		382		402
Total common shareholders earnings, diluted	$	285	$	262	$	505	$	511		$	296	$	270	$	801	$	781
Weighted average common shares outstanding, basic		356		350		355		350			357		352		356		350
9.50% Convertible Subordinated Notes		19		19		19		19			19		19		19		19
Weighted average common shares outstanding and participating securities, basic		375		369		374		369			376		371		375		369
Weighted average common shares outstanding, basic		356		350		355		350			357		352		356		350
Employee share-based compensation		1		2		1		2			1		1		1		2
Weighted average common shares outstanding, diluted		357		352		356		352			358		353		357		352
9.50% Convertible Subordinated Notes		19		19		19		19			19		19		19		19
Weighted average common shares outstanding and participating securities, diluted											377		372		376		371
Net earnings per common share, basic
Distributed earnings, basic (1)										$	0.39	$	0.36	$	1.18	$	1.08
Undistributed earnings, basic											0.44		0.41		1.07		1.15
Total										$	0.83	$	0.77	$	2.25	$	2.23
Net earnings per common share, diluted
Distributed earnings, diluted										$	0.39	$	0.36	$	1.17	$	1.08
Undistributed earnings, diluted											0.44		0.41		1.07		1.14
Total										$	0.83	$	0.77	$	2.24	$	2.22


(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.									(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.

Distributed earnings, basic (1)

The Utility enters into contracts to procure electricity, natural gas, nuclear fuel, and firm electricity transmission rights. Some of these contracts meet the definition of derivative instruments under SFAS No. 133. All such derivative instruments, including instruments designated as cash flow hedges, are recorded at fair value and presented as price risk management assets and liabilities on the balance sheet (see table below). As a result of applying the provisions of SFAS No. 71, unrealized changes in the fair value of derivative instruments are deferred and recorded into regulatory ~~accounts.~~assets or liabilities. Under the same regulatory accounting treatment, changes in the fair value of cash flow hedges are also recorded into regulatory ~~accounts,~~assets or liabilities, rather than being deferred in accumulated other comprehensive income.

In PG&E ~~Corporation’s~~Corporation and the Utility's Condensed Consolidated Balance Sheets, price risk management assets and liabilities associated with the Utility’s electricity and gas procurement activities are presented on a net basis by counterparty aswhere the right of offset exists. As PG&E Corporation and the Utility adopted the provisions of FIN 39-1 on January 1, 2008, the net balances include outstanding cash collateral associated with derivative positions. (See Note 2 of the Notes to the Condensed Consolidated Financial Statements for discussion of the adoption of FIN 39-1.) The table below ~~represents~~shows the total price risk management derivative balances and the portions that are designated as cash flow hedges:

Total Price Risk Management Derivatives

Price Risk Management Derivatives Designated as Cash Flow Hedges

(in millions)
June 30, 2008(1)

December 31, 2007(2)

June 30, 2008(3)

December 31, 2007(4)

Current Assets – Prepaid expenses and other $ 307 $ 55 $ 139 $ (2 )(5)
Other Noncurrent Assets – Other 418 171 162 42
Current Liabilities – Other 28 67 9 12
Noncurrent Liabilities – Other 37 20 - 3

~~(1)~~ Balances reflect a $445 million reduction to Current Assets-Prepaid expenses and other, a $385 million reduction to Other Noncurrent Assets–Other, and a $1 million increase to Current Liabilities–Other as a result of netting cash collateral in accordance with FIN 39-1.

~~(2)~~ Balances reflect a $3 million increase to Current Assets-Prepaid expenses and other, a $46 million increase to Other Noncurrent Assets–Other, and a $16 million reduction to Current Liabilities–Other as a result of netting cash collateral in accordance with FIN 39-1. This collateral was classified as Current Assets–Prepaid expenses in the 2007 Annual Report.

~~(3)~~ Balances reflect a $77 million reduction to Current Assets-Prepaid expenses and other and a $51 million reduction to Other Noncurrent Assets-Other as a result of netting cash collateral in accordance with FIN 39-1.

~~(4)~~ Balances reflect a $9 million increase to Other Noncurrent Assets-Other and a $7 million reduction to Current Liabilities-Other as a result of netting cash collateral in accordance with FIN 39-1. This collateral was classified as Current Assets–Prepaid expenses in the 2007 Annual Report.

~~(5)~~ ~~$2 million of the cash flow hedges in a liability position at December 31, 2007 relate to counterparties for which the total net derivatives position is a current asset.~~

	Total Price Risk Management Derivatives				Price Risk Management Derivatives Designated as Cash Flow Hedges
(in millions)	September 30, 2008(1)		December 31, 2007(2)		September 30, 2008(3)		December 31, 2007(4)
Current Assets – Prepaid expenses and other	$	120	$	55	$	8	$	(2	)(5)
Other Noncurrent Assets – Other		177		171		18		42
Current Liabilities – Other		88		67		36		12
Noncurrent Liabilities – Other		117		20		107		3


(1) Balances reflect the allocation of a $220 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $74 million, $72 million to Other Noncurrent Assets-Other, and $74 million to Current Liabilities-Other in accordance with FIN 39-1.
(2) Balances reflect the allocation of a $65 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $3 million, $46 million to Other Noncurrent Assets-Other, and $16 million to Current Liabilities-Other in accordance with FIN 39-1. This collateral was classified as Current Assets-Prepaid expenses and other in the 2007 Annual Report.
(3) Balances reflect the allocation of a $25 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $8 million, $7 million to Other Noncurrent Assets-Other, and $10 to Current Liabilities-Other in accordance with FIN 39-1.
(4) Balances reflect the allocation of a $16 million cash collateral receivable balance to Other Noncurrent Assets-Other for $9 million and $7 million to Current Liabilities-Other in accordance with FIN 39-1. This collateral was classified as Current Assets-Prepaid expenses and other in the 2007 Annual Report.
(5) $2 million of the cash flow hedges in a liability position at December 31, 2007 relate to counterparties for which the total net derivatives position is a current asset.

As of ~~June~~September 30, 2008, PG&E Corporation and the Utility had cash flow hedges with expiration dates through December 2012 for energy contract derivative instruments.

The Utility also has derivative instruments for the physical delivery of commodities transacted in the normal course of business. These derivative instruments are eligible for the normal purchase and sales exceptions under SFAS No. 133, and are not reflected in the Condensed Consolidated Balance Sheets. ~~They are recorded and recognized in income using accrual accounting. Therefore, these expenses are recognized in cost of electricity and cost of natural gas as incurred.~~

Net realized gains or losses on derivative instruments, including those derivative instruments for which the normal purchase and sales exception has been elected, are ~~included~~recorded in ~~various items of PG&E Corporation’s and~~ the ~~Utility’s Condensed Consolidated Statements of Income, primarily to~~ cost of electricity and the cost of natural gas. Cash inflows and outflows associated with the settlement of price risk management ~~activities~~transactions are recognized in operating cash flows on PG&E ~~Corporation’s~~Corporation and the Utility’s Condensed Consolidated Statements of Cash Flows.

The dividend participation rights ~~component~~ of PG&E Corporation’s Convertible Subordinated Notes, considered to be a derivative ~~instrument, is~~instruments, are recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 133. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for discussion of the Convertible Subordinated Notes.)

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157, which defines fair value measurements and implements a hierarchical disclosure requirement. SFAS No. 157 deferred the disclosure of the hierarchy for certain non-financial instruments to fiscal years beginning after November 15, 2008.

SFAS No. 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date,” or the “exit price.” Accordingly, an entity must now determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. The identification of market participant assumptions provides a basis for determining what inputs are to be used for pricing each asset or liability. Additionally, SFAS No. 157 establishes a fair value hierarchy ~~which~~that gives precedence to fair value measurements calculated using observable inputs toover those using unobservable inputs. Accordingly, the following levels were established for each input:

Level 1: “Inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.” Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments classified as Level 1 consist of financial instruments such as ~~exchange traded~~exchange-traded derivatives (other than options), listed equities, and U.S. government treasury securities.

Level 2: “Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly.” Instruments classified as Level 2 consist of financial instruments such as ~~non exchange-traded~~non-exchange-traded derivatives (other than options) valued using exchange inputs and exchange traded derivatives (other than options) for which the market is not active.

Level 3: “Unobservable inputs for the asset or liability.” These are inputs for which there is no market data available, or observable inputs that are adjusted using Level 3 assumptions. Instruments classified as Level 3 consist

primarily of financial and physical instruments such as options, ~~non exchange-traded~~non-exchange-traded derivatives valued using broker quotes, and new and/or complex instruments that have immature or limited markets.

SFAS No. 157 is applied prospectively with limited exceptions. One such exception relates to SFAS No. 157’s nullification of a portion of Emerging Issues Task Force (“EITF”) No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF 02-3”). Prior to the issuance of SFAS No. 157, EITF 02-3 prohibited ~~the use of unobservable inputs that would result in~~an entity from recognizing a day one gain or loss on derivative ~~contracts. As SFAS No. 157 requires that a~~contracts based on the use of unobservable inputs. A day one gain or loss is the difference between the transaction price and the fair value ~~measurement reflect~~of the ~~assumptions market participants would use in pricing an instrument,~~contract on the ~~valuation of~~day the derivative contracts may incorporate unobservable inputs that were previously prohibited by EITF 02-3. Therefore, retrospective adjustments to apply SFAS No. 157 need to be made for existing derivative contracts that are affected by this provision in EITF 02-3.contract is executed (i.e., at inception). Prior to the adoption of SFAS No. 157, the Utility ~~followed the provisions of EITF 02-3 by recording~~did not record any day one gains associated with Congestion Revenue Rights (“CRRs”) ~~at their transaction prices~~ as ~~observable data~~the fair value was ~~not available to support any day one gains. CRRs~~based primarily on unobservable market data. (CRRs allow market participants, including ~~Load Serving Entities,~~load serving entities, to hedge the financial risk of congestion charges imposed by the California Independent System Operator (“CAISO”) ~~imposed congestion charges~~ in the day-ahead market to be established when the CAISO’s Market Redesign and Technology Upgrade ~~day-ahead market.~~(“MRTU”) becomes effective.) The costs associated with ~~procurement of~~procuring CRRs are currently being recovered in rates or are probable of recovery in future rates. The adoption of SFAS No. 157 permitted the Utility to record day one gains associated with CRRs resulting in a $48 million ~~adjustment to~~increase in price risk management assets and the ~~fair value of the CRRs was recorded to~~related regulatory liabilities as of January 1, 2008.

The following table sets forth the fair value hierarchy by level of PG&E Corporation and the Utility’s recurring fair value financial instruments as of ~~June~~September 30, 2008. The instruments are classified based on the lowest level of input that is significant to the fair value measurement. PG&E Corporation 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.

Fair Value Measurements as of June 30, 2008

Nuclear Decommissioning Funds(1)

Price Risk Management Instruments(2)

(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3.

Fair Value Measurements as of June 30, 2008

Nuclear Decommissioning Funds(1)

Price Risk Management Instruments(2)

Fair Value Measurements as of September 30, 2008

(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $41 million to Level 1, $26 million to Level 2, and $153 million to Level 3.

Utility
Fair Value Measurements as of September 30, 2008
(in millions)	Level 1	Level 2	Level 3	Total
Assets:
Nuclear decommissioning trusts(1)	$ 1,609	$ 308	$ 7	$ 1,924
Price risk management instruments(2)	54	4	34	92
Long-term disability trust	49	-	79	128
Assets Total	$ 1,712	$ 312	$ 120	$ 2,144
Liabilities:
Other	$ -	$ -	$ 5	$ 5
Liabilities Total	$ -	$ -	$ 5	$ 5


(1) Excludes taxes on appreciation of investment value.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $41 million to Level 1, $26 million to Level 2, and $153 million to Level 3.

PG&E Corporation and the Utility’s fair value measurements incorporate various factors required under SFAS No. 157 such as the credit standing of the counterparties involved, nonperformance risk including the risk of nonperformance by PG&E Corporation and the ~~Utility’s nonperformance risk~~Utility on ~~its~~their liabilities, the applicable exit market, and specific risks inherent in the instrument. Nonperformance and credit risk adjustments on the Utility’s price risk management instruments are based on current market inputs when available, such as credit default swap spreads. When such information is not available, internal models may be used. As of September 30, 2008, the nonperformance and credit risk adjustment represents approximately 1% of the net price risk management value. As permitted under SFAS No. 157, PG&E Corporation and the Utility utilize a mid-market pricing convention (the mid-point between bid and ask prices) as a practical expedient in valuing the majority of its derivative assets and liabilities at fair value.

Money Market Investments

PG&E Corporation invests in AAA-rated money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued based on observable inputs such as expected yield and credit quality and are thus classified as Level 1 instruments. Approximately $192 million held in money market funds are recorded as Cash and cash equivalents in PG&E Corporation’s Condensed Consolidated Balance Sheets.

As of September 30, 2008, PG&E Corporation classified approximately $62 million invested in one money market fund as a Level 3 instrument because the fund manager imposed restrictions on fund participants’ redemption requests. PG&E Corporation’s investment in this money market fund, previously recorded as Cash and cash equivalents, is recorded as Prepaid expenses and other in PG&E Corporation’s Condensed Consolidated Balance Sheets. (In October 2008, PG&E Corporation received an initial redemption amount of approximately $32 million from the money market fund.)

The nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust hold primarily equities, debt securities, mutual funds, and life insurance policies. These instruments are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. The rabbi trusts are classified as Current Assets-Prepaid expenses and other and Other Noncurrent Assets-Other in PG&E Corporation’s Condensed Consolidated Financial Statements. The long-term disability trust is classified as Current Liabilities-Other in PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements.

Price Risk Management Instruments

Price risk management instruments are comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. PG&E Corporation and the Utility use similar models to value similar instruments. SFAS No. 71 allows the Utility to defer the unrealized gains and losses associated with these derivatives, as they are expected to be refunded or recovered in future rates.

All energy options (exchange-traded and OTC) are valued using the Black’s Option Pricing Model and classified as Level 3 measurements primarily due to volatility inputs.

CRRs, firm transmission rights (“FTRs”), and demand response (“DR”) contracts are new and/or complex instruments that have immature or limited markets. CRRs are discussed above. FTRs allow market participants, including load serving entities to hedge both the physical and financial risk associated with CAISO-imposed congestion charges until the MRTU becomes effective. DRs primarily allow market participants, including load serving entities, to manage their capacity requirements. In addition, DR contracts are used to hedge financial risk associated with increased energy prices resulting from increased demand on the electricity grid. Activity in these markets is minimal and observable inputs may not be available in pricing these instruments. Therefore, the pricing models used to value these instruments often incorporate significant estimates and assumptions that market participants would use in pricing the instrument. Accordingly, they are classified as Level 3 measurements.

Exchange-traded derivative instruments (other than options) are generally valued based on unadjusted prices in active markets using pricing models to determine the net present value of estimated future cash flows. Accordingly, a majority of these instruments are classified as Level 1 measurements. However, certain of these exchange-traded contracts are classified as Level 2 measurements because the contract term extends to a point at which the market is no longer considered active but where prices are still observable. This determination is based on an analysis of the relevant characteristics of the market such as trading hours, trading volumes, frequency of available quotes, and open interest. In addition, a number of OTC contracts have been valued using unadjusted exchange prices in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments. The remaining OTC derivative instruments are valued using pricing models based on the net present value of estimated future cash flows based on broker quotations. Such instruments are generally classified within Level 3 of the fair value hierarchy as broker quotes are only indicative of market activity and do not necessarily reflect binding offers to transact.

See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of the price risk management instruments.

Dividend Participation Rights

The dividend participation rights of the Convertible Subordinated Notes are embedded derivative instruments in accordance with SFAS No. 133 and, therefore, are bifurcated from Convertible Subordinated Notes and recorded at fair value in PG&E Corporation's Condensed Consolidated Balance Sheets. The dividend participation rights are valued based on the net present value of estimated future cash flows using internal estimates of common stock dividends. These rights are recorded as Current Liabilities-Other and Noncurrent Liabilities-Other in PG&E Corporation’s Condensed Consolidated Balance Sheets. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion of these instruments.)

The following table is a reconciliation of changes in fair value of instruments that have been classified as Level 3 in the fair value hierarchy for the ~~six-month~~nine month period ended ~~June~~September 30, 2008:

Price Risk Management Instruments

Long-term Disability

Dividend Participation Rights

Money Market Investments

Price Risk Management Instruments

Nuclear Decommissioning Trusts (3)

Long-term Disability

Dividend Participation Rights

Price Risk Management Instruments

Nuclear Decommissioning

Long-term Disability

Price Risk Management Instruments

Nuclear Decommissioning

Trusts (2)

Long-term Disability

The following table is a reconciliation of changes in fair value of instruments that have been classified as Level 3 in the fair value hierarchy for the ~~three-month~~three month period ended ~~June~~September 30, 2008:

Price Risk Management Instruments

Nuclear Decommissioning

Long-term Disability

Dividend Participation Rights

Money Market Investments

Price Risk Management Instruments

Nuclear Decommissioning Trusts (1)

Long-term Disability

Dividend Participation Rights

Price Risk Management Instruments

Nuclear Decommissioning

Long-term Disability

Price Risk Management Instruments

Nuclear Decommissioning Trusts (1)

Long-term Disability

PG&E Corporation and the Utility dodid not have any nonrecurring financial measurements that are within the scope of SFAS No. 157 as of ~~June~~September 30, 2008.

Receivable (Payable)

Balance Outstanding at

Administrative services provided to

Interest from PG&E Corporation

on employee benefit assets

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, ~~(“Disputed Claims”),~~ 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.

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~~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,~~disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be credited to customers.

As of ~~June~~September 30, 2008, the Utility’s liability for the remaining net ~~Disputed Claims~~disputed claims was approximately $1.7 billion, consisting of approximately $1.6 billion of remaining ~~Disputed Claims~~disputed claims (classified on the Condensed Consolidated Balance ~~Sheet~~Sheets as ~~accounts payable)~~Accounts payable – Disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $0.6 billion (classified on the Condensed Consolidated Balance ~~Sheet~~Sheets as ~~interest~~Interest payable) offset by an accounts receivable from the CAISO and the PX of approximately $0.5 billion (included within ~~accounts~~Accounts receivable – Customers on the Condensed Consolidated Balance ~~Sheet)~~Sheets). These amounts do not include potential remaining ~~refund amounts~~refunds that may be due to the Utility as a result of the FERC refund proceedings.

As of ~~June~~September 30, 2008, the Utility held $1.2 billion in escrow, including approximately $0.1 billion of earned interest, for payment of the remaining net ~~Disputed Claims~~disputed claims (classified as Restricted ~~Cash~~cash in the Condensed Consolidated Balance ~~Sheet)~~Sheets).

Interest accrues on the liability for ~~Disputed Claims~~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,~~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.~~disputed claims.

The Utility and the PX have been negotiating the terms of a proposed agreement regarding the potential transfer of $700 million to the PX from the Utility’s escrow account established for disputed claims to enable the PX to fund future settlements, pay refund claims, or amounts owed to CAISO or PX markets, as may be authorized by the FERC or a court of competent jurisdiction. The proposed agreement would be subject to approval by the FERC and by the bankruptcy courts that have jurisdiction of the Chapter 11 proceedings of the PX and the Utility. Under the proposed agreement, the Utility’s payment would reduce its liability for remaining net disputed claims. To protect the Utility against the imposition of double liability, the proposed agreement would provide that, to the extent that both the PX and an individual electricity supplier have filed claims relating to the same transaction, such claim would be paid by the Utility only once, either to the PX or directly to the electricity supplier, as may be ordered by the FERC or a court of competent jurisdiction. It is uncertain when a final agreement will be executed and, if executed, when required approvals would be obtained.

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

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, employee matters, environmental compliance and remediation, tax matters, and legal matters.

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase ~~electricity~~electric energy and capacity and makes payments under existing power purchase agreements. The price of purchased power may be fixed or variable. Variable pricing is generally based on either the current market price of gas or electricity at the date of purchase. Forward prices as of September 30, 2008 are used to determine the undiscounted future expected payments for contracts with variable pricing terms. At ~~June~~September 30, 2008, the undiscounted future expected power purchase agreement payments ~~based on June 30, 2008 forward prices~~ were as follows:

Payments made by the Utility under power purchase agreements amounted to approximately ~~$2,284~~$3,631 million and ~~$1,504~~$2,367 million for the ~~six~~nine months ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007, respectively. The amounts above do not include payments related to the California Department of Water Resources (“DWR”) purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

The following table shows the future fixed capacity payments due under qualifying facility (“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)
2008 $ 29
2009 50
2010 50
2011 50
2012 50
Thereafter 253
Total fixed capacity payments 482
Less: Amount representing interest (120 )
Present value of fixed capacity payments $ 362

(in millions)
202008	$	11
202009		50
202010		50
202011		50
202012		50
Thereafter		254
T Total fixed capacity payments	$	465
Less: Amount representing interest		(115	)
Present value of fixed capacity payments	$	350

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

Capacity payments, which allow QFs to recover investment costs, are based on the QF’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the QF 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~~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 of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.

