
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)

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

For the quarterly period ended ~~September 30, 2008~~March 31, 2009 OR

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

For the transition period from ___________ to __________

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

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

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

Pacific Gas and Electric Company (415) 973-7000				PG&E Corporation (415) 267-7000
~~Registrant's~~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~~has been subject to such filing requirements for the past 90 days. [X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). * [ ] Yes [ ] No * The registrant has not yet been phased into the interactive data requirements

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”,~~filer,” “accelerated ~~filer”,~~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~~issuer’s classes of common stock, as of the latest practicable date.

Common Stock Outstanding as of ~~October 31, 2008:~~May 1, 2009:

PG&E Corporation				~~360,983,933~~368,363,541
Pacific Gas and Electric Company				264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER 30, 2008~~MARCH 31, 2009

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		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	1211
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	1415
	NOTE 4:		Debt	1718
	NOTE 5:		~~Shareholders'~~ Equity	1918
	NOTE 6:		Earnings Per Common Share	2019
	NOTE 7:		Derivatives and Hedging Activities	2120
	NOTE 8:		Fair Value Measurements	2224
	NOTE 9:		Related Party Agreements and Transactions	2726
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	2826
	NOTE 11:		Commitments and Contingencies	2927

ITEM 2.	~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			3633
	Forward-Looking Statements			3835
	Results of Operations			3936
	Liquidity and Financial Resources			4642
	Contractual Commitments			5146
	Capital Expenditures			5146
	Off-Balance Sheet Arrangements			5347
	Contingencies			5447
	Regulatory Matters			5447
	Risk Management Activities			5647
	Critical Accounting Policies			5849
	New Accounting Policies			5850
	Accounting Pronouncements Issued But Not Yet Adopted			6051

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			6152
ITEM 4.	CONTROLS AND PROCEDURES			6152

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			6253
ITEM 1A.	RISK FACTORS			6253
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			6253
ITEM 5.	OTHER INFORMATION			6254
ITEM 6.	EXHIBITS			6355

PART I. FINANCIAL INFORMATION

ITEM 1: 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						Nine Months Ended							Three Months Ended
		September 30,						September 30,							March 31,
(in millions, except per share amounts)		2008			2007			2008			2007				2009			2008
Operating Revenues
Electric		$	2,880		$	2,574		$	8,039		$	7,107			$	2,426		$	2,514
Natural gas			794			705			2,946			2,714				1,005			1,219
Total operating revenues			3,674			3,279			10,985			9,821				3,431			3,733
Operating Expenses
Cost of electricity			1,282			998			3,406			2,606				883			1,027
Cost of natural gas			351			281			1,613			1,431				557			775
Operating and maintenance			983			953			3,010			2,794				1,059			1,036
Depreciation, amortization, and decommissioning			419			465			1,240			1,325				419			402
Total operating expenses			3,035			2,697			9,269			8,156				2,918			3,240
Operating Income			639			582			1,716			1,665				513			493
Interest income			23			36			82			125				9			26
Interest expense			(178	)		(196	)		(550	)		(571	)			(181	)		(187	)
Other income (expense), net			(17	)		7			(14	)		22
Other income, net																18			5
Income Before Income Taxes			467			429			1,234			1,241				359			337
Income tax provision			163			151			413			438				115			110
Net Income		$	304		$	278		$	821		$	803				244			227
Preferred dividend requirement of subsidiary																3			3
Income Available for Common Shareholders															$	241		$	224
Weighted Average Common Shares Outstanding, Basic			357			352			356			350				364			355
Weighted Average Common Shares Outstanding, Diluted			358			353			357			352				366			356
Net Earnings Per Common Share, Basic		$	0.83		$	0.77		$	2.25		$	2.23			$	0.65		$	0.62
Net Earnings Per Common Share, Diluted		$	0.83		$	0.77		$	2.24		$	2.22			$	0.65		$	0.62
Dividends Declared Per Common Share		$	0.39		$	0.36		$	1.17		$	1.08			$	0.42		$	0.39