At ~~June~~September 30, 2008, the ~~Utility's~~Utility’s undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2008 $ 1,074
2009 915

Payments for natural gas purchases and gas transportation services amounted to approximately ~~$1,589~~$2,227 million and ~~$1,230~~$1,603 million for the ~~six~~nine months ended ~~June~~September 30, 2008 and ~~June~~September 30, 2007, respectively.

PG&E Corporation retains a guarantee related to certain indemnity obligations of its former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company. PG&E Corporation's sole remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. At ~~June~~September 30, 2008, PG&E Corporation’s potential exposure under this guarantee was immaterial and PG&E Corporation has not made any provision for this guarantee.

Application to Recover Hydroelectric Facility Divestiture Costs

On April 14, 2008, the Utility filed an application with the CPUC requesting authorization to recover approximately $47 million, including $12.2 million of interest, of the costs it incurred in connection with the Utility’s efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken at the direction of the CPUC in preparation for the planned divestiture of the facilities to further the development of a competitive generation market in California. In 2003, the CPUC determined that the amount of these costs at the time, $34.8 million, was reasonable and authorized the Utility to track these costs and seek authorization to recover these costs in the future if the hydroelectric generation facilities were ultimately not divested. The Utility continues to own its hydroelectric generation assets. On May 19, 2008, the CPUC’s Division of Ratepayer Advocates ~~(“DRA”~~("DRA") filed a protest to the ~~Utility’s~~Utility's application. On ~~June 11,~~August 14, 2008, the ~~CPUC administrative law judge overseeing~~DRA and the ~~proceeding granted~~Utility agreed that the ~~DRA's~~Utility had supported its request ~~to conduct an audit of the Utility’s related accounting records. The audit must be completed by August 6, 2008. The procedural schedule will be set after the audit is reviewed.~~with appropriate and reasonable evidence. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve recovery of these costs.

California Department of Water Resources Contracts

Electricity purchased under the DWR allocated power purchase contracts with various generators provided approximately 15.2% of the electricity delivered to the Utility's customers for the ~~six~~nine months ended ~~June~~September 30, 2008. The DWR remains legally and financially responsible for its ~~electricity procurement~~power purchase contracts. The Utility acts as a billing and collection agent of the DWR's revenue requirements from the Utility's customers.

The DWR has stated publicly in the past that it intends to transfer full legal title of, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. ~~The~~In addition, the Chapter 11 Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

·	After assumption, the Utility's issuer rating by Moody’s Investors Service (“Moody's”) will be no less than A2 and the Utility's long-term issuer credit rating by Standard and Poor’s Rating Service (“S&P”) will be no less than A. The Utility’s current issuer rating by Moody’s is A3 and the Utility’s long-term issuer credit rating by S&P is BBB+;

·	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

·	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The CPUC has ~~been holding various workshops with interested parties~~opened a proceeding to investigate ~~whether~~how the DWR can ~~terminate~~end its role in purchasing power for the customers of the California investor-owned utilities. Until the DWR’s obligations under ~~the~~its power purchase contracts are terminated, the CPUC is prohibited by ~~assignment~~state law from reinstating “direct access”. Direct access is the ability of retail end-user customers to purchase electricity from energy providers other than the California investor-owned electric utilities. The CPUC has opened a proceeding to investigate how the DWR can end its role in purchasing power for the customers of the California investor-owned utilities, through novation of the DWR contracts or otherwise. A proposed decision was issued on October 7, 2008, that, if adopted by the CPUC, would set January 1, 2010 as the target date for completing negotiations to determine whether the DWR contracts can be novated and transferred to the Utility and other investor-owned utilities ending the DWR’s power procurement role. The CPUC is expected to issue a final decision by the end of 2008.

Incentive Ratemaking for Energy Efficiency Programs

The CPUC has 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. The maximum amount of incentives that the Utility may receive and the amount of any reimbursement obligations the Utility may incur over the 2006-2008 program cycle is $180 million. The financial impact will depend on the amount of any shareholder incentives the Utility may receive or the amount of any reimbursement obligations the Utility may incur based on the level of energy efficiency savings actually achieved over the three-year program cycle and when the applicable accounting standard for recognizing incentives or reimbursement obligations is met.

The Utility has several types of nuclear insurance for the two nuclear operating units at its Diablo Canyon nuclear generating facilities (“Diablo Canyon”) and for its retired nuclear generation facility at Humboldt Bay (“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 ~~$38.5~~$39.3 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 ~~$10.8~~$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 ~~$10.8~~$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 megawatts (“MW”) or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to ~~$100.6~~$117.5 million per reactor, with payments in each year limited to a maximum of ~~$15~~$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 ~~$201.2~~$235 million per incident, with payments in each year limited to a maximum of ~~$30~~$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 ~~August 20, 2008.~~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 Nuclear Regulatory Commission for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

In connection with the Utility’s initiatives to streamline processes and achieve cost and operating efficiencies, the Utility is eliminating and consolidating various employee positions. As a result, the Utility has incurred severance costs and expects that it will incur additional severance costs. The amount of future severance costs will depend on many variables, including whether affected employees elect to receive severance benefits or reassignment, the number of available vacant

positions for those seeking reassignment, and for those employees who elect severance benefits, their years of service and annual salaries. At ~~June~~September 30, 2008, the Utility estimated future severance costs will range from ~~$32~~$29 million to ~~$52~~$48 million, given the uncertainty of each of these variables. The Utility has recorded a liability of ~~$32~~$29 million as of ~~June~~September 30, 2008. The following table presents the changes in the liability from December 31, 2007:

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~~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 approximately ~~$538~~$575 million at ~~June~~September 30, 2008, and approximately $528 million at December 31, 2007. The ~~$538~~$575 million accrued at ~~June~~September 30, 2008 consists of:

·	Approximately ~~$221~~$222 million for remediation at the Hinkley and Topock natural gas compressor sites;

·	Approximately $83 million related to remediation at divested generation facilities;

·	Approximately ~~$182~~$221 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

·	Approximately ~~$52~~$49 million related to remediation costs for fossil decommissioning sites.

Of the approximately ~~$538~~$575 million environmental remediation liability, approximately $126 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately ~~$328~~$359 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.

The Utility's undiscounted future costs could increase to as much as ~~$895~~$940 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The amount of approximately ~~$895~~$940 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

The Utility's Diablo Canyon power plant 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. In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued a proposed policy to address once through cooling. The Water Board’s current proposal would require the installation of cooling towers at nuclear facilities by January 1, 2021, unless the installation of cooling towers would conflict with a nuclear safety requirement.

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. In April 2008, the U.S. Supreme Court agreed to review the Second Circuit decision regarding the cost-benefit test and a decision is expected by mid-2009. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, 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.

California Labor Code Issues

~~Approximately 12,929 of the Utility’s~~Hourly paid employees ~~are covered by collective bargaining agreements. Employees~~ in California are entitled to an unpaid, uninterrupted 30-minute duty-free meal period for every four hours of work. Pursuant to California Labor Code Section 226.7, ~~prohibits~~ employers ~~from requiring employees to work during any mandated meal. Employers~~ who fail to provide the mandated meal period must provide ~~the~~an employee with one additional hour of pay at the employee's regular rate of compensation for each work day that the meal period is not provided. If the employee worked during the 30-minute unpaid meal period, the employer also must ~~also~~ pay the employee for this time.

In April 2007, the California Supreme Court ruled that the payment required under this ~~California~~ law ~~requiring employers to pay an employee an additional hour of pay for each work day that a required meal period is not provided~~ is a “wage” rather than a penalty, and that claims brought for violation of this law are subject to a three-year statute of limitations rather than the one-year statute of limitations applicable to claims for penalty payments. ~~Prior to this decision, the Utility believed that its~~

The collective bargaining agreement ~~with~~between the Utility and the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”), which ~~did~~covers approximately 10,300 employees, does not provide certain employee groups a continuous 30-minute meal ~~period, preempted state law.~~

period. In June 2007, the Utility and the IBEW ~~reached an agreement under which~~agreed that covered employees whose eight-hour shifts do not allow for an uninterrupted 30-minute meal break ~~will~~would be paid one hour of pay for each 30-minute meal period missed going back 39 months. InFurther, in July 2007, the Utility and IBEW established a joint committee ~~composed of the IBEW and Utility representatives~~ to review payroll records to determine if payments were due to other IBEW- represented employees who missed a meal due to business needs. That review is continuing. Effective September 2007, the ~~Utility’s current collective bargaining agreements~~Utility instituted use of a new payroll time sheet to ensure ~~compliance with California labor law in light of~~all missed meals are accurately recorded by employees and paid for by the ~~California Supreme Court’s ruling. The Utility is continuing to investigate whether other employees may be entitled to payment for a missed or delayed meal.~~ Utility.

In connection with ~~these matters,~~those employees whose eight-hour shifts do not allow for an uninterrupted 30-minute meal period, the Utility has paid ~~approximately~~ $24 million as of ~~June~~September 30, 2008. ~~At June~~Additionally, at September 30, 2008, the Utility ~~has~~ accrued ~~an additional $5.1~~$5.7 million for probable future ~~payments.~~payments related to missed meals. The Utility is unable to estimate the additional amount of loss it may incur in connection with this matter. The ultimate outcome of ~~these matters~~this matter may have a material adverse impact on PG&E ~~Corporation’s~~Corporation and the Utility’s financial condition or results of operations.

Tax Matters

In the first quarter of 2008, PG&E Corporation reached a settlement with the Internal Revenue Service (“IRS”) appellate division for tax years 1997-2000. On July 9, 2008, PG&E Corporation was notified that the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) had approved the settlement. As a result of the settlement, PG&E Corporation received a $16 million refund from the IRS in October 2008. This settlement did not result in material changes to the amount of unrecognized tax benefits that PG&E Corporation recorded under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”

On June 20, 2008, PG&E Corporation reached an agreement with the IRS regarding a change in accounting method related to the capitalization of indirect service costs for tax years 2001-2004. This agreement resulted in a $29 million benefit from a reduction in interest expense accrued on unrecognized tax benefits partially offset by a $15 million liability associated with unrecognized state tax benefits, for a net tax benefit of approximately $14 million. OnIn addition, on June 27, 2008, PG&E Corporation agreed to athe revenue agent ~~report~~reports (“~~RAR”~~RARs”) from the IRS that reflected this agreement and resolved all significant 2001-2002 audit issues, except ~~a dispute relating~~for issues related to ~~PG&E Corporation’s entitlement to $104 million of~~ synthetic fuel tax credits, ~~which was referred to the IRS appellate division,~~ and all 2003-2004 audit issues. ~~The IRS will forward the RAR to the IRS appellate division, and it will be finalized when~~On August 26, 2008, PG&E Corporation ~~and~~signed a separate closing agreement that favorably resolved the ~~IRS appellate division resolve~~issues related to the ~~issue regarding~~ synthetic fuel tax credits. ~~At that time, the RAR will be~~The RARs and closing agreement were submitted to the Joint Committee for approval.

On October 28, 2008, the IRS executed the RARs and the closing agreement after the Joint Committee indicated it had taken no exception to the resolution of the 2001-2004 audits. As a result of the ~~anticipated~~ resolution of ~~the~~ 2001-2004 audits, ~~as described above, it is reasonably possible that~~PG&E Corporation expects to receive a refund of approximately $310 million and recognize after-tax income in the fourth quarter of 2008 of approximately $230 million. Approximately $180 million of the refund will be allocated to the Utility and approximately $60 million of the after-tax income will be attributable to the Utility. The after-tax income of $230 million includes approximately $175 million primarily related to a reduction in PG&E Corporation’s liability associated with unrecognized tax benefits ~~could decrease in~~and approximately $55 million associated with the utilization of federal capital loss carry forwards, as discussed below. (All these amounts exclude interest.) There are no other anticipated changes to the unrecognized tax benefits within the next 12 ~~months by an amount ranging from $0 to $200 million for PG&E Corporation, of which $0 to $100 million is related to the Utility.~~months.

~~The IRS is currently auditing tax years 2005-2006. PG&E Corporation filed its federal return for tax year 2007 in July 2008. Beginning in tax year~~As of September 30, 2008, PG&E Corporation ~~began participating in the IRS’ Compliance Assurance Process, a real-time audit process intended to expedite the resolution of issues raised during audits.~~

~~Currently, PG&E Corporation has~~had $268 million of federal capital loss carry forwards based on tax returns as filed, primarily resulting from the disposition of NEGT stock in 2004. The ~~majority~~resolution of the 2001-2004 audits will 1) reduce the capital loss carry forwards by approximately $51 million due to losses allowed in the audit settlements, and 2) utilize approximately $156 million of the federal capital loss carry forwards resulting in after-tax income of approximately $55 million, excluding interest, in the fourth quarter of 2008. PG&E Corporation’s remaining federal capital loss carry forwards will be approximately $61 million, of which $20 million will expire if not used by December ~~2009, will expire.~~ 2009.

The ~~settlement of the 2001-2004 audits may result in utilization of a significant portion of the federal capital loss carry forwards. However, because the settlement~~IRS is ~~subject to the Joint Committee’s approval,~~currently auditing tax years 2005-2007. For tax year 2008, PG&E Corporation has ~~not recognized any benefits from~~been participating in the ~~federal capital loss carry forwards.~~IRS’ Compliance Assurance Process, a real-time audit process intended to expedite the resolution of issues raised during audits.

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 $2.1 billion of California capital loss carry forwards based on tax returns as filed, the majority of which, if not used by December 2008, will expire.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits.

In accordance with SFAS No. 5, "Accounting for ~~Contingencies,"~~Contingencies" PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E ~~Corporation's~~Corporation and the Utility's policy is to exclude anticipated legal costs.

The accrued liability for legal matters is included in PG&E ~~Corporation's~~Corporation and the Utility's Current Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately ~~$51~~$47 million at ~~June~~September 30, 2008 and approximately $78 million at December 31, 2007.

After considering the above accruals, PG&E Corporation and the Utility do not expect that losses associated with legal matters will have a material impact on their financial condition or results of operations.

3235

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

The Utility served approximately 5.1 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at ~~June~~September 30, 2008. The Utility had approximately ~~$38.3~~$39 billion in assets at ~~June~~September 30, 2008 and generated revenues of approximately ~~$7.3~~$11 billion in the ~~six~~nine months ended ~~June~~September 30, 2008.

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~~Corporation and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2007, which, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2007 Annual Report.” Significant developments that have occurred since the 2007 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 which the Utility is required to consolidate under applicable accounting standards and 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 Notes to the Consolidated Financial Statements incorporated by reference in the 2007 Annual Report.

Summary of Changes in Earnings per Common Share and Net Income for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2008

For the three months ended ~~June~~September 30, 2008, PG&E Corporation’s diluted earnings per common share (“EPS”) was ~~$0.80~~$0.83 compared to ~~$0.74~~$0.77 for the same period in 2007. For the ~~six~~nine months ended ~~June~~September 30, 2008, PG&E Corporation’s diluted EPS was ~~$1.42~~$2.24 compared to ~~$1.45~~$2.22 for the same period in 2007. PG&E Corporation’s net income for the three months ended ~~June~~September 30, 2008 increased by approximately ~~$24~~$26 million, or 9%, to ~~$293~~$304 million, compared to ~~$269~~$278 million for the same period in 2007. For the ~~six~~nine months ended ~~June~~September 30, 2008, net income ~~decreased~~increased by approximately $8$18 million, or 2%, to ~~$517~~$821 million, compared to ~~$525~~$803 million for the same period in 2007.

The increase in diluted EPS and net income for the three months ended ~~June~~September 30, 2008 compared to the same period in 2007 is primarily due to ~~(1)~~ the Utility’s return on equity (“ROE”) on higher authorized capital investments (representing a ~~$23~~$22 million increase in net income as compared to the same period in the prior year). The increase in diluted EPS and net income for the nine months ended September 30, 2008 compared to the same period in 2007 is primarily due to the Utility’s ROE on higher authorized capital investments (representing a $73 million increase in net income as compared to the same period in the prior year), and (2) lower refueling expenses at the Diablo Canyon nuclear generating facilities (“Diablo Canyon”) than the prior year due to the timing of the outage (resulting in a $21 million increase in net income). These increases to net income were partially offset by ~~increased operating and maintenance expenses associated with the natural gas system (resulting in a $6 million decrease in net income as compared to the same period in the prior year).~~

~~The decrease in diluted EPS and net income for the six months ended June 30, 2008 compared to the same period in 2007 is primarily due to~~ (1) higher storm and outage-related costs, largely due to severe winter weather that occurred in January 2008 (resulting in a ~~$26~~$27 million decrease in net income as compared to the same period in the prior year), (2)

increased ~~refueling~~operating and maintenance expenses ~~at Diablo Canyon~~associated with the natural gas system (resulting in a $17 million decrease in net income as compared to the same period in the prior ~~year~~year), and (3) increased refueling expenses at the Utility’s Diablo Canyon nuclear generating facilities (“Diablo Canyon”) resulting from an extended outage to replace the steam generators in one of the nuclear generating units (resulting in a $6 million decrease in net income), (3) increased operating and maintenance expenses associated with the natural gas system (resulting in a $10 million decrease in net income), and (4) other increased expenses (resulting in a $16 million decrease in net income). Most of the decreases in net income was offset by the Utility’s ROE on higher authorized capital investments (representing a $51 million increase in net income as compared to the same period in the prior year).

Key Factors Affecting Results of Operations and Financial Condition

PG&E ~~Corporation’s~~Corporation and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E ~~Corporation's~~Corporation and the Utility's results of operations and financial condition, including:

·	The Outcome of Regulatory Proceedings and the Impact of Ratemaking Mechanisms. The amount of the Utility’s revenues and the amount of costs that the Utility is authorized to recover from customers are primarily determined through regulatory proceedings. 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. ~~On July 30, 2008,~~Unlike the ~~Utility filed~~current GRC, which set revenue requirements for a ~~new TO rate case requesting~~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 retail revenue requirement of approximately $849 million and a rate increase, effective October 1, 2008, to recover the costs associated with significant electric transmission infrastructure expansion and replacement.three-year period (2011 through 2013). From time to time, the Utility also files separate applications requesting the CPUC or the FERC to authorize additional revenue requirements for specific projects, such as new power plants, gas or electric transmission ~~projects, and the~~facilities, installation of an advanced metering ~~infrastructure. On May 15, 2008, the Utility requested that the CPUC approve additional funding to improve customer service~~infrastructure, and reliability ~~beyond the level assumed in the last GRC.~~improvements. The Utility’s revenues can also be affected by incentive ratemaking, such as the CPUC’s customer energy efficiency shareholder incentive mechanism. The amount of incentives the Utility may receive and the amount of any reimbursement obligations the Utility may incur will depend on the level of energy efficiency savings actually achieved over the three-year program cycles (2006-2008 and 2009-2011). (See “Regulatory Matters” below.) Finally, the outcome of regulatory proceedings may also be affected by ~~increases~~volatility in the prices of natural gas and electricity as these costs are passed through to customers in the form of higher rates.

·	Capital Structure and Return on Common Equity. On May 29, 2008, the CPUC adopted a new three-year cost of capital mechanism to replace the CPUC’s annual cost of capital proceeding. The Utility’s current authorized capital structure, including a 52% common equity component, will be maintained through 2010. The Utility’s current authorized cost of capital, including a ROE of 11.35% on its electric and natural gas distribution and electric generation rate base, will be maintained through 2010, unless the annual automatic adjustment mechanism established by the CPUC is triggered. The Utility can apply for an adjustment to either the capital structure or cost of capital sooner based on extraordinary circumstances. (See “Regulatory Matters” below.) In September 2007, the FERC accepted the Utility’s request to earn a ROE of 12% on its electric transmission rate base, as part of the annual TO rate case, effective March 1, 2008, subject to hearing and refund.

·	The Ability of the Utility to Control Costs While Improving Reliability. The Utility’s revenue requirements are primarily set based on forecasted operating expenses and capital expenditures. The Utility’s revenue requirements are designed to allow the Utility to earn an ROE, as well as to recover depreciation, tax, and interest expense associated with authorized capital expenditures. ~~Material differences~~Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can ~~materially~~ affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s net income available for shareholders. ~~In particular, the~~The Utility anticipates that it will incur higher expenses than originally forecasted in the GRC ~~in connection with~~to maintain the ~~operations~~aging infrastructure of its electric and natural gas systems and to improve operating and maintenance ~~of its natural gas system and maintenance of aging infrastructure.~~processes. The Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies to create future sustainable cost-savings and to offset increased spending related to the natural gas system and the increasing cost of materials. (See “Results of Operations – Operating and Maintenance” below.) When capital is placed in service at a higher rate than forecasted, the Utility incurs associated depreciation, property tax, and interest expense. The Utility does not recover an ROE on the higher level of capital expenditures until added to rate base in future rate cases. The Utility’s financial condition and results of operations will be impacted by the amount of revenue requirements it is authorized to recover, the amount and timing of its capital expenditures, and whether the Utility is able to manage its operating costs and capital expenditures within authorized ~~revenues.~~levels.

The ~~Amount and Timing~~Availability of Debt and Equity ~~Financing Needs.~~Financing. The Utility’s needs for additional financing during 2008 and future years will be affected by the amount and timing of capital expenditures, as well as by 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 (“~~Disputed Claims”~~Chapter 11”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) ~~In addition,~~The Utility’s ability to make scheduled principal and interest payments, refinance debt, fund operations, deposit collateral in connection with its natural gas and electricity procurement hedging contracts, and make planned capital expenditures, depends on the levels of its operating cash flow and access to the capital markets. The recent financial distress experienced at major financial institutions has caused significant disruption in the capital markets. Although the Utility continues to have access to the commercial paper markets, short-term interest rates have increased significantly. Interest rates on long-term debt also have increased. For example, the Utility’s ~~financing needs will be affected by when certain pollution control bonds aggregating $454~~$600 million principal amount of 10-year senior notes issued on October 21, 2008 bear interest at 8.25% compared to the Utility’s $700 million principal amount of 10-year senior notes issued in December 2007 and March 3, 2008 that ~~the Utility repurchased during March and April 2008 can be resold. The Utility’s financial condition and results of operations will be affected by the~~bears interest ~~rates, timing, and terms and conditions of any such financings.~~at 5.625%. The timing and amount of PG&E Corporation’s future equity contributions to the Utility will affect the timing and amount of any PG&E Corporation equity issuances and/or debt issuances which, in turn, will affect PG&E Corporation’s results of operations and financial condition. (See “Liquidity and Financial Resources” below.)

In addition to the key factors discussed above, PG&E ~~Corporation’s~~Corporation and the Utility’s future results of operations and financial condition are subject to the risk factors discussed in the section entitled “Risk Factors” in the 2007 Annual Report and the section entitled “PART II Item 1A. Risk Factors” below.

FORWARD-LOOKING STATEMENTS

This combined quarterly report on Form 10-Q, including the MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, anticipated costs and savings associated with the Utility’s efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable cost-savings, estimated capital expenditures, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

·	the Utility’s ability to manage capital expenditures and operating expenses within authorized levels and recover such costs through rates in a timely manner;

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

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

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

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

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

·	operating performance of Diablo Canyon, 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 it has recognized from operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures;

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

·	whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives 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 new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;

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

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

·	the ability of PG&E Corporation, ~~and/or~~ the Utility, and counterparties, to access capital markets and other sources of credit in a timely manner on ~~favorable terms;~~acceptable terms, especially given the recent deteriorating conditions in the economy and financial markets;

·	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 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~~Corporation and the Utility's future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2007 Annual Report and the section entitled ~~“Part~~“PART II Item 1A. Risk Factors” below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events or otherwise.

3638

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007:

		Three Months Ended						Six Months Ended							Three Months Ended						Nine Months Ended
		June 30,						June 30,							September 30,						September 30,
(in millions)		2008			2007			2008			2007				2008			2007			2008			2007
Utility
Electric operating revenues		$	2,645		$	2,359		$	5,159		$	4,534			$	2,880		$	2,574		$	8,039		$	7,107
Natural gas operating revenues			933			828			2,152			2,009				794			705			2,946			2,714
Total operating revenues			3,578			3,187			7,311			6,543				3,674			3,279			10,985			9,821
Cost of electricity			1,097			884			2,124			1,607				1,282			998			3,406			2,606
Cost of natural gas			487			396			1,262			1,150				351			281			1,613			1,431
Operating and maintenance			991			921			2,027			1,840				982			950			3,009			2,788
Depreciation, amortization, and decommissioning			418			430			820			859				419			465			1,239			1,325
Total operating expenses			2,993			2,631			6,233			5,456				3,034			2,694			9,267			8,150
Operating income			585			556			1,078			1,087				640			585			1,718			1,671
Interest income			33			35			57			83				20			33			77			116
Interest expense			(178	)		(178	)		(358	)		(360	)			(170	)		(189	)		(528	)		(549	)
Other income, net(1)			3			11			19			17
Other income (expense), net(1)																(5	)		9			14			28
Income before income taxes			443			424			796			827				485			438			1,281			1,266
Income tax provision			134			154			254			299				167			159			421			458
Income available for common stock		$	309		$	270		$	542		$	528			$	318		$	279		$	860		$	808
PG&E Corporation, Eliminations and Other(2)
Operating revenues		$	-		$	-		$	-		$	-			$	-		$	-		$	-		$	-
Operating expenses			1			1			1			3				1			3			2			6
Operating loss			(1	)		(1	)		(1	)		(3	)			(1	)		(3	)		(2	)		(6	)
Interest income			-			2			2			6				3			3			5			9
Interest expense			(7	)		(7	)		(14	)		(15	)			(8	)		(7	)		(22	)		(22	)
Other expense, net			(2	)		(1	)		(16	)		(3	)			(12	)		(2	)		(28	)		(6	)
Loss before income taxes			(10	)		(7	)		(29	)		(15	)			(18	)		(9	)		(47	)		(25	)
Income tax provision (benefit)			6			(6	)		(4	)		(12	)
Income tax benefit																(4	)		(8	)		(8	)		(20	)
Net loss		$	(16	)	$	(1	)	$	(25	)	$	(3	)		$	(14	)	$	(1	)	$	(39	)	$	(5	)
Consolidated Total
Operating revenues		$	3,578		$	3,187		$	7,311		$	6,543			$	3,674		$	3,279		$	10,985		$	9,821
Operating expenses			2,994			2,632			6,234			5,459				3,035			2,697			9,269			8,156
Operating income			584			555			1,077			1,084				639			582			1,716			1,665
Interest income			33			37			59			89				23			36			82			125
Interest expense			(185	)		(185	)		(372	)		(375	)			(178	)		(196	)		(550	)		(571	)
Other income, net(1)			1			10			3			14
Other income (expense), net(1)																(17	)		7			(14	)		22
Income before income taxes			433			417			767			812				467			429			1,234			1,241
Income tax provision			140			148			250			287				163			151			413			438
Net income		$	293		$	269		$	517		$	525			$	304		$	278		$	821		$	803


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

3739

Utility

The following presents the Utility's operating results for the three and ~~six~~nine months ended ~~June~~September 30, 2008 and 2007.

Electric Operating Revenues

The Utility provides electricity to residential, industrial, and small and large commercial customers through its own generation facilities and through ~~contracts~~power purchase agreements with third ~~parties under power purchase agreements.~~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 (“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 programs, energy efficiency programs, and demand side management.

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

		Three Months Ended						Six Months Ended							Three Months Ended						Nine Months Ended
		June 30,						June 30,							September 30,						September 30,
(in millions)		2008			2007			2008			2007				2008			2007			2008			2007
Electric revenues		$	2,948		$	2,868		$	5,789		$	5,594			$	3,255		$	3,172		$	9,044		$	8,765
DWR pass-through revenues(1)			(303	)		(509	)		(630	)		(1,060	)			(375	)		(598	)		(1,005	)		(1,658	)
Total electric operating revenues		$	2,645		$	2,359		$	5,159		$	4,534			$	2,880		$	2,574		$	8,039		$	7,107
Total electricity sales (in Gigawatt hours)(2)			18,141			16,177			35,477			30,955
Total electricity sales (in millions of kWh)(2)																21,183			18,688			56,660			49,643


(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.	(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.													(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.
(2)These volumes exclude electricity provided by DWR.	(2)These volumes exclude electricity provided by DWR.													(2)These volumes exclude electricity provided by DWR.

The Utility’s electric operating revenues increased by approximately ~~$286~~$306 million, or 12%, in the three months ended ~~June~~September 30, 2008 and approximately ~~$625~~$932 million, or ~~14%~~13%, in the ~~six~~nine months ended ~~June~~September 30, 2008, compared to the same periods in 2007 mainly due to the following factors:

·	Electricity procurement costs ~~which are~~ passed through to customers increased by approximately ~~$208~~$291 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$505~~$798 million in the ~~six~~nine months ended ~~June~~September 30, 2008, primarily due to an increase in the volume of power purchased by the Utility following the DWR’s termination of a power purchase contract in December 2007 and during the extended scheduled outage at Diablo Canyon earlier this year, and increases in purchased power prices. (See “Cost of Electricity” below.)

·	Electric operating revenues to fund public purpose and energy efficiency programs increased by approximately ~~$62~~$36 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$138~~$175 million in the ~~six~~nine months ended ~~June~~September 30, ~~2008.~~2008 primarily due to an increase in expenses for these programs. (See “Operating and Maintenance” below.)

·	Base revenue requirements increased by approximately $26 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$51~~$77 million in the ~~six~~nine months ended ~~June~~September 30, 2008, as a result of attrition adjustments as authorized in the 2007 GRC.

·	Electric transmission revenues increased by approximately ~~$12~~$13 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$27~~$40 million in the ~~six~~nine months ended ~~June~~September 30, 2008, primarily due to an increase in rates as authorized in the current TO rate case.

·	Other electric operating revenues ~~including~~increased by approximately $22 million in the three months ended September 30, 2008 and approximately $70 million in the nine months ended September 30, 2008 primarily due to increases in revenues to recover costs related to the Diablo Canyon steam generator replacement project and revenues to fund the ~~Smart Meter~~SmartMeterTMadvanced metering project ~~increased by approximately $43 million in the three months ended June 30, 2008 and approximately $39 million in the six months ended June 30, 2008. (See~~(see “Capital Expenditures” ~~below.~~below for further discussion of SmartMeterTM).

These increases were partially offset by a decrease of approximately ~~$65~~$76 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$135~~$210 million in the ~~six~~nine months ended ~~June~~September 30, 2008, representing the amount of revenue collected

during ~~these~~the comparable periods in 2007 for payment of principal and interest on the ~~Rate Reduction Bonds~~rate reduction bonds (“RRBs”) that matured in December ~~2007.~~2007 and approximately $6 million and $18 million for the three and nine months ended September 30, 2008, representing the amount of revenue collected for payment of the energy recovery bonds (“ERBs”) due to their declining balance.

The Utility’s electric operating revenues for 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. 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 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. Finally, future electric operating revenues ~~will increase as~~are impacted by changes in the Utility’s electricity procurement costs ~~increase,~~ as discussed under “Cost of Electricity” below.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs, ~~and~~ the cost of fuel used by its generation facilities, orthe cost of fuel supplied to other facilities under tolling ~~agreements.~~agreements, and realized gains and losses on price risk management activities. (See Note 7 and 8 of the Notes to the Condensed Consolidated Financial Statements for further information.) The Utility’s cost of purchased power, ~~and the~~ cost of fuel used in Utility-owned generation, and cost of fuel supplied to other facilities under tolling agreements are passed through to customers. 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~~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						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
(in millions)	2008			2007			2008			2007			2008			2007			2008			2007
Cost of purchased power	$	1,140		$	892		$	2,178		$	1,620		$	1,334		$	990		$	3,511		$	2,609
Proceeds from surplus sales allocated to the Utility		(90	)		(46	)		(135	)		(88	)		(90	)		(26	)		(225	)		(112	)
Fuel used in own generation		47			38			81			75			38			34			120			109
Total cost of electricity	$	1,097		$	884		$	2,124		$	1,607		$	1,282		$	998		$	3,406		$	2,606
Average cost of purchased power per kWh	$	0.089		$	0.084		$	0.088		$	0.087		$	0.091		$	0.088		$	0.089		$	0.087
Total purchased power (in millions of kWh)		12,862			10,629			24,652			18,683			14,726			11,291			39,377			29,975

The Utility's total cost of electricity increased by approximately ~~$213~~$284 million, or ~~24%~~28%, in the three months ended ~~June~~September 30, 2008 and by approximately ~~$517~~$800 million, or ~~32%~~31%, in the ~~six~~nine months ended ~~June~~September 30, 2008, compared to the same periods in 2007. These increases were primarily driven by increases in the total volume of purchased power of ~~2,233~~3,435 million kilowatt-hours (“kWh”), or ~~21%~~30%, for the three months ended ~~June~~September 30, 2008 and ~~5,969~~9,402 million kWh, or ~~32%~~31%, for the ~~six~~nine months ended ~~June~~September 30, 2008. Following the DWR’s termination of its power purchase agreement with Calpine Corporation in December 2007, the volume of power provided by the DWR to the Utility’s customers decreased. As a result, the Utility was required to increase its purchases of power from third parties to meet customer load. Higher market prices also contributed to an increase in the cost of purchased power for the three and nine months ended September 30, 2008 compared to the same periods in 2007. In addition, during the ~~three and six~~nine months ended ~~June~~September 30, 2008, the Utility increased the volume of power it purchased from third parties during the extended outage at Diablo Canyon Unit 2 that lasted from February through mid-April 2008. (See “Operating and Maintenance” below.) In comparison, because the refueling outage of Diablo Canyon Unit 1 occurred entirely during May 2007, the increase in the volume of purchased power for the same ~~periods~~period in 2007 was lower. ~~Higher market prices also contributed to an increase in the cost of purchased power for the three and six months ended June 30, 2008 compared to the same periods in 2007.~~

Various factors will affect the Utility’s future ~~costs~~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 are terminated or ~~expired.~~expire. The Utility expects that its cost of electricity in 2008 will continue to increase compared to 2007 as the Utility continues to purchase replacement power due to the DWR’s termination of its power purchase agreement with Calpine Corporation in December 2007. ~~The Utility also anticipates lower output~~Output from the Utility’s hydroelectric generation facilities ~~caused by lower than normal~~is dependent on levels of precipitation ~~resulting in increases~~and could impact the volume of purchased power. ~~In addition, rising~~Volatility in natural gas prices ~~are~~is expected to ~~increase~~impact the Utility’s cost of electricity for the remainder of 2008 and future years. The Utility’s future cost of electricity also may be affected by federal or state legislation or rules which may be adopted to regulate the emissions of greenhouse gases from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. As directed by recent California legislation, the CPUC has

already adopted an interim greenhouse gas emissions performance standard that would apply to electricity procured or generated by the Utility.

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 California for delivery to the Utility's distribution system which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

Average bundled revenue per Mcf(1) of natural gas sold

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

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

Three Months Ended Six Months Ended

June 30,

June 30,

(in millions)
2008

2007

2008

2007

Cost of natural gas sold $ 448 $ 354 $ 1,202 $ 1,060
Cost of natural gas transportation 39 42 60 90
Total cost of natural gas $ 487 $ 396 $ 1,262 $ 1,150
Average cost per Mcf of natural gas sold $ 8.30 $ 6.68 $ 7.20 $ 6.42

The Utility's total cost of natural gas increased in the three and ~~six~~nine months ended ~~June~~September 30, 2008 by approximately ~~$91~~$70 million, or ~~23%~~25%, and by approximately ~~$112~~$182 million, or ~~10%~~13%, compared to the same periods in 2007, primarily due to increases in the average market price of natural gas purchased in the three and ~~six~~nine months ended ~~June~~September 30, 2008. ~~Average market prices were higher in~~For the ~~three and six~~nine months ended June 30, 2008 due to higher demand in the national market, lower imports of liquefied natural gas, and the higher global cost of crude oil and other energy commodities, as compared to the same periods in 2007. For the six months ended JuneSeptember 30, 2008, the increase was partially offset by aan approximately $23 million refund the Utility received as part of a settlement with TransCanada’s Gas Transmission Northwest Corporation for 2007 gas transmission capacity rates.

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.

The Utility’s operating and maintenance expenses increased by approximately ~~$70~~$32 million, or 8%3%, and approximately ~~$187~~$221 million, or ~~10%~~8%, in the three and ~~six~~nine months ended ~~June~~September 30, 2008, respectively, compared to the same ~~period~~periods in 2007. Expenses increased mainly due to the following factors:

·	Public purpose program and customer energy efficiency incentive program expenses increased by approximately ~~$67~~$48 million and ~~$140~~$187 million in the three and ~~six~~nine months ended ~~June~~September 30, 2008 ~~respectively. These changes were~~ primarily due to increased customer participation and increased marketing of new and existing ~~programs.~~programs, including the California Solar Initiative program and the Self-Generation Incentive Program. Of these changes, approximately ~~$62~~$36 million and ~~$138~~$175 million, respectively, ~~are~~were recovered in electric operating revenues and ~~approximately $6~~less than $1 million and $14 million, respectively, ~~are~~were recovered in natural gas operating revenues. ~~The excess of revenue over expense is primarily~~Expenses related to public purpose programs and energy efficiency programs are generally fully recoverable and differences between costs and revenues in a particular period are due to timing differences.

·	Costs increased by approximately $38 million during the ~~recovery during~~nine months ended September 30, 2008 for the repair and restoration of electric distribution systems and to respond to customer inquiries following the January 2008 winter storm. Of the approximately $38 million in costs, ~~incurred during~~ the ~~second half of 2007 related~~Utility has requested that the CPUC permit the Utility to recover approximately $8 million from its customers. There was no similar storm in the ~~SmartAC~~TM ~~Program.~~same period in 2007.

·	Labor costs increased by approximately ~~$11~~$12 million and ~~$17~~$29 million in the three and ~~six~~nine months ended ~~June~~September 30, 2008, respectively, to conduct expanded natural gas leak surveys in parts of the Utility's service territory and to make related repairs in an effort to improve operating and maintenance processes in the Utility's natural gas system.

·	There was an increase in maintenance costs of approximately $10 million in the nine months ended September 30, 2008 compared to the same period in 2007 due to the longer duration of the planned outage of Diablo Canyon Unit 2 in 2008 compared to the Diablo Canyon Unit 1 outage in 2007.

·	Costs related to injuries and damages not specifically related to gas or electric lines of business ~~increased~~decreased by approximately $8$7 million ~~for both~~and $12 million in the three and ~~six~~nine months ended ~~June~~September 30, 2008, ~~as a result of a favorable settlement~~respectively, due to increases in ~~2007. There was~~reserves during 2007 for which there were no similar ~~settlement~~increases in 2008.

·	~~Labor costs increased~~Costs decreased by approximately $6$12 million ~~for system-wide repair and restoration of electric distribution systems for~~in the three months ended ~~June 30, 2008. For the six months ended June~~September 30, 2008 ~~labor costs~~compared to the same period in 2007 due primarily to an initiative to implement operational efficiencies which occurred primarily during the third quarter of 2007. Costs increased by approximately ~~$38 million for the repair and restoration of electric distribution systems and responding to customer inquiries as a result of the January 2008 winter storm. Of the approximately $38~~$5 million in the nine months ended September 30, 2008 compared to the same period in 2007 due to primarily to an increase in costs ~~the Utility is seeking recovery of~~related to software maintenance contracts.

·	Advertising decreased by approximately ~~$12~~$9 million and $10 million in ~~eligible costs in its March 28,~~the three and nine months ended September 30, 2008 ~~Catastrophic Events Memorandum Account application. There was no similar storm in~~as compared to the same period in 2007.

·	~~The timing of the planned outages at Diablo Canyon favorably impacted the results~~Costs decreased by approximately $12 million for the three and nine months ended ~~June~~September 30, 2008 ~~compared~~due to a CPUC decision ordering the Utility make a refund to ratepayers in 2007 related to billing practices for which there was no similar decision in 2008.

·	Costs decreased by approximately $12 million for the nine months ended September 30, 2008 due to a larger increase in accrual in 2007 than in 2008 related to compensation for employees’ missed meals. (See Note 11 of the Notes to the ~~same period in 2007. There was~~Condensed Consolidated Financial Statements for a ~~decrease in maintenance costs~~discussion of California labor code issues.)

·	Costs decreased by approximately ~~$35~~$9 million ~~because the planned outage of Diablo Canyon Unit 1 occurred during the second quarter of 2007, while costs~~ for the ~~planned outage~~nine months ended September 30, 2008 due a larger increase in accrual in 2007 than in 2008 related to employee severance due to the elimination and consolidation of ~~Diablo Canyon Unit 2 were incurred primarily in the first quarter of 2008.~~various employee positions.