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

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	(Unaudited)						(Unaudited)
	Balance At						Balance At
(in millions)	September 30, 2008			December 31, 2007			March 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	251		$	345		$	271		$	219
Restricted cash		1,325			1,297			1,284			1,290
Accounts receivable:
Customers (net of allowance for doubtful accounts of $75 million in 2008 and $58 million in 2007)		2,530			2,349
Customers (net of allowance for doubtful accounts of $87 million in 2009 and $76 million in 2008)								1,490			1,751
Accrued unbilled revenue								645			685
Regulatory balancing accounts		1,117			771			1,372			1,197
Inventories:
Gas stored underground and fuel oil		333			205			62			232
Materials and supplies		172			166			195			191
Income taxes receivable		-			61			45			120
Prepaid expenses and other		580			255			833			718
Total current assets		6,308			5,449			6,197			6,403
Property, Plant, and Equipment
Electric		27,146			25,599			28,730			27,638
Gas		10,016			9,620			10,241			10,155
Construction work in progress		1,668			1,348			1,644			2,023
Other		16			17			17			17
Total property, plant, and equipment		38,846			36,584			40,632			39,833
Accumulated depreciation		(13,422	)		(12,928	)		(13,709	)		(13,572	)
Net property, plant, and equipment		25,424			23,656			26,923			26,261
Other Noncurrent Assets
Regulatory assets		4,233			4,459			6,087			5,996
Nuclear decommissioning funds		1,819			1,979			1,634			1,718
Other		1,094			1,089			494			482
Total other noncurrent assets		7,146			7,527			8,215			8,196
TOTAL ASSETS	$	38,878		$	36,632		$	41,335		$	40,860

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)
	Balance At
(in millions, except share amounts)	March 31, 2009			December 31, 2008
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	385		$	287
Long-term debt, classified as current		-			600
Energy recovery bonds, classified as current		374			370
Accounts payable:
Trade creditors		839			1,096
Disputed claims and customer refunds		1,552			1,580
Regulatory balancing accounts		727			730
Other		408			343
Interest payable		778			802
Income taxes payable		134			-
Deferred income taxes		389			251
Other		1,364			1,567
Total current liabilities		6,950			7,626
Noncurrent Liabilities
Long-term debt		10,185			9,321
Energy recovery bonds		1,120			1,213
Regulatory liabilities		3,770			3,657
Pension and other postretirement benefits		2,133			2,088
Asset retirement obligations		1,530			1,684
Income taxes payable		36			35
Deferred income taxes		3,496			3,397
Deferred tax credits		92			94
Other		2,161			2,116
Total noncurrent liabilities		24,523			23,605
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		-			-
Common stock, no par value, authorized 800,000,000 shares, issued 366,336,769 common and 683,656 restricted shares in 2009 and issued 361,059,116 common and 1,287,569 restricted shares in 2008		6,123			5,984
Reinvested earnings		3,701			3,614
Accumulated other comprehensive loss		(214	)		(221	)
Total shareholders’ equity		9,610			9,377
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		9,862			9,629
TOTAL LIABILITIES AND EQUITY	$	41,335		$	40,860

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

Balance At

(in millions, except share amounts)
September 30,
2008

December 31, 2007

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings $ 1,335 $ 519
Long-term debt, classified as current 600 -
Energy recovery bonds, classified as current 366 354
Accounts payable:
Trade creditors 962 1,067
Disputed claims and customer refunds 1,588 1,629
Regulatory balancing accounts 906 673
Other 385 394
Interest payable 708 697
Income taxes payable 116 -
Deferred income taxes 156 -
Other 1,375 1,374
Total current liabilities 8,497 6,707
Noncurrent Liabilities
Long-term debt 7,816 8,171
Energy recovery bonds 1,310 1,582
Regulatory liabilities 4,456 4,448
Asset retirement obligations 1,628 1,579
Income taxes payable 231 234
Deferred income taxes 3,383 3,053
Deferred tax credits 95 99
Other 2,071 1,954
Total noncurrent liabilities 20,990 21,120
Commitments and Contingencies
Preferred Stock of Subsidiaries 252 252
Preferred Stock
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued - -
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 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 3,238 3,151
Accumulated other comprehensive income 18 10
Total common shareholders' equity 9,139 8,553
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 38,878 $ 36,632