In addition, there was an aggregate increase of ~~$13~~approximately $12 million and ~~decrease of $16~~$7 million in the three and ~~six~~nine months ended ~~June~~September 30, 2008, respectively, representing other miscellaneous operating and maintenance expenses that changed from the comparable ~~period~~periods in 2007.

Operating and maintenance expenses are influenced by wage inflation, benefits, property taxes, the timing and length of Diablo Canyon refueling outages, environmental remediation costs, legal costs, material costs, and various other administrative and general expenses. The Utility anticipates that it will incur higher material, permitting, and labor costs in the future as well as higher costs to operate and maintain its aging infrastructure. The Utility may make additional payments to employees for missed or delayed meals to comply with California labor law as the Utility’s investigation into this matter continues. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of California labor code issues.) The Utility is currently negotiating the terms of a collective bargaining agreement with three labor unions covering approximately 13,000 employees. Two of the collective bargaining agreements will expire on December 31, 2008. The other collective bargaining agreement expires on February 28, 2009. The Utility’s future labor and benefit costs will be impacted by the terms of the new collective bargaining agreements.

In addition, the Utility anticipates that it will incur costs, not included in forecasts used to set rates in the GRC, to improve operating and maintenance processes used in its natural gas system following the discovery that some operating and maintenance activities were not effective. ~~The amount of these additional expenses will depend on the outcome of the Utility’s continuing review of these operating and maintenance activities.~~ (See "Risk Factors" in the 2007 Annual Report.) The Utility also expects that it will incur higher expenses in future periods to comply with the requirements of renewed FERC licenses for the Utility’s hydroelectric generation facilities. The Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies to create future sustainable cost-savings and to offset increased spending to address operational issues and increasing cost of materials.

Depreciation, Amortization, and Decommissioning

The Utility's depreciation, amortization, and decommissioning expenses decreased by approximately ~~$12~~$46 million, or 3%10% in the three months ended ~~June~~September 30, 2008 and approximately ~~$39~~$86 million, or 5%6%, in the ~~six~~nine months ended ~~June~~September 30, 2008, as compared to the same periods in 2007, mainly due to decreases in amortization expense of approximately ~~$60~~$73 million and ~~$124~~$197 million, respectively, related to the ~~rate reduction bond (“RRB”)~~RRB regulatory asset. The RRB regulatory asset was fully recovered through rates when the RRBs matured in December 2007 and, as a result, no amortization has been recorded in 2008. These decreases were partially offset by increases to depreciation expense of approximately ~~$48~~$27 million in the three months ended ~~June~~September 30, 2008 and approximately ~~$85~~$111 million in the ~~six~~nine months ended ~~June~~September 30, ~~2008. Depreciation expense increased~~2008 primarily due to plant additions and depreciation rate changes as authorized in the 2007 GRC and the current TO rate case.

The Utility’s depreciation, amortization, and decommissioning expenses in subsequent years are expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the 2007 GRC decision and future TO rate cases.

Interest Income

In the three months ended ~~June~~September 30, 2008, the Utility’s interest income decreased by approximately $2$13 million, or 6%39%, as compared to the same period in 2007. AInterest income decreased by $10 million ~~decrease in interest income was~~ primarily due to lower interest rates earned on funds held in escrow related to ~~Disputed Claims~~disputed claims and a lower escrow balance reflecting settlements of ~~Disputed Claims. The~~disputed claims. There was an additional decrease ~~was partially offset by an increase~~ of approximately $8$3 million in other interest ~~including a decision to allow recovery of interest income on a regulatory asset established for the recovery of certain scheduling coordinator (“SC”) costs.~~income.

In the ~~six~~nine months ended ~~June~~September 30, 2008, the Utility’s interest income decreased by approximately ~~$26~~$39 million, or ~~31%~~34%, as compared to the same period in 2007 when the Utility received approximately $16 million in interest income on a federal tax ~~refund received in 2007.~~refund. In addition, there was a decrease of ~~$16~~$26 million in interest income, primarily due to lower interest rates earned on funds held in escrow related to ~~Disputed Claims~~disputed claims and a lower escrow balance reflecting settlements of ~~Disputed Claims.~~disputed claims. These decreases were partially offset by an increase of approximately $6$3 million in other ~~interest, including a decision to allow recovery of interest income on a regulatory asset established for the recovery of certain SC costs.~~interest.

The Utility’s interest income in 2008 and future periods will be primarily affected by changes in the balance held in escrow related to ~~Disputed Claims~~disputed claims and changes in interest rate levels.

Interest Expense

In the three and ~~six~~nine months ended ~~June~~September 30, 2008, there was ~~no change in the Utility’s interest expense, and~~ a decrease of approximately $2$19 million, or 1%10%, and $21 million, or 4%, respectively, as compared to the same periods in 2007. Interest expense decreased primarily due to the following factors:

Interest expense decreased by approximately $18 million in the three months ended September 30, 2008, and approximately $16 million in the nine months ended September 30, 2008, primarily due to lower FERC interest rates accrued on the liability for disputed claims.

·	Interest expense decreased by approximately $7 million in the three months ended ~~June~~September 30, 2008, and approximately ~~$28~~$21 million in the ~~six~~nine months ended ~~June~~September 30, 2008, due to the reduction in the outstanding balance of ~~energy recovery bonds~~ERBs and the maturity of the RRBs in December 2007.

·	Interest expense on pollution control bonds decreased by approximately $7$6 million in the three ~~and six~~ months ended ~~June~~September 30, 2008 and $13 million in the nine months ended September 30, 2008, due to the repurchase of auction rate pollution control bonds ~~series 2005 A-G (“PC2005 bonds”)~~ in March and April 2008 and a decrease in interest rates on outstanding variable rate pollution control bonds.

·	Interest expense decreased by approximately $16 million in the nine months ended September 30, 2008, primarily due to lower interest rates affecting various balancing accounts.

·	Other interest expense decreased by approximately $2$4 million in the three months ended ~~June~~September 30, 2008, primarily due to a lower balance of borrowings outstanding under the Utility’s $2 billion revolving credit facility and approximately $1$5 million in the ~~six~~nine months ended ~~June~~September 30, 2008, primarily due to lower commercial paper interest ~~rates and a lower average outstanding commercial paper balance.~~rates.

These decreases were partially offset by an additional interest expense of approximately $16 million in the three months ended ~~June~~September 30, 2008, and approximately ~~$34~~$50 million in the ~~six~~nine months ended ~~June~~September 30, 2008, ~~in interest expense~~ related to $1.2 billion in ~~Senior Notes~~senior notes issued in March and December 2007 and $600 million in ~~Senior Notes~~senior notes issued in March 2008.

The Utility’s interest expense in 2008 and future periods will be impacted by changes in interest rates, as ~~the Utility’s short-term debt and a portion of its long-term debt bear variable interest rates, as~~ well as by changes in the amount of debt outstanding ~~including~~as long-term debt matures and additional long-term debt is issued (see “Liquidity and Financial Resources” below for ~~debt maturities and to finance capital expenditures in future periods.~~further discussion).

Other Income (Expense), Net

The Utility’s other income (expense), net decreased by approximately $14 million, or 156%, in the three months ended September 30, 2008 and $14 million, or 50%, in the nine months ended September 30, 2008 compared to the same periods in 2007. These decreases are primarily due to an increase in costs of approximately $19 million in the three and nine months ended September 30, 2008 due to the Utility’s efforts to oppose the statewide initiative related to renewable energy (Proposition 7) and the City of San Francisco’s municipalization efforts.

Income Tax Expense

The Utility's income tax expense ~~decreased~~increased by approximately ~~$20~~$8 million, or ~~13%~~5%, for the three months ended ~~June~~September 30, 2008 and decreased by approximately ~~$45~~$37 million, or ~~15%~~8%, for the ~~six~~nine months ended ~~June~~September 30, 2008, as compared to the same periods in 2007. The effective tax rates for the three months ended ~~June~~September 30, 2008 and 2007 were ~~30.0%~~34.1% and 36.0%, respectively. The effective tax rates for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 were ~~31.6%~~32.6% and 35.9%, respectively. The ~~decrease~~decreases in the effective tax ~~rates~~rate for ~~both~~ the three and ~~six~~nine months ended ~~June~~September 30, 2008 ~~are~~were primarily due to the ~~Internal Revenue Service (“IRS”)~~IRS’ approval of the Utility’s change in accounting method for the capitalization of indirect service costs for tax years 2001-2004, which resulted in a reduction of accrued interest on uncertain tax positions. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters” ~~for further discussion.~~.) ~~For the six months ended June 30, 2008, an IRS audit settlement reached in January 2008 also decreased the effective tax rate. There was no similar settlement recorded in the same periods in 2007.~~

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 is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three and ~~six~~nine months ended ~~June~~September 30, 2008 as compared to the same period in 2007.

Other Expense, Net

PG&E Corporation's other expense increased by approximately $1$10 million, or ~~50%~~500%, for the three months ended ~~June~~September 30, 2008, and approximately ~~$13~~$22 million, or ~~433%~~367%, for the ~~six~~nine months ended ~~June~~September 30, 2008 primarily due to an increase in investment losses in the rabbi trusts related to the Rabbi Trust, an increase of political contributions, and an increase in dividend participation rights expense as a result of the implementation of Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS No. 157”).non-qualified deferred compensation plans.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility utilize $200 million and $2 billion revolving credit facilities, respectively, along with cash generated from operations, to fund electricity and natural gas purchases on behalf of customers, collateral requirements for commodity contracts and, for short periods of time, capital expenditures, among other things. The level of the Utility's short-term debt fluctuates as a result of seasonal demand for electricity and natural gas, energy commodity costs, collateral requirements, the timing and effect of regulatory decisions and financings, and the amount and timing of capital expenditures, among other factors. The Utility generally utilizes long-term senior unsecured debt and equity issuances, while maintaining its CPUC-authorized capital structure, to fund debt maturities and capital expenditures. PG&E Corporation funds equity contributions to the Utility through the issuance of common stock and long-term debt.

Access to the capital markets is essential to the continuation of the Utility’s capital expenditure program. The Utility currently plans to incur additional long-term debt of $3.5 billion to $4.0 billion through the remainder of 2008 and through 2011, excluding the October pollution control bond financing and senior notes issuance discussed below. Of this amount, the Utility expects to incur approximately $1.0 billion of long-term debt within the next six months primarily to finance capital expenditures and to refinance $600 million of long-term debt that will mature in March 2009. In addition, PG&E Corporation expects to issue additional common stock, debt, or other securities to fund a portion of the Utility’s future equity needs through 2011.

The recent disruption in the capital markets has made it challenging for companies to access the markets for commercial paper, new credit facilities and unsecured long-term debt. Notwithstanding this volatility, the Utility has continued to have access to the commercial paper market, albeit at higher prices and with shorter duration, and was able to secure a new credit facility to support the pollution control bond financing discussed below. In addition, as discussed below, the Utility was able to issue $600 million of senior unsecured 10-year notes in October 2008.

These financings have enabled the Utility to repay its outstanding commercial paper such that the Utility has available liquidity of $1.4 billion as of October 31, 2008, which consists of $1.1 billion of availability under its revolving credit facility and $231 million of unrestricted cash and cash equivalents. PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and access to the capital markets on reasonable terms, will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures.

The amount and timing of the Utility’s future financing needs will depend on various factors, including: (1) the conditions in the capital markets and the Utility’s ability to access the capital markets; (2) the timing and amount of forecasted capital expenditures, and incremental capital expenditures beyond those currently forecasted, and the ability of the Utility, if necessary, to defer, postpone, or cease certain capital expenditures; (3) the amount of cash internally generated through normal business operations; (4) the amount of collateral required for commodity contract commitments; and (5) the timing of the resolution of the 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). The amount and timing of PG&E Corporation’s future financing needs will depend on various factors, including the need to infuse capital in the Utility to maintain its 52% equity structure and fund capital expenditures.

At ~~June~~September 30, 2008, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately ~~$297~~$251 million and restricted cash of approximately $1.3 billion. At ~~June~~September 30, 2008, PG&E Corporation on a

stand-alone basis had cash and cash equivalents of approximately ~~$228~~$194 million; the Utility had cash and cash equivalents of approximately ~~$69~~$57 million and restricted cash of approximately $1.3 billion. Restricted cash primarily consists of approximately $1.2 billion of cash held in escrow pending the resolution of the remaining ~~Disputed Claims as well as deposits made~~disputed claims filed in the Utility’s reorganization proceeding under ~~certain third-party agreements.~~Chapter 11. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in money market funds.

Each of PG&E Corporation’s and the Utility’s revolving credit facilities include commitments from a well-diversified syndicate of lenders. Neither credit facility permits the lenders to refuse funding a draw solely due to the occurrence of a “material adverse effect” as defined in the facilities. No single lender’s commitment represents more than 11% of total borrowing capacity under either facility. As of ~~June~~October 31, 2008, the commitment from Lehman Brothers Bank, FSB represented approximately $13 million or 7%, of the total borrowing capacity under PG&E Corporation’s $200 million senior credit facility and approximately $60 million, or 3%, of the Utility’s $2.0 billion working capital facility.

As of September 30, 2008, the Utility had ~~$281~~$273 million of letters of credit and no$533 million of borrowings outstanding under its $2.0 billion working capital ~~facility (“working capital facility”). As of June 30, 2008, the~~facility. The Utility also ~~had $156 million of outstanding commercial paper. The Utility~~ treats the amount of its outstanding commercial paper as a reduction to the amount available under its working capital facility. As of ~~June~~September 30, 2008, the Utility had ~~approximately $1.6 billion~~$802 million of ~~short-term CPUC-authorized debt capacity available. The Utility expects that the current total available capacity under its~~outstanding commercial ~~paper and working capital facilities will be sufficient to meet any additional short-term borrowing needs.~~

~~During March and April~~paper. As of October 31, 2008, the Utility ~~repurchased $454~~has repaid all of its outstanding commercial paper using the proceeds from the financings discussed below. PG&E Corporation has no outstanding borrowings or letters of credit under its senior credit facility.

On October 21, 2008, the Utility issued $600 million principal amount of ~~PC2005~~8.25% 10-year Senior Notes due on October 15, 2018. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the Utility’s other series of Senior Notes issued in 2008.)

In addition to the senior notes issuance, the Utility received $95 million and $309 million from the September 22, 2008 and October 29, 2008 sales of pollution control bonds issued by the California Infrastructure and Economic Development Bank (“CIEDB”) to ~~minimize~~partially reimburse the Utility for its March and April 2008 purchase of $454 million of auction rate pollution control bonds issued in 2005 (“PC2005 bonds”). The September bonds bear interest at 3.75% through September 19, 2010 and are subject to mandatory tender on September 20, 2010 at a price of 100% of the principal amount plus accrued interest. Each series of October bonds is supported by a direct-pay letter of credit that expires on October 29, 2011, unless extended. The October bonds bear interest at variable interest rates not to exceed 12% per year. The initial interest rate ~~risk arising from~~on the ~~credit downgrade of the bond insurer. The repurchases were financed through a combination of long-term and short-term debt. The Utility holds the PC2005~~October bonds in treasury. The Utility expects that the PC2005 bonds will be resold during 2008, depending on conditions in the tax-exempt bond market and liquidity needs at the Utility. The proceeds will be used to repay short-term debt.

On March 3, 2008, the Utility issued $200 million principal amount of 5.625% 10-year Senior Notes due on November 30, 2017, which increased the outstanding amount of its 5.625% Senior Notes to $700 million. Also on March 3, 2008, the Utility issued $400 million principal amount of 6.35% 30-year Senior Notes due on February 15, 2038. The Utility expects it will incur additional long-term debt ranging from $4.5 billion to $5.1 billion during the remainder of 2008 through 2011 primarily to finance capital expenditures and replace maturing debt.

The amount and timing of the Utility’s future financing needs will depend on various factors, including: (1) the timing and amount of forecasted capital expenditures and any incremental capital expenditures beyond those currently forecasted; (2) the amount of cash internally generated through normal business operations; (3) the timing of the resolution of the Disputed Claims (upon settlement or the conclusion of the FERC and judicial proceedings) and the amount of interest on these claims that the Utility will be required to pay (seewas 1.75%. (See Note 104 of the Notes to the Condensed Consolidated Financial ~~Statements); and (4)~~Statements for a further discussion of these bonds.) The Utility anticipates that the ~~timing~~refinancing of the ~~resale~~remaining $50 million of PC2005 bonds will occur by the end of 2008, subject to conditions in the tax-exempt bond market and the liquidity needs of the ~~PC2005 bonds.~~Utility.

During the ~~six~~nine months ended ~~June~~September 30, 2008, PG&E Corporation issued ~~2,241,807~~4,023,421 shares of common stock upon exercise of employee stock options, for the account of 401(k) participants, and under its Dividend Reinvestment and Stock Purchase Plan, generating approximately ~~$82~~$150 million of cash. In February 2008 and July 2008, PG&E Corporation contributed $50 million and $40 million, respectively, 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. PG&E Corporation expects to issue additional common stock, debt, or other securities, depending on market conditions, to fund a portion of the Utility’s future equity needs.

Dividends

During the ~~six~~nine months ended ~~June~~September 30, 2008, the Utility paid common stock dividends totaling ~~$305~~$447 million, including ~~$284~~$426 million of common stock dividends paid to PG&E Corporation and $21 million of common stock dividends paid to PG&E Holdings, LLC. At December 31, 2007, PG&E Holdings, LLC, a wholly owned subsidiary of the ~~Utility.~~Utility, held approximately 7% of the Utility common stock. Effective August 29, 2008, PG&E Holdings LLC, was dissolved, and the shares subsequently cancelled.

~~On February 22, 2008, PG&E Corporation declared its quarterly dividend at $0.39 per share, an increase of $0.03 per share over the previous level of $0.36 per share.~~ During the ~~six~~nine months ended ~~June~~September 30, 2008, PG&E Corporation paid common stock dividends totaling ~~$284~~$433 million, including ~~$18~~$28 million to ~~its~~Elm Power Corporation. At December 31, 2007, Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, held 24,665,500 shares of PG&E Corporation common stock. Effective August 29, 2008, Elm Power ~~Corporation.~~ Corporation was dissolved, and the shares subsequently cancelled.

On ~~June 18,~~September 17, 2008, the Board of Directors of PG&E Corporation declared a dividend of $0.39 per share, totaling ~~$149~~$140 million, ~~including $10 million to its wholly owned subsidiary, Elm Power Corporation that~~which was paid on ~~July~~October 15, 2008 to shareholders of record on ~~June~~September 30, 2008.

During the ~~six~~nine months ended ~~June~~September 30, 2008, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling $7$10 million. On ~~June 18,~~September 17, 2008, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock payable on ~~August~~November 15, 2008, to preferred shareholders of record on ~~July~~October 31, 2008.

Utility

Operating Activities

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

The Utility's cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 were as follows:

	Six Months Ended						Nine Months Ended
	June 30,						September 30,
(in millions)	2008			2007			2008			2007
Net income	$	549		$	535		$	870		$	818
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction		870			913
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction								1,337			1,417
Deferred income taxes and tax credits, net		316			101			470			(35	)
Other changes in noncurrent assets and liabilities		480			129			55			270
Gain on sale of assets		-			(1	)		(1	)		(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(66	)		143			(179	)		(82	)
Inventories		(57	)		(22	)		(153	)		(92	)
Accounts payable		123			(221	)		(85	)		(315	)
Income taxes receivable/payable		57			(59	)		208			228
Regulatory balancing accounts, net		(351	)		(483	)		(94	)		(238	)
Other current assets		429			271			(125	)		120
Other current liabilities		(73	)		(48	)		(80	)		35
Other		(3	)		(23	)		(3	)		(32	)
Net cash provided by operating activities	$	2,274		$	1,235		$	2,220		$	2,093

In the ~~six~~nine months ended ~~June~~September 30, 2008, net cash provided by operating activities increased by approximately ~~$1,039~~$127 million from the same period in 2007. ~~The~~

In the nine months ended September 30, 2008, net cash provided by operating activities was approximately $2,220 million. For the nine months ended September 30, 2008, net cash provided by operating activities was primarily impacted by net income of $870 million, adjusted for noncash depreciation, amortization, decommissioning and allowance for equity funds used during construction of $1,337 million (see “Results of Operations” above). Additionally, the following changes in ~~financial condition~~operating assets and liabilities positively impacted cash flows during the ~~six months ended June 30, 2008:~~period:

·	~~Increase~~Liabilities for deferred income taxes and tax credits increased by approximately $470 million between December 31, 2007 and September 30, 2008, primarily due to an increase in balancing account revenues and an increase in deductible fixed asset-related book/tax differences based on the 2007 tax return filed in 2008, as well as an increase in balancing account revenues and an increase in deductible tax depreciation as authorized by the 2008 Economic Stimulus Act.

·	Income taxes receivable/payable increased by approximately $208 million between December 31, 2007 and September 30, 2008, primarily due to the accrual of ~~approximately $936 million~~income taxes payable for the first nine months of 2008.

The following changes in operating assets and liabilities negatively impacted cash flows during the period:

·	Net collateral ~~payable~~paid primarily related to price risk management activities increased by approximately $155 million between December 31, 2007 and ~~June~~September 30, 2008 ~~compared with a decrease of approximately $138 million in collateral receivable related to price risk management activities over the same period in 2007~~ as a result of changes in the Utility’s exposure to counterparties’ credit risk. Collateral ~~payable represents cash collected, and collateral receivable represents cash paid, to reduce the Utility’s net credit exposure to price risk management activities. The Utility’s collateral~~ payables and receivables ~~will fluctuate based on~~are included in the Other changes in noncurrent assets and liabilities, Other current assets, and Other current liabilities in the ~~Utility’s net credit exposure, which is primarily dependent on electricity and gas price movement.~~table above.

·	Increase in liabilities of approximately $316 million for deferred income taxes and tax credits between December 31, 2007 and June 30, 2008, compared to approximately $101 million increase over the same period in 2007. Increase in 2008 is primarily due to higher billings to customers and an increase in deductible tax depreciation from the 2008 Economic Stimulus Act with no similar changes for the same period in 2007.

·	~~Increase in~~ Regulatory balancing accounts, net under-collection ofincreased by approximately ~~$351~~$94 million between December 31, 2007 and ~~June~~September 30, 2008, ~~compared with~~primarily due to an increase of approximately ~~$483~~$454 million in under-collected electricity procurement costs. This increase was partially offset by an increase of $172 million in over-collected amounts due to the DWR. (See “Cost of Electricity” above.) The increase in the Regulatory balancing accounts, net under-collection ~~over the same period in 2007. The increase resulted from receipt~~also was partially offset by a refund of aapproximately $230 million ~~refund~~the Utility received from the California Energy Commission (“CEC”)~~, which more than offset the increase in the under-collection resulting from higher than forecasted electricity procurement costs during 2008 (see “Cost of Electricity” above)~~. The funds from the CEC will be refunded to customers in 2009.

·	There were miscellaneous other changes in operating assets and liabilities due to timing differences and seasonality.

In the nine months ended September 30, 2007, net cash provided by operating activities was approximately $2,093 million. For the nine months ended September 30, 2007, net cash provided by operating activities was primarily impacted by net income of $818 million, adjusted for noncash depreciation, amortization, decommissioning and allowance for equity funds used during construction of $1,417 million (see “Results of Operations” above). Additionally, increases of approximately $228 million in income tax payable positively impacted cash flows during the nine month period ending September 30, 2007. The following changes in operating assets and liabilities negatively impacted cash flows during the period:

~~Among~~

·	Accounts payable decreased by approximately $315 million primarily due to differences in the timing of purchases and payments of operating expenses.

·	Regulatory balancing accounts, net over-collection decreased by approximately $238 million between December 31, 2006 and September 30, 2007 primarily due to CPUC-authorized rate reductions designed to reduce the over-collection.

As a result of the resolution of 2001-2004 audits, PG&E Corporation expects to receive a refund of approximately $310 million, excluding interest, in the next several months. Approximately $180 million of the refund will be allocated to the Utility. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of "Tax Matters".) Additionally, future operating cash flow will be impacted by the timing of cash collateral payments and receipts related to price risk management activity, among other ~~factors,~~factors. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure, which is primarily dependent 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 will drive changes in cash provided by or used in operating activities.~~costs. The CPUC has established a balancing account mechanism to adjust the Utility’s electric rates whenever the forecasted aggregate over-collections or under-collections of the Utility’s electric procurement costs for the current year exceed 5% of the Utility's prior year generation revenues, excluding generation revenues for DWR contracts. In accordance with this mechanism, on August 21, 2008, the ~~Utility has requested approval~~CPUC approved the Utility’s request to collect from customers ~~$482 million during~~ the ~~15-month period October 2008 through December 2009 to recover the forecast~~forecasted 2008 end-of-year under-collection of procurement costs, due mainly to ~~rapidly~~ rising natural gas ~~costs.~~costs and lower than forecasted hydroelectric generation. Effective October 1, 2008, customer rates were adjusted to allow the Utility to collect $645 million in procurement costs through December 2009. The ~~forecast~~Utility will be updated in September 2008 for actual recorded under-collections through August 2008. On July 21, 2008, a proposed decision was issued that recommends the Utility’s request be approved. The CPUC is expected to vote on this proposed decision on August 21, 2008. Independent of the balancing account mechanism, on June 10, 2008, the Utility filed its application for recovery ofupdating its forecasted electricity procurement ~~and related~~ costs ~~for 2009. If this request is granted, the Utility will collect an additional approximately $339 million (to be updated~~ in November, ~~2008) over 12 months starting~~for inclusion in the Annual Electric True-Up, which will adjust rates on January 1, 2009.

Investing Activities

The Utility's investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. ~~Year-to-year variances in cash~~Cash used in investing activities ~~depend~~depends primarily upon the amount and type of construction activities, which can be influenced by the need to make electricity and natural gas reliability improvements as well as by storms and other factors.

The Utility's cash flows from investing activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 were as follows:

	Six Months Ended						Nine Months Ended
	June 30,						September 30,
(in millions)	2008			2007			2008			2007
Capital expenditures	$	(1,712	)	$	(1,320	)	$	(2,691	)	$	(2,035	)
Net proceeds from sale of assets		12			8
Proceeds from sale of assets								21			15
Increase in restricted cash		(7	)		(13	)		(3	)		(32	)
Other investing activities		(29	)		(58	)
Proceeds from nuclear decommissioning trust sales								1,121			703
Purchases of nuclear decommissioning trust investments								(1,161	)		(805	)
Net cash used in investing activities	$	(1,736	)	$	(1,383	)	$	(2,713	)	$	(2,154	)

Net cash used in investing activities increased by approximately ~~$353~~$559 million in the ~~six~~nine months ended ~~June~~September 30, 2008 compared to the same period in 2007, primarily due to an increase of approximately ~~$392~~$656 million in capital expenditures for ~~installation of~~installing the SmartMeter™ advanced metering ~~project,~~infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Financing Activities

The Utility’s cash flows from financing activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007 were as follows:

	Six Months Ended						Nine Months Ended
	June 30,						September 30,
(in millions)	2008			2007			2008			2007
Borrowings under accounts receivable facility and working capital facility							$	533		$	600
Repayments under accounts receivable facility and working capital facility	$	(250	)	$	(300	)		(250	)		(300	)
(Repayment) issuance of commercial paper, net discount of $1 million in 2008 and $2 million in 2007		(114	)		109
Net issuance of commercial paper, net of discount of $9 million in 2008 and $2 million in 2007								524			91
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007		598			690			693			690
Long-term debt matured, redeemed, or repurchased		(454	)		-
Long-term debt repurchased								(454	)		-
Rate reduction bonds matured		-			(143	)		-			(217	)
Energy recovery bonds matured		(165	)		(160	)		(260	)		(251	)
Equity infusion		50			200
Equity contribution								90			200
Common stock dividends paid		(284	)		(254	)		(426	)		(381	)
Preferred stock dividends paid		(7	)		(7	)		(10	)		(10	)
Other		16			21			(31	)		29
Net cash (used in) provided by financing activities	$	(610	)	$	156
Net cash provided by financing activities							$	409		$	451

In the ~~six~~nine months ended ~~June~~September 30, 2008, net cash ~~used in~~provided by financing activities ~~increased~~decreased by approximately ~~$766~~$42 million compared to the same period in ~~2007, representing a decreased reliance~~2007. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depends on the level of cash provided by ~~financing~~or used in operating activities ~~due to~~and the ~~increase in~~level of cash provided by ~~operating activities partially offset by the increase in cash~~or used in investing activities. ~~Components of the increase in net cash used in financing activities include the following:~~

·	In an effort to mitigate increasing interest rates as a result of downgrades to the bond issuer’s credit rating and credit issues which impacted the auction rate markets, the Utility repurchased $454 million of PC2005 bonds in March and April 2008. There was no similar repurchase in 2007.

·	Proceeds from the issuance of Senior Notes were approximately $92 million less in the six months ended June 30, 2008 as compared to the same period in 2007. Proceeds from the issuance of Senior Notes were used to repay outstanding commercial paper, for working capital purposes, and to fund capital expenditures.

·	The Utility’s net repayments of commercial paper were approximately $223 million higher in the six months ended June 30, 2008 as compared to the same period in 2007 primarily due to the increases in cash from operations in 2008 as described above.

·	The Utility received an equity infusion of $50 million from PG&E Corporation in February 2008, as compared to $200 million equity infusion during the same period in 2007. Equity infusions are sized to maintain the common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

·	Repayments under the accounts receivable facility and working capital facility were approximately $50 million less for the six months ended June 30, 2008 as compared to the same period in 2007. The accounts receivable facility was terminated in February 2007 in connection with an upsize of the working capital facility, and the full outstanding balance of $300 million was repaid. Only $250 million was drawn on the working capital facility as of December 31, 2007, the balance of which was repaid during the first quarter of 2008.

·	~~The RRBs matured and were fully repaid in December 2007. As a result, there were no debt repayments in 2008 as compared to $143 million in payments for the six months ended June 30, 2007.~~

PG&E Corporation

Operating Activities

PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility for services rendered and payments for employee compensation, and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt.

PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with operating activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007.

Investing Activities

Other than payment of dividends, PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with investing activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007.

Financing Activities

PG&E Corporation's primary sources of financing funds, on a stand-alone basis, are dividends from the Utility, equity issuances, and external financing. PG&E Corporation’s uses of cash, on a stand-alone basis, primarily relate to the payment of common stock dividends and common stock repurchases.

PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with financing activities for the ~~six~~nine months ended ~~June~~September 30, 2008 and 2007.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual obligations and commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of transportation capacity, natural gas and electricity to support customer demand, and the purchase of fuel and transportation to support the Utility's generation activities. In addition to those commitments disclosed in the 2007 Annual Report and those arising from normal business activities, PG&E Corporation and the Utility’s commitments at ~~June~~September 30, 2008 include $200 million of 5.625% Senior Notes due November 30, 2017, ~~and~~ $400

million of 6.35% Senior Notes due February 15, ~~2038.~~2038, and $95 million of pollution control bonds series F and G due on November 1, 2026 and December 1, 2018, respectively.

On October 21, 2008, the Utility issued $600 million of 8.25% Senior Notes due October 15, 2018. In addition, on October 29, 2008, the California Pollution Control Financing Authority and the CIEDB issued $309 million of pollution control bonds series A through D for the benefit of the Utility. These series of bonds have maturities ranging from 2016 through 2026. (See Notes 4, 5, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements and the 2007 Annual Report for further discussion.)

CAPITAL EXPENDITURES

The Utility expects that capital expenditures will total approximately ~~$3.7~~$3.6 billion in 2008. During the ~~six~~nine month period ended ~~June~~September 30, 2008, the Utility incurred capital expenditures of approximately ~~$1.7~~$2.7 billion. (See “Liquidity and Financial Resources – Investing Activities” above.) ~~The~~Depending on conditions in the capital market, the Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and enhance system reliability and customer service, to extend the life of or replace existing infrastructure, to add new infrastructure to meet already authorized growth, and to implement various initiatives designed to achieve operating and cost efficiencies. Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC and TO rate cases. In addition, from time to time, 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 May 15, 2008, the Utility requested that the CPUC approve the Utility’s proposed six-year electric distribution reliability improvement program and authorize the Utility to collect revenues to recover forecasted capital expenditures totaling approximately $2.3 billion and operating and maintenance expenses totaling approximately $43 million over the six-year period beginning on January 1, 2009. The amounts requested are incremental to the revenue requirement already authorized by the CPUC in the Utility’s 2007 GRC. The program includes initiatives that are designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities. The Utility expects that the work performed in the six-year program also would provide additional reliability benefits. The Utility proposes to record program costs and related revenue requirements in a separate balancing account so that the revenue requirement increase would be used only to recover costs associated with the proposed initiatives, and to allow the return of unused amounts to customers. The Utility would seek CPUC review and approval to recover any costs that exceed the CPUC’s authorized amount. For the next GRC in 2011, the Utility would provide forecasts that exclude costs related to the proposed reliability improvements. The Utility would continue to record the program costs and related revenue requirements in the balancing account until the GRC following the completion of this program in 2014.

The CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”) have objected to the Utility’s request. Among other arguments, the DRA and TURN argue that the Utility’s request should be made in a GRC, that it violates the 2007 GRC settlement, and that the revenue requirement authorized in the 2007 GRC fully funds the reasonable amounts the Utility might need to spend on its electric distribution system. They assert that the Utility’s request raises many issues including: the adequacy of the funding levels approved in the 2007 GRC, the reasonableness of the Utility’s reliability efforts in recent years, the availability of other more appropriate sources of funding between rate cases, including savings in other areas of utility operations, the value of increased reliability to the Utility’s customers, and the need for and efficacy of the Utility’s proposed ratemaking. The Utility filed its response on June 30, 2008, reiterating its position that the proposed program does not violate the 2007 GRC settlement, that the Utility is permitted to seek additional revenue outside of a GRC, and that the factual issues the DRA and TURN cite justify the need for hearings on the Utility’s request.

PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility’s request. ~~(See “Regulatory Matters” below~~

SmartMeter ™ Advanced Metering Project Upgrade

The CPUC has previously authorized the Utility to recover approximately $1.4 billion in capital costs in connection with its SmartMeterTM advanced metering project. Of this amount, the Utility has incurred capital expenditures of $504 million through September 30, 2008. The Utility’s request to recover additional expenditures of $572 million, including $463 million of additional capital expenditures to upgrade certain elements of the Utility’s SmartMeterTM program is still pending at the CPUC. On June 30, 2008, the DRA and TURN recommended that the CPUC reject the Utility’s request. In the alternative, the DRA and TURN recommend that the CPUC authorize reduced amounts of $358 million and $324 million, respectively. Neither the DRA nor TURN specified the amount of capital expenditures included in their recommended amounts. On July 23, 2008, the Utility filed a response opposing these recommendations and reaffirming the Utility’s support for ~~more information.~~the requested amounts. A final CPUC decision is expected in December 2008. PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility’s application for additional funds to upgrade its advanced metering system. The Utility has incurred approximately $27 million in capital and expense costs for the upgrade as of October 31, 2008 and may incur approximately $7 million in additional capital and expense costs for the upgrade before the end of the year. If the CPUC does not approve the Utility’s request, the Utility may be unable to recover these costs.

On July 31, 2008, the CPUC adopted a decision requiring the Utility to accelerate the deployment of advanced meters and take action to make “dynamic pricing” available to customers in 2010 and 2011. Dynamic pricing will utilize price signals to encourage efficient energy consumption and cost-effective demand response. To meet this accelerated schedule, the Utility will be required to incur additional costs, including costs to design and implement new software and billing systems to integrate the new advanced metering technology. The CPUC has directed the Utility to request recovery of the additional cost required to implement dynamic pricing. The Utility is developing its estimates of the additional costs it will incur to comply with this decision and expects to file a request for cost recovery with the CPUC in early 2009.

Colusa Power Plant

On June 12, 2008, the CPUC gave its final approval for the Utility to construct the Colusa Project, a 657-megawatt (“MW”) combined cycle generating facility to be located in Colusa County, California after reviewing the final environmental certification issued by the CEC. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008.

The Utility’s recovery of costs related to the Colusa Project is subject to the initial capital cost limits of approximately $673 million and operations and maintenance ratemaking previously approved by the CPUC. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Project will commence operations in 2010.

Humboldt Bay Repowering Project

On September 24, 2008, the CEC issued its final decision authorizing the construction of the Humboldt Bay Repowering Project ("HBRP"), a 163 MW reciprocating engine electric generating facility to be located in Humboldt County at the site of the Utility's existing Humboldt Bay Power Plant. Demolition of existing structures on the site is complete and construction will commence during November 2008. Subject to meeting operational performance requirements and other conditions, it is anticipated that the HBRP will commence operations in 2010.

The Utility’s recovery of costs related to the HBRP is subject to the initial capital cost limits of approximately $239 million and operations and maintenance ratemaking previously approved by the CPUC.

Tesla Generating Station

On October 14, 2008, the Utility filed comments objecting to the proposed decision. The CPUC is expected to issue a final decision by the end of 2008.

Request for New Generation Offers and Potential New Utility-Owned Generation

On July 21, 2008, the Utility received bids from third parties in response to the Utility’s April 1, 2008 long-term RFO for 800 to 1,200 MW of dispatchable and operationally flexible new generation resources to be on-line no later than May 2015. The Utility is evaluating these offers and plans to develop a shortlist of offers during the fourth quarter of 2008. The Utility’s RFO requested both power purchase agreements and purchase and sale agreements. Under a purchase and sale agreement a new generating facility would be constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements.

The Utility conducted a similar RFO in 2004-2005 and, as a result of that process, entered into several power purchase agreements with third parties that are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreement. These agreements were approved by the CPUC in November 2006. Since that time, the development plans for two of the proposed generation facilities have been terminated and the development of a third, the proposed Russell City Energy Center, has been delayed pending CPUC approval of an amendment to the related power purchase agreement.

Proposed Electric Transmission Projects

The Utility has been exploring the feasibility of obtaining regulatory approval for a potential investment in an electric transmission project that would traverse the Pacific Northwest. On April 17, 2008, the FERC granted part of the Utility’s request for a declaratory order to collect transmission rates designed to provide an incentive to the Utility to continue leading the development of the proposed 1,000-mile, ~~500-kV~~500 kilovolt (“kV”) transmission line to run from British Columbia, Canada to Northern California that would provide access to potential new renewable generation resources, improve regional transmission reliability, and provide opportunities for other market participants to use the new facilities. The FERC’s order allows the Utility to recover all prudently incurred pre-commercial costs, such as costs for feasibility studies and surveys, and all prudently incurred development and construction costs if the proposed project is abandoned or cancelled for reasons beyond the Utility’s control. The development and construction of this proposed transmission project remains subject to significant business, financial, regulatory, environmental, and political risks and challenges.

The Utility also has been exploring the development of a new 500-kV electric transmission project, the Central California Clean Energy Transmission line, to increase transmission capacity between northern and southern California and provide needed access to new renewable generation resources. The CAISO has been conducting stakeholder meetings to review the Utility’s proposal and the Utility has been conducting various studies to ensure that the project is designed and located to avoid or minimize potential impacts. Depending on the results of these stakeholder meetings and studies, the Utility will decide whether to request CPUC approval to construct the line.

The Utility cannot predict whether the many conditions and challenges to the development of these proposed electric transmission projects will be met.

Potential Natural Gas Pipeline Projects

PG&E Corporation continues to pursue the development of the proposed 230-mile Pacific Connector Gas Pipeline, along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation. The development of the Pacific Connector Gas Pipeline is dependent upon the development of the Jordan Cove liquefied natural gas terminal by Fort Chicago Partners, L.P. and the satisfaction of other conditions and requirements.

~~Finally,~~ PG&E Corporation also has been exploring potential investments in natural gas transmission pipeline projects, but it has decided not to pursue an investment in El Paso Corporation’s proposed Ruby Pipeline. On April 30, 2008, PG&E Corporation terminated the letter of intent it had entered into in December 2007 with El Paso Corporation to acquire an interest in the proposed Ruby Pipeline. ~~The~~On October 7, 2008, the assigned administrative law judge at the CPUC issued a proposed decision that, if adopted by the CPUC, would grant the Utility ~~will continue~~the authority to ~~seek CPUC approval of its natural gas transportation~~enter into a contract ~~entered into in December 2007,~~ for ~~firm service rights~~long-term capacity on the proposed Ruby Pipeline for a 15-year term commencing in 2011 when the pipeline is proposed to be placed into service.