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

PG&E CORPORATION	PG&E CORPORATION							PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS							CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
		(Unaudited)							(Unaudited)
		Nine Months Ended							Three Months Ended
		September 30,							March 31,
(in millions)		2008			2007				2009			2008
Cash Flows From Operating Activities
Cash Flows from Operating Activities
Net income		$	821		$	803			$	244		$	227
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction			1,337			1,419
Depreciation, amortization, and decommissioning										463			437
Allowance for equity funds used during construction										(25	)		(20	)
Deferred income taxes and tax credits, net			482			(33	)			235			167
Other changes in noncurrent assets and liabilities			87			281				(51	)		111
Gain on sale of assets			(1	)		(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable			(181	)		(80	)			301			89
Inventories			(153	)		(92	)			166			107
Accounts payable			(100	)		(322	)			(116	)		144
Income taxes receivable/payable			177			234				209			(37	)
Regulatory balancing accounts, net			(94	)		(238	)			(180	)		(356	)
Other current assets			(123	)		120				32			103
Other current liabilities			(68	)		19				(390	)		68
Other			(2	)		(32	)			2			(2	)
Net cash provided by operating activities			2,182			2,078				890			1,038
Cash Flows From Investing Activities
Cash Flows from Investing Activities
Capital expenditures			(2,691	)		(2,035	)			(1,079	)		(853	)
Proceeds from sale of assets			21			15				2			6
Increase in restricted cash			(3	)		(32	)
Decrease in restricted cash										11			2
Proceeds from nuclear decommissioning trust sales			1,121			703				387			164
Purchases of nuclear decommissioning trust investments			(1,161	)		(805	)			(412	)		(117	)
Money market investments (see Note 8)			(62	)		-
Other										5			-
Net cash used in investing activities			(2,775	)		(2,l54	)			(1,086	)		(798	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility			533			600
Repayments under accounts receivable facility and working capital facility			(250	)		(300	)
Net issuance of commercial paper, net of $9 million discount 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			693			690
Long-term debt repurchased			(454	)		-
Rate reduction bonds matured			-			(217	)
Cash Flows from Financing Activities
Net repayments under revolving credit facility										-			(250	)
Net issuance (repayments) of commercial paper, net of discount of $2 million in 2009 and $1 million in 2008										96			(198	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $16 million in 2009 and $2 million in 2008										884			598
Long-term debt matured or repurchased										(600	)		(300	)
Energy recovery bonds matured			(260	)		(251	)			(89	)		(83	)
Common stock issued			150			120				96			39
Common stock dividends paid			(406	)		(367	)			(138	)		(129	)
Other			(31	)		38				(1	)		(9	)
Net cash provided by financing activities			499			404
Net cash provided by (used in) financing activities										248			(332	)
Net change in cash and cash equivalents			(94	)		328				52			(92	)
Cash and cash equivalents at January 1			345			456				219			345
Cash and cash equivalents at September 30		$	251		$	784
Cash and cash equivalents at March 31									$	271		$	253

Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)		$	449		$	443
Income taxes paid (refunded), net			(146	)		307
Cash (paid) received for:
Interest, net of amounts capitalized									$	(190	)	$	(189	)
Income taxes, net										294			-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$	140		$	127			$	154		$	139
Capital expenditures financed through accounts payable			224			170				235			242
Noncash common stock issuances										33			6