~~SmartMeter ™ Advanced Metering Project Upgrade~~

~~The CPUC has previously authorized the Utility to recover approximately $1.4 billion in capital costs in connection with its SmartMeter~~TM advanced metering project. Of this amount, the Utility has incurred capital expenditures of $421 million through June 30, 2008. The Utility’s request to recover additional expenditures of $572 million, including $463 million of additional capital expenditures, to upgrade certain elements of the Utility’s SmartMeterTM program is still pending at the CPUC. On June 30, 2008, the DRA and TURN recommended that the CPUC reject the Utility’s request. In the alternative, the DRA and TURN recommend that the CPUC authorize reduced amounts of $358 million and $324 million, respectively. Neither the DRA nor TURN specified the amount of capital expenditures included in their recommended amounts. On July 23, 2008, the Utility filed a response opposing these recommendations and reaffirming the Utility’s support for the requested amounts. A final ~~CPUC~~ decision is expected ~~in December~~on November 6, 2008. The Utility cannot predict whether the CPUC will approve its application for additional funds to upgrade its advance metering system. The Utility expects to incur approximately $19 million in capital costs for the upgrade before the CPUC decision is issued. If the CPUC does not approve the Utility’s request, the Utility may be unable to recover these costs.

~~In addition, on July 31, 2008, the CPUC adopted a decision requiring the Utility to propose various electric rates to implement “dynamic pricing” in 2010 and 2011 to send~~ ~~more dynamic price signals to encourage efficient energy consumption and cost-effective demand response.~~ The decision requires the Utility to accelerate the deployment of advanced meters and take other action to make dynamic pricing available to customers. To meet this accelerated schedule, the Utility will be required to incur additional costs, including costs to design and implement new software and billing systems to integrate the new advanced metering technology. The CPUC has directed the Utility to submit a request for additional funds to recover the Utility’s estimated costs to comply with the CPUC decision. At this time, the Utility is unable to estimate the amount of additional costs it will incur to comply with the decision.

~~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). The CPUC authorized the Utility to recover project costs of up to $706 million from customers without further reasonableness review. If costs exceed this threshold, the CPUC authorized the Utility to recover costs of up to $815 million, subject to a reasonableness review of the full amount. As of June 30, 2008, the Utility has spent approximately $475 million, including progress payments, under contracts for the eight steam generators that the Utility has ordered. The Utility anticipates the future expenditures will be approximately $224 million. The Utility installed four of the new steam generators in Unit 2 during the refueling outage that began in February 2008 and ended in April 2008. The remaining new generators for Unit 1 are expected to be installed in 2009.

~~New Generation Facilities~~

On June 12, 2008, the CPUC gave its final approval for the Utility to construct the Colusa Project, a 657-megawatt (“MW”) combined cycle generating facility to be located in Colusa County, California after reviewing the final environmental certification issued by the CEC. Construction will begin once final environmental permitting is complete.

The Utility’s recovery of costs related to the Colusa Project is subject to the initial capital cost limits and operations and maintenance ratemaking previously approved by the CPUC. Subject to receiving final environmental permits, meeting operational performance requirements and other conditions, it is anticipated that the Colusa Project will commence operations in 2010.

~~Potential New Utility-Owned Generation~~

On July 21, 2008, the Utility received bids from third parties in response to the Utility’s April 1, 2008 request for offers (“RFO”) for 800 to 1,200 MW of dispatchable and operationally flexible generation resources to be on-line no later than May 2015. The Utility is evaluating these offers and currently expects to develop a shortlist of bidders by October 2008. The Utility’s RFO requested both power purchase agreements and purchase and sale agreements. Under a purchase and sale agreement a new generating facility would be constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements.

The Utility has previously entered into several power purchase agreements with third parties that are contingent on the third party’s development of the new generation facility to provide the power to be purchased by the Utility under the

agreement. To the extent that third parties fail to develop the new generation facility due to financial, permitting, or other reasons, the Utility may seek CPUC authorization to develop or acquire new generation facilities to ensure that the Utility is able to meet its customers’ demand. In November 2006, the CPUC approved several power purchase agreements that the Utility entered into with third parties following the Utility’s previous RFO for long-term generation resources to meet its forecasted future need. Some of the generation resource projects to be developed by these third parties have either been terminated or face significant delay or uncertainty. The CPUC also has authorized the development of utility-owned generation outside of the RFO process when there is an attractively priced resource development proposal that presents a unique opportunity or that is needed to meet specific, unique reliability issues and the only means of developing new resources in sufficient time is by utility ownership.

On July 18, 2008, the Utility filed an application requesting that the CPUC authorize the Utility to develop and construct a 560-MW generating unit at the Tesla Generating Station, a proposed combined-cycle power plant to be located in eastern Alameda County, California. On July 17, 2008, the Utility agreed to acquire Midway Power, LLC from its owner, ESI Energy, LLC, to obtain the real property and development rights for the Tesla Generating Station site, subject to certain conditions, including permission from the CEC to transfer the license previously issued by the CEC for the Tesla Generating Station. The CEC issued a license to construct and operate the Tesla Generating Station in 2004 as a 1,120-MW combined-cycle generating facility, utilizing two power trains capable of generating 560 MW each. The acquisition agreement provides the Utility the option to proceed with the development of the second generating unit in the future, subject to CPUC approval. The CEC license to construct and operate the Tesla Generating Station contains certain conditions that must be met to ensure that the project is designed, constructed, and operated in conformity with applicable law. The current CEC permit requires that construction begin by June 2009.

The Utility has requested that the CPUC issue a final decision by January 29, 2009 to authorize the Utility to recover its forecasted initial capital costs of approximately $850 million to construct one of the units. If the actual cost is less, the Utility’s customers would receive the benefit. If the actual cost is higher, the Utility has proposed that it be permitted to recover in rates the $850 million initial capital costs without an after-the-fact reasonableness review and that it be permitted to file an application requesting recovery of the excess costs to the extent that: (1) excess costs result from operational enhancements to the project, or (2) the excess costs are the result of an action or force that was beyond the Utility’s reasonable control, such as permitting delays or changes to the project mandated by regulatory agencies. The Utility also has proposed that it be allowed to pass through to customers any performance incentives it may pay and any penalties it may receive under contracts for construction, engineering, and equipment, to the extent that such payments have not been included in the estimate of initial capital costs.

In order to ensure that the generating unit achieves commercial operation no later than the summer of 2012 when it is needed for reliability purposes, the Utility will enter into various engineering, equipment and supply contracts before the CPUC issues a final decision. The Utility has requested that the CPUC issue an interim order by September 18, 2008, to permit the Utility to recover the termination costs it would incur under these contracts if the CPUC ultimately denies the Utility’s application to develop and construct the generating unit. As of September 18, 2008, the Utility will be responsible for approximately $5 million in termination costs if the interim order is denied. If the interim order is granted, the Utility would be eligible to recover its termination costs, subject only to a review of the reasonableness of its management and administration of the terminated contracts, and will proceed with progress payments under the contracts until a final CPUC decision is reached. The Utility anticipates that termination costs could reach up to $50 million by January 29, 2009, the date the Utility has requested that the CPUC issue its final decision, if the CPUC ultimately denies the Utility’s application. In addition, if the CPUC does not approve the application, the Utility has requested that the CPUC permit the Utility to recover a rate of return on its site acquisition costs until the time that the property is placed in service.

PG&E Corporation and the Utility cannot predict the extent to which any of the RFOs described above will result in Utility-owned generation projects or if the CPUC will approve the Utility’s application to develop the Tesla Generating Station.

OFF-BALANCE SHEET ARRANGEMENTS

For financing and other business purposes, PG&E Corporation and the Utility maintain certain arrangements that are not reflected in their Condensed Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E ~~Corporation's~~Corporation or the Utility's activities or a significant ongoing source of financing. These arrangements enable PG&E Corporation and the Utility to obtain financing or execute commercial transactions on more favorable terms. For further information related to letter of credit agreements and the credit facilities, see the 2007 Annual Report and Note 4 of the Notes to the Condensed Consolidated Financial Statements.

5053

Credit Risk

The Utility conducts business with wholesale customers and counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. If a counterparty failed to perform on its contractual obligation to deliver electricity, then the Utility may find it necessary to procure electricity at current market prices, which may be higher than the contract prices. Credit-related losses attributable to receivables and electric and gas procurement activities from wholesale customers and counterparties are expected to be recoverable from customers through rates and are not expected to have a material impact on net income.

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. ~~Further, the~~The Utility ties many energy contracts to master agreements that require security (referred to as “credit collateral”) in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The following table summarizes the Utility's net credit risk exposure to its wholesale customers and counterparties, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at ~~June~~September 30, 2008 and December 31, 2007:

(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%			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%
June 30, 2008		$	1,462	$ 660	$	802	1	$	111
September 30, 2008											$	378	$ 98	$	281	2	$	159
December 31, 2007		$	311	$ 91	$	220	2	$	111		$	311	$ 91	$	220	2	$	111


(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.	(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.									(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.	(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.									(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.

On September 15, 2008, Lehman Brothers, Inc. filed a petition under Chapter 11 of the U.S. Bankruptcy Code. The Utility's net credit exposure to various Lehman Brothers, Inc. subsidiaries related to price risk management activity was immaterial.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies, ~~that~~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

The Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, the resolution of which may affect PG&E Corporation and the Utility's ~~and PG&E Corporation's~~ results of operations or financial condition.

2008 Cost of Capital Proceeding

On May 29, 2008, the CPUC adopted a uniform three-year cost of capital mechanism in the second phase of the 2008 Cost of Capital proceeding for the Utility and the other two California investor-owned electric utilities that will replace the annual cost of capital proceeding. Under the adopted mechanism, the utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010.

Under the decision, the Utility’s 2008 cost of capital (including an 11.35% ROE) will be maintained through 2010, unless the automatic adjustment mechanism described below is triggered. The Utility’s 2008 capital structure (including a 52% equity component) is authorized through 2010. The decision permits the utilities to apply for an adjustment to either the cost of capital or the capital structure sooner based on extraordinary circumstances.

The cost of capital mechanism uses an interest rate index (the 12-month October through September average of the Moody's Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity.

In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points ~~(the “deadband”~~(“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year. ~~Finally, the~~The 12-month October 2007 through September 2008 average of the Moody's Investors Service utility bond index ~~which triggered~~did not trigger a change in the ~~adjustment, will become the new benchmark.~~authorized cost of debt, preferred stock, or equity for 2009.

Spent Nuclear Fuel Storage Proceeding

As a consequence of the U.S. Department of Energy’s (“DOE”) failure to develop a permanent national repository for spent nuclear fuel and high-level radioactive waste produced by the nation's nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon in on-site storage pools. The Utility believes that the existing spent fuel pools at Diablo Canyon have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. In addition, the Utility is constructing a dry cask storage facility at Diablo Canyon to store spent nuclear fuel.

The construction of this dry cask storage facility, along with modifications to the power plant to support dry cask storage processing, is not expected to be completed until late 2008 with the initial movement of spent nuclear fuel to dry cask storage beginning in June 2009. If the Utility is unable to complete the facility and load spent fuel into the dry cask storage facility by October 2010 for Unit 1 or May 2011 for Unit 2, the Utility would have to curtail or halt operations in the unit until such time as additional safe storage for spent fuel is made available.

On ~~July 1,~~October 23, 2008, the Nuclear Regulatory Commission ("NRC") ~~held~~issued an order rejecting the final contention made by a ~~hearing~~party who had appealed the NRC’s 2004 decision to ~~consider whether~~grant the ~~NRC staff sufficiently addressed the latent health impacts and damage~~Utility a license to ~~property of a potential radiological release in its supplemental environmental assessment report when it decided to issue a permit for~~construct the dry cask storage facility. The ~~NRC’s~~NRC concluded that the NRC staff’s supplemental environmental assessment, ~~had~~which concluded there would be no significant environmental impacts from potential terrorist acts directed at the ~~Diablo Canyon~~ dry cask storage ~~facility. The NRC is expected~~facility, was supported by a reasonable analysis. Any party wishing to ~~issue~~appeal the NRC’s order must file a ~~decision~~notice of appeal within 60 days.

In addition, on ~~this matter~~August 7, 2008, the U.S. Court of Appeals for the Federal Circuit issued an appellate order in the ~~third quarter~~litigation pending against the DOE in which the Utility and other nuclear power plant owners seek to recover costs they incurred to build on-site spent nuclear fuel storage facilities due to the DOE’s delay in constructing a national repository for nuclear waste. In October 2006, the U.S. Court of Federal Claims found that the DOE had breached its contract with the Utility but awarded the Utility only approximately $43 million of the $92 million incurred by the Utility through 2004. In ruling on the Utility’s appeal, the U.S. Court of Appeals for the Federal Circuit reversed the lower court on issues relating to the calculation of damages and ordered the lower court to re-calculate the award. The Utility expects the final award will approximate $89 million for costs incurred through 2004 and that the Utility will recover all of its costs incurred after 2004 to build on-site storage facilities. After the appellate court denied the DOE’s request for an extension of time to file a petition for rehearing, the DOE filed a motion for reconsideration of that order which the appellate court has not yet addressed. On October 30, 2008, the U.S. Court of Federal Claims took notice of the appellate court’s order and requested the parties to file a joint status report and proposed schedule for remand litigation by December 1, 2008. Amounts recovered from the DOE will be credited to customers through rates.

PG&E Corporation and the Utility are unable to predict the outcome of any rehearing petition.

Energy Efficiency Programs and Incentive Ratemaking

~~In January 2008,~~ The schedule adopted by the CPUC ~~directed its~~to review and determine whether the Utility and other California investor-owned utilities are entitled to receive shareholder incentive earnings (or whether they will incur reimbursement obligations) based on the 2006-2007 energy efficiency program accomplishments called for the CPUC’s Energy Division to ~~update certain~~issue updated energy savings assumptions and to verify the utilities’ installation of energy efficiency measures in time for the utilities to submit interim claims in September 2008. As a result of continuing delays in the issuance of the updated savings assumptions and completion of the Energy Division’s verification, on August 15, 2008, the Utility and other investor-owned utilities jointly filed a petition requesting that the CPUC (1) approve the utilities’ interim claims for incentives for 2006-2007 programs based on the utilities’ reports of their accomplishments submitted to the CPUC in February 2008; (2) verify the utilities’ energy savings results for the final true-up claim for the 2006-2008 programs to be ~~used~~submitted in 2010 based on the Energy Division’s measurement and evaluation studies to ~~measure and verify~~be completed in 2010 but use the ~~energy savings achieved~~reported results submitted by the ~~California investor-owned~~ utilities ~~through implementation~~to assess the interim claims in 2008 and 2009; and (3) adopt a schedule allowing the utilities to recognize earnings (or reimbursement obligations) attributable to their claims annually despite possible delays in the CPUC’s process. In the petition the Utility requested the CPUC to approve interim shareholder incentive earnings of ~~their 2006-2008~~$77 million representing 65% of approximately $119 million. Per the adopted mechanism, the remaining 35% ($42 million) would be held back until the completion of evaluation and ~~2009-2011 energy efficiency programs. The original schedule set~~measurement studies for the final true-up claim in 2010.

On November 4, 2008, a proposed decision was issued by the CPUC ~~called~~administrative law judge (“ALJ”) assigned to this proceeding and an alternate proposed decision was issued by the President of the CPUC. The ALJ’s proposed decision recommends that the CPUC deny the petition for modification. If the proposed decision is adopted by the CPUC, the utilities’ interim claims will not be determined until after the Energy Division ~~to complete~~issues its final verification report in January 2009 using recent updates to estimates of energy savings from the energy efficiency measures installed by ~~August 2008 so that~~ the ~~new assumptions could be~~utilities on customer premises. If the proposed decision is adopted and the updated savings estimates are used to assess the ~~utilities’~~2006-2007 program results submitted by the Utility in February 2008, it is unlikely that the Utility would receive any incentive earnings in 2008 or 2009 and the Utility could incur a reimbursement obligation which the Utility estimates could be approximately $14 million.

The alternate proposed decision recommends that the CPUC grant the petition in part and award the Utility interim incentive earnings for 2006-2007 program accomplishments of $59.3 million in 2008 (50% of approximately $119 million) and hold back the remaining 50%. The alternate proposed decision recommends that the interim claims to be submitted in ~~September~~2009 for 2008 ~~for incentives (or reimbursement obligations) based on energy~~program performance be assessed using the recent updated savings ~~achieved in 2006-2007. (Under the interim claim process, 35% of the incentives or reimbursement obligations calculated for each interim claim will~~estimates and be ~~“held back” until completion of measurement studies verifying the actual energy savings for the entire three-year program cycle.) Due to an expected delay in the completion of~~determined after the Energy ~~Division’s~~Division issues a final verification report ~~and following a party’s request for~~on the ~~CPUC to initiate an alternative dispute process,~~2008 program year. If this final verification report is delayed, the ~~CPUC has scheduled a preliminary meeting on August 8, 2008 to explore~~alternate proposed decision would permit the ~~possibility of conducting a facilitated or mediated settlement conference to resolve the utilities’~~2009 interim claims for ~~2006-2007 before~~ the ~~end of 2008.~~

The amount of any shareholder incentives the Utility may receive or the amount of any reimbursement obligations the Utility may incur for 2006-2008, will depend on the form of revised assumptions the CPUC adopts, the level of energy efficiency savings actually achieved over the three-year2008 program ~~cycle, and the amount of the savings attributable~~year to ~~the Utility’s energy efficiency programs~~be based on the ~~revised assumptions and verification results. If the parties are able~~utilities’ reported results, subject to ~~reach~~ a ~~settlement, the terms~~holdback of ~~the settlement, including the~~at least 50%. The total amount of ~~any shareholder~~ incentive ~~or reimbursement obligation,~~claims for the completed three-year program period (2006-2008) would be subject to ~~CPUC approval.~~ verification and adjustment based on the results of the measurement and evaluation studies to be completed in 2010.

It is ~~uncertain whether this alternative dispute process will be successful or whether~~expected that the CPUC will ~~issue a decision by~~consider both of the ~~end of 2008.~~proposed decisions at its December 4, 2008 meeting.

On July 21, 2008, the Utility filed its application seeking CPUC approval of the Utility’s energy efficiency programs and funding of $1.87 billion for the 2009-2011 cycle of energy efficiency programs. The CPUC has authorized bridge funding for the Utility to continue offering its existing programs in 2009 until the CPUC issues its final decision on the 2009-2011 energy efficiency application, which is expected in mid-2009. On July 31, 2008, the CPUC issued a decision indicating that ~~clarified that the~~ energy efficiency savings goals for the 2009-2011 program period will be considered on a gross ~~basis; i.e.~~basis (i.e., without deduction for customer energy savings not directly attributed to utility ~~programs.~~programs). The CPUC also stated that it would review whether it should modify the incentive ratemaking structure due to the transition from net goals to gross goals for the 2009 and beyond program periods. ~~It is expected that that~~On October 30, 2008, the CPUC ~~will issue~~assigned commissioner and the ALJ issued a ~~decision regarding authorization of~~ruling requiring the ~~Utility’s~~Utility and other investor-owned utilities to re-file their proposed 2009-2011 energy efficiency programs by a date no earlier than January 15, 2009, in ~~late 2008 or early 2009.~~order to take into account the recent updated energy savings estimates.

The amount of any shareholder incentives the Utility may receive or(and the amount and timing of any reimbursement obligations the Utility may ~~incur~~incur) for ~~implementation of~~ the 2009-2011 ~~programs~~program cycle will depend on ~~how~~whether the Utility can design 2009-2011 programs that will meet the CPUC’s energy savings goals based on the recently revised estimates of energy savings; whether the CPUC changes the incentive

~~structure, the form of revised energy savings assumptions used to determine the amount of incentives or reimbursement obligation,~~ structure; and the level of energy efficiency savings actually achieved over the three-year program cycle.

Application to Recover Hydroelectric Generation Facility Divestiture Costs

On April 14, 2008, the Utility filed an application with the CPUC requesting authorization to recover approximately $47 million, including $12.2 million of interest, of the costs it incurred in connection with the Utility’s efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken at the direction of the CPUC in preparation for the planned divestiture of the facilities to further the development of a competitive generation market in California. In 2003, the CPUC determined that the amount of these costs at the time, $34.8 million, was reasonable and authorized the Utility to track these costs and seek authorization to recover these costs in the future if the hydroelectric generation facilities were ultimately not divested. The Utility continues to own its hydroelectric generation assets. On May 19, 2008, the DRA filed a protest to the Utility’s application. On ~~June 11,~~August 14, 2008, the ~~CPUC administrative law judge overseeing~~DRA and the ~~proceeding granted~~Utility agreed that the ~~DRA's~~Utility had supported its request ~~to conduct an audit of the Utility’s related accounting records. The audit must be completed by August 6, 2008. The procedural schedule will be set after the audit is reviewed.~~with appropriate and reasonable evidence. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve recovery of these costs.

~~Proposed~~ Electric ~~Distribution Reliability Program (Cornerstone Improvement Program)~~Transmission Owner Rate Cases

On ~~May 15,~~October 22, 2008, the ~~Utility filed~~FERC approved an ~~application requesting that the CPUC (1) approve~~all-party settlement in the Utility’s ~~proposed six-year electric distribution reliability improvement program~~TO rate case that was filed in July 2007. The settlement sets an annual wholesale base transmission revenue requirement of $706 million and ~~(2) authorize~~a retail base transmission revenue requirement of $718 million, effective March 1, 2008. The Utility has been reserving the difference between expected revenues based on rates requested by the Utility in its TO rate application and expected revenues based on rates proposed in the settlement. As a result, the settlement will not impact the Utility’s results of operations or financial condition. The Utility will refund any over –collected amounts to ~~collect revenues~~customers, with interest, through an adjustment to ~~recover forecasted capital expenditures totaling approximately $2.3 billion~~rates in 2010.

Also, on September 30, 2008, the FERC accepted the Utility’s TO rate case that was filed on July 30, 2008 requesting an increase in retail base revenue requirement, to $849 million, and ~~operating and maintenance expenses totaling approximately $43 million over~~an increase in the ~~six-year period beginning January~~Utility’s wholesale base revenue requirement to $838 million. As customary, the FERC suspended the rate increase associated with the requested increase in revenue requirements for five months, until March 1, 2009. The ~~amounts requested are incremental~~increase in rates will be subject to the revenue requirement already authorized by the CPUC in the Utility’s 2007 GRC. The program includes initiatives that are designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities. The Utility expects that the work performed in the six-year program also would provide additional reliability benefits. The Utility proposes to record program costs and related revenue requirements in a separate balancing account so that the revenue requirement increase would be used only to recover costs associated with the proposed initiatives, and to allow the return of unused amounts to customers. The Utility would seek CPUC review andrefund pending final FERC approval to recover any costs that exceed the CPUC’s authorized amount. For the next GRC in 2011, the Utility would provide forecasts that exclude costs related to the proposed reliability improvements. The Utility would continue to record the program costs and related revenue requirements in the balancing account until the GRC following the completion of this program in 2014.

On June 17, 2008, the DRA and TURN filed a joint motion to dismiss the Utility’s application. Among other arguments, the DRA and TURN argue that the Utility’s request should be made in a GRC, that it violates the 2007 GRC settlement, and that the revenue requirement authorized in the 2007 GRC fully funds the reasonable amounts the Utility might need to spend on its electric distribution system. They argue that the Utility’s request raises many issues including: the adequacy of the ~~funding levels approved~~requested increase in the 2007 GRC; the reasonableness of the Utility’s reliability efforts in recent years; the availability of other more appropriate sources of funding between rate cases, including savings in other areas of utility operations; the value of increased reliability to the Utility’s customers; and the need for and efficacy of the Utility’s proposed ratemaking. The Utility filed its response on June 30, 2008, reiterating its position that the proposed program does not violate the 2007 GRC settlement, that the Utility is permitted to seek additional revenue outside of a GRC, and that the factual issues the DRA and TURN cite justify the need for hearings on the Utility’s request. On July 18, 2008, the DRA and TURN filed a reply to the Utility’s response reiterating the arguments made in their motion.

Although the Utility has proposed a schedule that requests the CPUC to issue a final decision on the Utility’s application by December 18, 2008, it is uncertain when the CPUC will act on the application.requirements.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as price risk and interest rate risk. For a comprehensive discussion of PG&E Corporation’s market risk, see the section entitled “Risk Management Activities” in the 2007 Annual Report.

On June 26, 2008, the CPUC approved the Utility’s conformed 2006 Long-Term Procurement Plan and its revised Electricity and Gas Hedging Plan. The revised plan updates the Utility’s planning criteria and need determination over the 10-year period 2007-2016.

Price Risk

Electric Transmission Congestion Rights

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

The Utility has been allocated and has acquired via auction certain CRRs as of ~~June~~September 30, 2008, and anticipates acquiring additional CRRs through the allocation and auction phases prior to the MRTU effective date. Currently, the CAISO is targeting an MRTU implementation date of February 1, 2009. The ~~anticipated MRTU effective~~CAISO Board of Governors will continue to evaluate whether that implementation date ~~has been delayed and a revised date has not yet been disclosed by the CAISO.~~remains feasible as it approaches. During the ~~first~~fourth quarter of ~~2008,~~2007, the Utility participated in an auction to acquire additional firm electricity transmission rights (“FTRs”) in order to hedge its financial risk until the MRTU becomes effective.

The CRRs are accounted for as derivative instruments and are recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets at fair value. On January 1, 2008, the value recorded for CRRs increased by $48 million compared to December 31, 2007 due to the adoption of SFAS No. 157. (See Note 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion.) Changes in the fair value of the CRRs are deferred and recorded in regulatory accounts as they are recoverable through rates.

~~Natural Gas Procurement (Core Customers)~~

The Utility generally enters into physical and financial natural gas commodity contracts from one to twelve months in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased in the monthly and, to a lesser extent, daily spot market to meet such seasonal demand. The Utility's cost of natural gas purchased for its core customers includes costs for the commodity, Canadian and interstate transportation, and intrastate gas transmission and storage. The Utility’s natural gas procurement costs for its core customers are recoverable through the CPIM, and all costs and benefits associated with hedging purchases under the hedging plan approved in 2007 are accounted for outside the CPIM.

On June 26, 2008, the CPUC issued an Order Instituting Rulemaking (“OIR”) to examine the California gas utilities’ gas cost incentive mechanisms and the treatment of hedging costs under those incentive mechanisms for core customers. The OIR will determine whether the utilities’ hedging plans should be incorporated into their incentive mechanisms and whether reexamination of the utilities’ current incentive mechanisms is necessary.

Natural Gas Transportation and Storage

The Utility uses value-at-risk to measure the shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market prices and customer demand. 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 approximately ~~$27~~$31 million at ~~June~~September 30, 2008. The Utility's high, low, and average values-at-risk during the ~~six-months~~nine months ended ~~June~~September 30, 2008 were approximately ~~$30~~$34 million, $17 million, and ~~$23~~$26 million, respectively.

Convertible Subordinated Notes

In accordance with Statement ~~SFAS~~of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), the dividend participation rights of the Convertible Subordinated Notes are considered to be 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. Dividend participation rights are recognized as operating cash flows in PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. Changes in the fair value are recognized (in Other ~~Income, Net)~~income (expense), net) in PG&E Corporation’s Condensed Consolidated Statements of Income as a non-operating expense or income. At ~~June~~September 30, 2008, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately ~~$55~~$49 million, of which ~~$27~~$28 million was classified in Current Liabilities - Other and ~~$28~~$21 million was classified in Noncurrent Liabilities - Other in the accompanying Condensed Consolidated Balance Sheets. At December 31, 2007, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $62 million, of which $25 million was classified ~~as a current liability~~ in Current Liabilities – Other and $37 million was classified ~~as a noncurrent liability~~ in Noncurrent Liabilities – Other in the accompanying Condensed Consolidated Balance Sheets. The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”), resulting in a $6 million increase in fair value. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion of the implementation of SFAS No. 157.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At ~~June~~September 30, 2008, if interest rates changed by 1% for all current variable rate debt issued by PG&E Corporation and the Utility, the change would affect net income for the nine months ended September 30, 2008 by approximately $5$7.1 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, 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 2007 Annual Report. They include:

·	regulatory assets and liabilities;

·	unbilled revenues;

·	environmental remediation liabilities;

·	asset retirement obligations;

·	income taxes; and

·	pension and other postretirement benefits.

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157, (see “New Accounting Policies” below and Note 2 and Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion), which are also considered critical accounting policies. Additionally, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board (“FASB”) Staff Position on Interpretation 39, “Amendment of FASB Interpretation No. 39” ~~(See~~(see Note 2 of the Notes to the Condensed Consolidated Financial Statements for further discussion).

For the period ended ~~June~~September 30, 2008, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and there were no material changes to the important assumptions underlying the critical accounting estimates.

NEW ACCOUNTING POLICIES

Fair Value Measurements

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157. SFAS No. 157 establishes a fair value hierarchy that prioritizes inputs to valuation techniques used to measure fair value. The objective of a fair value measurement is to determine the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. (See Notes 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion on SFAS No. 157.)

Level 3 Instruments at Fair Value

As Level 3 measurements are based on unobservable inputs, significant judgment may be used in the valuation of these instruments. Accordingly, the following table sets forth the fair values of instruments classified as Level 3 within the fair value hierarchy, along with a brief description of the valuation technique for each type of instrument:

~~Level 3 Instruments at Fair Value~~

	Value as of
(in millions)	September 30, 2008			January 1, 2008
Money market investments (held by PG&E Corporation)	$	62		$	-
Nuclear decommissioning trusts		7			8
Price risk management instruments		34			115
Long term disability trust		79			69
Dividend participation rights		(49	)		(68	)
Other		(5	)		(4	)
Total Level 3 Instruments	$	128		$	120

(in millions)
Value as of June 30, 2008

Nuclear Decommissioning Funds $ 7
Price Risk Management Instruments 382
Long Term Disability Trust 95
Dividend Participation Rights (55 )
Other (6 )
Total Level 3 Instruments $ 423

Level 3 fair value measurements represent ~~15%~~approximately 5% of the total net value of all fair value measurements of PG&E Corporation. During the three and ~~six~~nine months ended ~~June~~September 30, 2008, there were no material increases or decreases in Level 3 assets or liabilities resulting from a transfer of assets or liabilities from, or into, Level 1 or Level 2. The majority of these instruments are accounted for in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended, as they are expected to be recovered or refunded through regulated rates. Therefore, changes in the aggregate fair value of these assets and liabilities (including realized and unrealized gains and losses) are recorded within regulatory accounts in the accompanying Condensed Consolidated Balance Sheets with the exception of the dividend participation rights ~~which are held by~~associated with PG&E ~~Corporation.~~Corporation’s Convertible Subordinated Notes. The changes in the fair value of the dividend participation rights are reflected in Other ~~Income, Net~~income (expense), net in PG&E Corporation’s Condensed Consolidated Statements of Income. Additionally, changes in the fair value of the Level 3 ~~Instruments~~instruments did not have a material effect on liquidity and capital resources as of ~~June~~September 30, 2008.

Money Market Investments

PG&E Corporation invests in AAA-rated money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued based on observable inputs such as expected yield and credit quality and are thus classified as Level 1 instruments. Approximately $192 million held in money market funds are recorded as Cash and cash equivalents in PG&E Corporation’s Condensed Consolidated Balance Sheets.

Nuclear Decommissioning ~~Funds~~Trusts and Long Term Disability Trust

The nuclear decommissioning ~~funds~~trusts and the long-term disability trust primarily hold equities, debt securities, mutual funds, and life insurance policies. These instruments are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. ~~Commingled~~The nuclear decommissioning trusts and the long-term disability trust also invest in long-term commingled funds, ~~within these trusts represent the Utility’s shares~~which are funds that consist of ~~certain money market~~assets from several accounts that are intermingled. These commingled funds ~~held. Due to~~have liquidity restrictions and lack of an active market for individual shares of the funds; therefore the trusts’ investments in these ~~money market funds, commingled~~ funds are classified as Level 3. The Level 3 nuclear decommissioning ~~fund~~trust assets ~~did not~~decreased from approximately $8 million at January 1, 2008 to approximately $7 million at September 30, 2008 and no material change ~~significantly~~was noted from June 30, 2008 to September 30, 2008. The decrease of approximately $1 million for the ~~three and six~~nine months ended ~~June~~September 30, ~~2008.~~2008 was primarily due to unrealized losses of these commingled fund investments. The Level 3 long-term disability trust assets increased from approximately $69 million at January 1, 2008 to approximately ~~$95~~$79 million at ~~June~~September 30, 2008. This increase of approximately ~~$26~~$10 million for the nine months ended September 30, 2008 was primarily due to net purchases of commingled fund investments, offset by unrealized losses on these investments. Additionally, the Level 3 long-term disability trust assets decreased from approximately ~~$103 million at March 31, 2008 to~~

~~approximately~~ $95 million at June 30, 2008 to approximately $79 million at September 30, 2008. This decrease of approximately $8$16 million for the three months ended September 30, 2008 was primarily due to ~~sale~~net sales of commingled fund investments and unrealized losses on these investments.

Price Risk Management Instruments

The price risk management instrument category is comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. When necessary, PG&E Corporation and the Utility generally use similar models to value similar instruments. Since the Utility’s contracts are used within the regulatory framework, regulatory accounts are recorded to offset the associated gains and losses of these derivatives, which will be reflected in future rates. The Level 3 price risk management instruments ~~increased~~decreased from approximately $115 million as of January 1, 2008 to approximately ~~$382~~$34 million as of ~~June~~September 30, 2008. This ~~increase~~decrease of approximately ~~$267~~$81 million was primarily due to ~~an increase~~a decrease in commodity prices on ~~June~~September 30, 2008 as compared to January 1, 2008. Additionally, the Level 3 price risk management instruments ~~increased~~decreased from approximately ~~$299~~$382 million as of ~~March 31,~~June 30, 2008 to approximately ~~$382~~$34 million at ~~June~~September 30, 2008. This ~~increase~~decrease of approximately ~~$83~~$348 million was primarily due to ~~an increase~~a decrease in commodity prices on ~~June~~September 30, 2008, as compared to ~~March 31,~~June 30, 2008.

	Value (in millions)
Type of Instrument	September 30, 2008			January 1, 2008
Options (exchange-traded and OTC)	$	32		$	50
Congestion revenue rights, Firm transmission rights, and Demand response		69			61
Swaps and forwards		(221	)		(2	)
Netting and collateral		154			6
Total	$	34		$	115

All options (exchange-traded and OTC) are valued using the Black’s Option Pricing Model and classified as Level 3 measurements primarily due to volatility inputs. The Utility receives implied volatility for options traded on exchanges which may be adjusted to incorporate the specific terms of the Utility’s contracts, such as strike price or location.

CRRs, FTRs, and demand response contracts are new and/or complex instruments that have immature or limited markets. CRRs allow market participants, including ~~LSEs, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. FTRs allow market participants, including LSEs,~~load serving entities, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market ~~prior~~ to be established when MRTU becomes effective. FTRs allow market participants, including load serving entities to hedge both the ~~operation of~~physical and financial risk associated with CAISO-imposed congestion charges until the MRTU ~~day-ahead market.~~becomes effective. Demand response contracts allow market participants, including ~~LSEs,~~load serving entities, to hedge financial risk associated with increased energy prices resulting from increased demand on the electricity grid. As the markets for these instruments have minimal activity, observable inputs may not be available in pricing these instruments. Therefore, the pricing models used to value these instruments often incorporate significant estimates and assumptions that market participants would use in pricing the instrument. Accordingly, they are classified as Level 3 measurements. When available, observable market data is used to calibrate pricing models.

The remaining Level 3 price risk management instruments are OTC derivative instruments that are valued using pricing models based on the net present value of estimated future cash flows based on broker quotations. The Utility receives multiple non-binding broker quotes for certain locations which are generally averaged for valuation purposes. In certain circumstances, broker quotes may be interpolated or ~~dealer quotations. Such~~extrapolated to fit the terms of a contract, such as frequency of settlement or tenor. These instruments are ~~generally~~ classified within Level 3 of the fair value hierarchy.

Dividend Participation Rights

The dividend participation rights ~~component~~ of the Convertible Subordinated Notes ~~is considered to be an~~are embedded derivative ~~instrument~~instruments in accordance with SFAS No. 133 and, therefore, ~~is bifurcated. They~~are bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Balance Sheets. The dividend participation rights are valued based on the net present value of estimated future cash flows using internal estimates of ~~company~~common stock dividends. These rights are recorded ~~in the~~as Current Liabilities-Other and Noncurrent Liabilities-Other ~~financial statement~~ in ~~the~~PG&E Corporation’s Condensed Consolidated ~~Financial Statements.~~Balance Sheets. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion of these instruments.)

Nonperformance Risk

In accordance with SFAS No. 157, PG&E Corporation and the Utility incorporate the risk of nonperformance into the valuation of their fair value measurements. Nonperformance risk adjustments on the Utility’s price risk management instruments are based on current market inputs when available, such as credit default swaps spreads. When such information is not available, internal models may be used. The nonperformance risk adjustment for the net price risk management instruments contributed less than 1% of the value on June 30, 2008 and increased to approximately 1% of the value on September 30, 2008. As the Utility’s contracts are used within the regulatory framework, the nonperformance risk adjustments are recorded to regulatory accounts and do not impact earnings.

See Notes 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion on other new accounting policies.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities - an amendment of ~~FASB~~Financial Accounting Standards Board (“FASB”) Statement No. 133

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging ~~Activities, an~~Activities-an amendment of ~~SFAS~~FASB Statement No. ~~133~~,” or133” (“SFAS No. 161”). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133. An entity is required to provide qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures on fair value amounts of and gains and losses on derivative instruments, and disclosures relating to credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective prospectively for fiscal years beginning after November 15, 2008. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 161.

~~ENVIRONMENTAL MATTERS~~

5760

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 Utility had an undiscounted and gross environmental remediation liability of approximately $538 million at June 30, 2008, and approximately $528 million at December 31, 2007. The $538 million accrued at June 30, 2008 consists of:

·	~~Approximately $221 million for remediation at the Hinkley and Topock natural gas compressor sites;~~

·	~~Approximately $83 million related to remediation at divested generation facilities;~~

·	Approximately $182 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

·	~~Approximately $52 million related to remediation costs for fossil decommissioning sites.~~

Of the approximately $538 million environmental remediation liability, approximately $126 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately $328 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.

The Utility's undiscounted future costs could increase to as much as $895 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The amount of approximately $895 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

The Utility's Diablo Canyon power plant 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. In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued a proposed policy to address once through cooling. The Water Board’s current proposal would require the installation of cooling towers at nuclear facilities by January 1, 2021, unless the installation of cooling towers would conflict with a nuclear safety requirement.

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. In April 2008, the U.S. Supreme Court agreed to review the Second Circuit decision regarding the cost-benefit test and a decision is expected by mid-2009. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, 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 the first quarter of 2008, PG&E Corporation reached a settlement with the Internal Revenue Service (“IRS”) appellate division for tax years 1997-2000. On July 9, 2008, PG&E Corporation was notified that the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) had approved the settlement. This settlement did not result in material changes to the amount of unrecognized tax benefits that PG&E Corporation recorded under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”

On June 20, 2008, PG&E Corporation reached an agreement with the IRS regarding a change in accounting method related to the capitalization of indirect service costs for tax years 2001-2004. This agreement resulted in a $29 million benefit from a reduction in interest expense accrued on unrecognized tax benefits partially offset by a $15 million liability associated with unrecognized state tax benefits, for a net tax benefit of approximately $14 million. On June 27, 2008, PG&E Corporation agreed to a revenue agent report (“RAR”) from the IRS that reflected this agreement and resolved all 2001-2002 audit issues, except a dispute relating to PG&E Corporation’s entitlement to $104 million of synthetic fuel tax credits, which was referred to the IRS appellate division, and all 2003-2004 audit issues. The IRS will forward the RAR to the IRS appellate division, and it will be finalized when PG&E Corporation and the IRS appellate division resolve the issue regarding synthetic fuel tax credits. At that time, the RAR will be submitted to the Joint Committee for approval.

As a result of the anticipated resolution of the 2001-2004 audits as described above, it is reasonably possible that the liability associated with unrecognized tax benefits could decrease in the next 12 months by an amount ranging from $0 to $200 million for PG&E Corporation, of which $0 to $100 million is related to the Utility.

The IRS is currently auditing tax years 2005-2006. PG&E Corporation filed its federal return for tax year 2007 in July 2008. Beginning in tax year 2008, PG&E Corporation began participating in the IRS’ Compliance Assurance Process, a real-time audit process intended to expedite the resolution of issues raised during audits.

Currently, PG&E Corporation has $268 million of federal capital loss carry forwards based on tax returns as filed, primarily resulting from the disposition of NEGT stock in 2004. The majority of the federal capital loss carry forwards, if not used by December 2009, will expire. The settlement of the 2001-2004 audits may result in utilization of a significant portion of the federal capital loss carry forwards. However, because the settlement is subject to the Joint Committee’s approval, PG&E Corporation has not recognized any benefits from the federal capital loss carry forwards.

~~LEGAL MATTERS~~

In accordance with SFAS No. 5, "Accounting for Contingencies," PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs.

The accrued liability for legal matters is included in PG&E Corporation's and the Utility's Current Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately $51 million at June 30, 2008 and approximately $78 million at December 31, 2007.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation 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 the “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 and the Utility's disclosure controls and procedures as of ~~June~~September 30, 2008, PG&E ~~Corporation's~~Corporation and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 (“the Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E ~~Corporation's~~Corporation and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Act is accumulated and communicated to PG&E ~~Corporation’s~~Corporation and the Utility’s management, including PG&E ~~Corporation's~~Corporation and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal controls over financial reporting that occurred during the quarter ended ~~June~~September 30, 2008 that have materially affected, or are reasonably likely to materially affect, PG&E ~~Corporation's~~Corporation or the Utility's internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Solano County District Attorney’s Office

For more information regarding the resolution of this matter, see ~~“Part~~“PART II, Item 1. Legal Proceedings” in PG&E ~~Corporation's~~Corporation and ~~the Utility's~~Pacific Gas and Electric Company’s (“Utility”) combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2008.

ITEM 1A. RISK FACTORS

The discussion of the Utility’s efforts to store spent nuclear fuel appearing in the 2007 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors” under the following caption “The operation and decommissioning of the Utility's nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its insurance or other source, adversely affecting its financial condition, results of operations, and cash flow” is updated as follows to reflect the new date that the Utility expects it will begin loading spent fuel into the dry cask storage facility:

Because the U.S. Department of Energy has failed to develop a permanent national repository for the nation's spent nuclear fuel and high-level radioactive waste produced by the nation's nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon nuclear generating facilities (“Diablo Canyon”) in on-site storage pools. The Utility believes that the existing spent fuel pools at Diablo Canyon have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. The Utility is also constructing a dry cask storage facility at Diablo Canyon to store spent nuclear fuel which it expects to complete by the end of 2008.

Although the Utility expected to begin loading spent nuclear fuel in 2008, the Utility currently expects that the dry cask storage facility and modifications to the power plant to support dry cask storage processing will be completed in late 2008 and that the initial movement of spent nuclear fuel into dry storage will begin in June 2009. If the Utility is unable to complete the facility and load spent fuel into the dry cask storage facility by October 2010 for Unit 1 or May 2011 for Unit 2, the Utility would have to curtail or halt operations of the unit until such time as additional safe storage for spent fuel is made available.

~~In connection with the pending appeal of the 2004 decision by~~On October 23, 2008, the Nuclear Regulatory Commission ("NRC") issued an order rejecting the final contention made by a party who had appealed the NRC’s 2004 decision to grant the Utility a ~~permit~~license to construct the dry cask storage ~~facility,~~facility. The NRC concluded that the NRC ~~held a hearing on July 1, 2008 to consider whether the NRC staff sufficiently addressed the latent health impacts and damage to property of a potential radiological release in its~~staff’s supplemental environmental assessment, ~~report when it decided to issue the permit. The NRC’s supplemental assessment had~~which concluded there would be no significant environmental impacts from potential terrorist acts directed at the ~~Diablo Canyon~~ dry cask storage ~~facility. The NRC is expected~~facility, was supported by a reasonable analysis. Any party wishing to ~~issue~~appeal the NRC’s order must file a ~~decision on this matter in the third quarter~~notice of ~~2008.~~appeal within 60 days.

The discussion ~~of the potential adverse impact of municipalization and other forms of bypass on the Utility are discussed in the 2007 Annual Report~~ under the heading “Management’s Discussion and Analysis of the Financial Condition and Results of Operations –- Risk Factors” in the 2007 Annual Report under the following caption “The Utility ~~faces~~relies on access to the ~~risk of unrecoverable costs if~~capital markets. There can be no assurance that the Utility will be able to successfully finance its ~~customers obtain distribution and transportation services from other providers as a result of municipalization, technological change,~~planned capital expenditures on favorable terms or ~~other forms of bypass.”~~rates” is updated as follows to ~~describe a voter initiative that will appear on~~reflect the ~~City and County of San Francisco’s November 2008 ballot:~~recent events in the financial markets:

~~On July 22, 2008, the Board of Supervisors of the City~~The Utility’s ability to make scheduled principal and ~~County of San Francisco voted to place an initiative~~interest payments, refinance debt, fund operations, deposit collateral in connection with its natural gas and electricity procurement hedging contracts, and make planned capital expenditures, depends on the ~~November 2008 ballot seeking approval~~levels of its operating cash flow and access to ~~amend~~ the ~~city’s charter~~capital markets. Like many companies, the Utility relies on the capital markets to ~~require a study of~~fund its daily operations with commercial paper, and to fund its significant capital expenditure plan with long-term debt and equity. The Utility’s ability to access the capital markets and the costs and ~~benefits~~terms of ~~taking over the electric system~~available financing depend on many factors, including changes in ~~San Francisco. The charter amendment would allow the Board of Supervisors to issue revenue bonds to finance a takeover of~~ the Utility’s ~~facilities~~credit ratings, changes in ~~San Francisco without further voter approval, as~~the federal or state regulatory environment affecting energy companies, volatility in electricity or natural gas prices, and general economic and market conditions. The recent financial distress experienced at major financial institutions has caused significant disruption in the capital markets, particularly in the commercial paper market where short-term rates have increased significantly and access generally has contracted. Long-term debt rates on utility bond issuances also have increased significantly since mid-September and the volume of utility bond issuances has decreased. The longer such conditions persist, the more significant the implications become for the Utility, including the potential that adequate capital is ~~currently required.~~not available to fund the Utility’s operations and planned capital expenditures. If the ~~ballot measure were approved~~Utility is unable, in part or in whole, to fund its operations and planned capital expenditures there could be a material adverse effect on PG&E Corporation and the Board of Supervisors were to move forward with municipalization proceedings, the Utility would be entitled to receive the fair market value of its facilities subject to the takeover, but the valuation issues in any municipalization proceeding would most likely be highly contentious.

If the number of the Utility's customers declines due to municipalization, or other forms of bypass, and the Utility's rates are not adjusted in a timely manner to allow it to fully recover its investment in electricity and natural gas facilities and electricity procurement costs, PG&E Corporation's and the Utility's financial condition,Utility’s results of operations, ~~and~~ cash flows ~~could be materially adversely affected.~~and financial condition.

In addition, if the Utility were unable to access the capital markets, the Utility may need to consider additional options, such as decreasing or suspending dividend payments to PG&E Corporation. PG&E Corporation also would need to consider its alternatives, such as contributing capital to the Utility to enable the Utility to fulfill its obligation to serve. These alternatives would be evaluated in the context of market conditions then-prevailing, prudent financial management, and any applicable regulatory requirements.

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

During the ~~second~~third quarter of 2008, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the ~~second~~third quarter of 2008, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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

~~PG&E Corporation:~~

On ~~May 14,~~July 25, 2008, PG&E Corporation ~~held~~contributed equity of $40 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 ~~annual meeting of shareholders. At the meeting, the shareholders voted as indicated below on the following matters:~~capital expenditures.

~~1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified (included as Item 1 in the proxy statement):~~

For Against Abstain
David R. Andrews 266,235,373 3,047,596 4,268,100
C. Lee Cox 265,271,261 4,056,555 4,223,253
Peter A. Darbee 265,158,877 4,149,574 4,242,618
Maryellen C. Herringer 265,596,437 3,791,112 4,163,520
Richard A. Meserve 225,354,269 43,960,973 4,235,827
Mary S. Metz 264,611,678 4,769,367 4,170,024
Barbara L. Rambo 266,308,879 2,957,106 4,285,084
Barry Lawson Williams 262,704,969 6,523,337 4,322,763

Each director nominee was elected a director of PG&E Corporation. Each director nominee received a majority of the shares represented and voting (excluding abstentions) with respect to the nominee’s election, which shares voting affirmatively also constituted a majority of the required quorum.

~~2. Ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2008 (included as Item 2 in the proxy statement):~~

~~For:~~	~~266,061,878~~
~~Against:~~	~~3,856,499~~
~~Abstain:~~	~~3,632,692~~

This proposal was approved by a majority of the shares represented and voting (excluding abstentions) with respect to this proposal, which shares voting affirmatively also constituted a majority of the required quorum.

~~3. Consideration of a shareholder proposal regarding statement of personal contribution by CEO (included as Item 3 in the proxy statement):~~

~~For:~~	~~11,798,255~~
~~Against:~~	~~218,506,882~~
~~Abstain:~~	~~5,976,209~~
~~Broker non-vote~~ ~~(1)~~:	~~37,269,723~~

This shareholder proposal was not approved, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (excluding abstentions and broker non-votes) with respect to the proposal.

~~4. Consideration of a shareholder proposal regarding shareholder say on executive pay (included as Item 4 in the proxy statement):~~

~~For:~~	~~121,773,318~~
~~Against:~~	~~109,174,157~~
~~Abstain:~~	~~5,333,871~~
~~Broker non-vote~~ ~~(1)~~:	~~37,269,723~~

This shareholder proposal was approved, as the number of shares voting affirmatively on the proposal constituted more than a majority of the shares represented and voting (excluding abstentions and broker non-votes) with respect to the proposal, and also constituted a majority of the required quorum.

~~5. Consideration of a shareholder proposal regarding independent lead director (included as Item 5 in the proxy statement):~~

~~For:~~	~~57,261,504~~
~~Against:~~	~~170,820,904~~
~~Abstain:~~	~~8,198,938~~
~~Broker non-vote~~ ~~(1)~~:	~~37,269,723~~

~~(1)~~ A non-vote occurs when brokers or nominees have voted on some of the matters to be acted on at a meeting, but do not vote on certain other matters because, under the rules of the New York Stock Exchange, they are not allowed to vote on those other matters without instructions from the beneficial owner of the shares. Broker non-votes are counted when determining whether the necessary quorum of shareholders is present or represented at each annual meeting.

~~Pacific Gas and Electric Company:~~

On May 14, 2008, the Utility held its annual meeting of shareholders. Shares of capital stock of the Utility consist of shares of common stock and shares of first preferred stock. As PG&E Corporation and a subsidiary own all of the outstanding shares of common stock, they hold approximately 96% of the combined voting power of the outstanding capital stock of the Utility. PG&E Corporation voted all of its shares of common stock for the nominees named in the 2008 joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2008. The shares of common stock held by the subsidiary were not voted. The balances of the votes shown below were cast by holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters:

~~1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified (included as Item 1 in the proxy statement):~~

For Against Abstain
David R. Andrews 272,294,704 197,831 91,240
C. Lee Cox 272,281,529 197,546 104,700
Peter A. Darbee 272,295,625 186,490 101,660
Maryellen C. Herringer 272,288,492 199,871 95,412
Richard A. Meserve 272,240,567 247,147 96,061
Mary S. Metz 272,274,958 214,048 94,769
William T. Morrow 272,296,059 180,903 106,813
Barbara L. Rambo 272,281,908 205,706 96,161
Barry Lawson Williams 272,274,075 204,658 105,042

Each director nominee was elected a director of Pacific Gas and Electric Company. Each director nominee received a majority of the shares represented and voting (excluding abstentions) with respect to the nominee’s election, which shares voting affirmatively also constituted a majority of the required quorum.

~~2. Ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm for the year 2008 (included as Item 2 in the proxy statement):~~

~~For:~~	~~272,357,765~~
~~Against:~~	~~87,495~~
~~Abstain:~~	~~138,515~~

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility's earnings to fixed charges ratio for the three and ~~six~~nine months ended ~~June~~September 30, 2008 was ~~3.01~~3.33 and ~~2.82,~~2.99, respectively. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three and ~~six~~nine months ended ~~June~~September 30, 2008 was ~~2.96~~3.27 and ~~2.77,~~2.94, respectively. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility's Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility's first preferred stock and its senior notes, respectively.

6362

ITEM 6. EXHIBITS

~~3.1~~4	~~Bylaws of PG&E Corporation, as amended~~Fourth Supplemental Indenture dated as of ~~May 14,~~October 21, 2008 ~~(incorporated by reference~~relating to ~~PG&E Corporation's Quarterly Report on Form 10-Q for~~ the ~~quarter ended March 31, 2008 (File No. 1-12609) Exhibit 3.1)~~

~~3.2~~	~~Bylaws~~Utility’s issuance of ~~Pacific Gas and Electric Company, as amended as~~$600,000,000 aggregate principal amount of ~~May 14, 2008~~its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s ~~Quarterly~~Current Report on Form ~~10-Q for the quarter ended March 31,~~8-K dated October 21, 2008 (File No. 1-2348), Exhibit ~~3.2)~~4.1)

10.110	~~Amendment to January 3, 2007 Restricted Stock~~Separation Agreement between ~~PG&E Corporation and Peter A. Darbee, effective May 9, 2008 (January 3, 2007 Restricted Stock Agreement filed as Exhibit 10.3 to PG&E Corporation’s~~William T. Morrow and Pacific Gas and Electric ~~Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)~~

10.2*	~~Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation~~Company dated ~~May 9,~~July 8, 2008

11	Computation of Earnings Per Common Share

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1**	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

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

6463

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION


CHRISTOPHER P. JOHNS

Christopher P. Johns Senior Vice President, Chief Financial Officer, and Treasurer (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: ~~August~~November 6, 2008

6564

EXHIBIT INDEX

~~3.1~~4	~~Bylaws of PG&E Corporation, as amended~~Fourth Supplemental Indenture dated as of ~~May 14,~~October 21, 2008 ~~(incorporated by reference~~relating to ~~PG&E Corporation's Quarterly Report on Form 10-Q for~~ the ~~quarter ended March 31, 2008 (File No. 1-12609) Exhibit 3.1)~~

~~3.2~~	~~Bylaws~~Utility’s issuance of ~~Pacific Gas and Electric Company, as amended as~~$600,000,000 aggregate principal amount of ~~May 14, 2008~~its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s ~~Quarterly~~Current Report on Form ~~10-Q for the quarter ended March 31,~~8-K dated October 21, 2008 (File No. 1-2348), Exhibit ~~3.2)~~4.1)

10.110	~~Amendment to January 3, 2007 Restricted Stock~~Separation Agreement between ~~PG&E Corporation and Peter A. Darbee, effective May 9, 2008 (January 3, 2007 Restricted Stock Agreement filed as Exhibit 10.3 to PG&E Corporation’s~~William T. Morrow and Pacific Gas and Electric ~~Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)~~

10.2*	~~Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation~~Company dated ~~May 9,~~July 8, 2008

11	Computation of Earnings Per Common Share

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1**	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

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

6665

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
		(Unaudited)							(Unaudited)
		Balance At							Balance At
(in millions, except share amounts)		June 30, 2008			December 31, 2007				September 30, 2008		December 31, 2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings		$	156		$	519			$	1,335	$	519
Long-term debt, classified as current			600			-				600		-
Energy recovery bonds, classified as current			362			354				366		354
Accounts payable:
Trade creditors			1,133			1,067				962		1,067
Disputed claims and customer refunds			1,588			1,629				1,588		1,629
Regulatory balancing accounts			924			673				906		673
Other			388			394				385		394
Interest payable			744			697				708		697
Income taxes payable			12			-				116		-
Deferred income taxes			228			-				156		-
Other			1,926			1,374				1,375		1,374
Total current liabilities			8,061			6,707				8,497		6,707
Noncurrent Liabilities
Long-term debt			7,721			8,171				7,816		8,171
Energy recovery bonds			1,409			1,582				1,310		1,582
Regulatory liabilities			5,185			4,448				4,456		4,448
Asset retirement obligations			1,614			1,579				1,628		1,579
Income taxes payable			230			234				231		234
Deferred income taxes			3,178			3,053				3,383		3,053
Deferred tax credits			96			99				95		99
Other			1,969			1,954				2,071		1,954
Total noncurrent liabilities			21,402			21,120				20,990		21,120
Commitments and Contingencies
Preferred Stock of Subsidiaries			252			252				252		252
Preferred Stock
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued			-			-				-		-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 381,076,783 common and 1,392,583 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007			6,211			6,110
Common stock held by subsidiary, at cost, 24,665,500 shares			(718	)		(718	)
Common stock, no par value, authorized 800,000,000 shares, issued 358,198,735 common and 1,315,818 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007										5,883		6,110
Common stock held by subsidiary, at cost, 24,665,500 shares in 2007										-		(718	)
Reinvested earnings			3,389			3,151				3,238		3,151
Accumulated other comprehensive income			15			10				18		10
Total common shareholders' equity			8,897			8,553				9,139		8,553
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	38,612		$	36,632			$	38,878	$	36,632

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.							See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
		(Unaudited)							(Unaudited)
		Balance At							Balance At
(in millions, except share amounts)		June 30, 2008			December 31, 2007				September 30, 2008		December 31, 2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings		$	156		$	519			$	1,335	$	519
Long-term debt, classified as current			600			-				600		-
Energy recovery bonds, classified as current			362			354				366		354
Accounts payable:
Trade creditors			1,133			1,067				962		1,067
Disputed claims and customer refunds			1,588			1,629				1,588		1,629
Related parties			24			28				33		28
Regulatory balancing accounts			924			673				906		673
Other			373			370				371		370
Interest payable			744			697				701		697
Income taxes payable			42			-				193		-
Deferred income taxes			234			4				161		4
Other			1,740			1,200				1,185		1,200
Total current liabilities			7,920			6,541				8,401		6,541
Noncurrent Liabilities
Long-term debt			7,441			7,891				7,536		7,891
Energy recovery bonds			1,409			1,582				1,310		1,582
Regulatory liabilities			5,185			4,448				4,456		4,448
Asset retirement obligations			1,614			1,579				1,628		1,579
Income taxes payable			82			103				82		103
Deferred income taxes			3,214			3,104				3,421		3,104
Deferred tax credits			96			99				95		99
Other			1,863			1,838				1,974		1,838
Total noncurrent liabilities			20,904			20,644				20,502		20,644
Commitments and Contingencies
Shareholders' Equity
Preferred stock without mandatory redemption provisions:
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares			145			145				145		145
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares			113			113				113		113
Common stock, $5 par value, authorized 800,000,000 shares, issued 283,856,022 shares in 2008 and issued 282,916,485 shares in 2007			1,419			1,415
Common stock held by subsidiary, at cost, 19,481,213 shares			(475	)		(475	)
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2008 and issued 282,916,485 shares in 2007										1,322		1,415
Common stock held by subsidiary, at cost, 19,481,213 shares in 2007										-		(475	)
Additional paid-in capital			2,269			2,220				2,150		2,220
Reinvested earnings			5,952			5,694				5,910		5,694
Accumulated other comprehensive income			18			13				21		13
Total shareholders' equity			9,441			9,125				9,661		9,125
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	38,265		$	36,310			$	38,564	$	36,310

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.							See accompanying Notes to the Condensed Consolidated Financial Statements.

(in millions)
2008	$	1,526	$	565
2009		2,877		2,384
2010		2,653		2,345
2011		2,609		2,309
2012		2,481		2,231
Thereafter		19,924		18,639
Total	$	32,070	$	28,473

	PG&E Corporation				Utility
	Six Months Ended June 30,				Six Months Ended June 30,
(in millions)	2008		2007		2008		2007
Stock options	$	1	$	4	$	1	$	2
Restricted stock		14		13		9		8
Performance shares		6		-		3		(1	)
Total compensation expense (pre-tax)	$	21	$	17	$	13	$	9
Total compensation expense (after-tax)	$	12	$	10	$	8	$	5

	Pension Benefits Six Months Ended June 30,						Other Benefits Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost for benefits earned	$	118		$	118		$	15		$	14
Interest cost		287			270			40			40
Expected return on plan assets		(349	)		(354	)		(47	)		(48	)
Amortization of transition obligation (1)		-			-			12			12
Amortization of prior service cost (1)		24			24			8			8
Amortization of unrecognized gain (1)		-			-			(8	)		(6	)
Net periodic benefit cost	$	80		$	58		$	20		$	20


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

	Three Months Ended				Six Months Ended				Receivable (Payable) Balance Outstanding at				Three Months Ended				Nine Months Ended
	June 30,				June 30,				June 30,		December		September 30,				September 30,
(in millions)	2008		2007		2008		2007		2008		2007		2008		2007		2008		2007
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1	$	2	$	2	$	-	$	2	$	-	$	1	$	2	$	3
Utility employee benefit assets due from PG&E Corporation		-		-		-		-		27		27		-		-		-		-
Interest from PG&E Corporation on employee benefit assets		-		1		-		1		-		-		-		-		-		1
Utility expenses from:
Administrative services received from PG&E Corporation													$	34	$	31	$	86	$	83
Utility employee benefit assets due to PG&E Corporation														1		1		2		3

(in millions)
Balance at December 31, 2007	$	30		$	30
Additional severance accrued		15			17
Less: Payments		(13	)		(18	)
Balance at June 30, 2008	$	32
Balance at September 30, 2008				$	29

~~Earnings for the period were impacted by a $1 million unrealized gain relating to assets or liabilities still held at the reporting date.~~

~~(1)~~ ~~Excludes taxes on appreciation of investment value and cash and cash equivalents.~~