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	PACIFIC GAS AND ELECTRIC COMPANY													PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	CONDENSED CONSOLIDATED STATEMENTS OF INCOME													CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		(Unaudited)													(Unaudited)
		Three Months Ended						Nine Months Ended							Three Months Ended
		September 30,						September 30,							March 31,
(in millions)		2008			2007			2008			2007				2009			2008
Operating Revenues
Electric		$	2,880		$	2,574		$	8,039		$	7,107			$	2,426		$	2,514
Natural gas			794			705			2,946			2,714				1,005			1,219
Total operating revenues			3,674			3,279			10,985			9,821				3,431			3,733
Operating Expenses
Cost of electricity			1,282			998			3,406			2,606				883			1,027
Cost of natural gas			351			281			1,613			1,431				557			775
Operating and maintenance			982			950			3,009			2,788				1,059			1,036
Depreciation, amortization, and decommissioning			419			465			1,239			1,325				419			402
Total operating expenses			3,034			2,694			9,267			8,150				2,918			3,240
Operating Income			640			585			1,718			1,671				513			493
Interest income			20			33			77			116				9			24
Interest expense			(170	)		(189	)		(528	)		(549	)			(173	)		(180	)
Other income (expense), net			(2	)		13			24			38
Other income, net																21			19
Income Before Income Taxes			488			442			1,291			1,276				370			356
Income tax provision			167			159			421			458				131			120
Net Income			321			283			870			818				239			236
Preferred stock dividend requirement			3			4			10			10
Income Available for Common Stock		$	318		$	279		$	860		$	808
Preferred dividend requirement																3			3
Income Available for Common Shareholders															$	236		$	233

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

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	(Unaudited)						(Unaudited)
	Balance At						Balance At
(in millions)	September 30, 2008			December 31, 2007			March 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	57		$	141		$	54		$	52
Restricted cash		1,325			1,297			1,284			1,290
Accounts receivable:
Customers (net of allowance for doubtful accounts of $75 million in 2008 and $58 million in 2007)		2,530			2,349
Customers (net of allowance for doubtful accounts of $87 million in 2009 and $76 million in 2008)								1,490			1,751
Accrued unbilled revenue								645			685
Related parties		-			6			5			2
Regulatory balancing accounts		1,117			771			1,372			1,197
Inventories:
Gas stored underground and fuel oil		333			205			62			232
Materials and supplies		172			166			195			191
Income taxes receivable		-			15			21			25
Prepaid expenses and other		517			252			823			705
Total current assets		6,051			5,202			5,951			6,130
Property, Plant, and Equipment
Electric		27,146			25,599			28,730			27,638
Gas		10,016			9,620			10,241			10,155
Construction work in progress		1,668			1,348			1,644			2,023
Total property, plant, and equipment		38,830			36,567			40,615			39,816
Accumulated depreciation		(13,407	)		(12,913	)		(13,693	)		(13,557	)
Net property, plant, and equipment		25,423			23,654			26,922			26,259
Other Noncurrent Assets
Regulatory assets		4,233			4,459			6,087			5,996
Nuclear decommissioning funds		1,819			1,979			1,634			1,718
Related parties receivable		27			23			26			27
Other		1,011			993			423			407
Total other noncurrent assets		7,090			7,454			8,170			8,148
TOTAL ASSETS	$	38,564		$	36,310		$	41,043		$	40,537

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

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	(Unaudited)					(Unaudited)
	Balance At					Balance At
(in millions, except share amounts)	September 30, 2008		December 31, 2007			March 31, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS' EQUITY
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	1,335	$	519		$	385		$	287
Long-term debt, classified as current		600		-			-			600
Energy recovery bonds, classified as current		366		354			374			370
Accounts payable:
Trade creditors		962		1,067			839			1,096
Disputed claims and customer refunds		1,588		1,629			1,552			1,580
Related parties		33		28			19			25
Regulatory balancing accounts		906		673			727			730
Other		371		370			405			325
Interest payable		701		697			771			802
Income taxes payable		193		-
Income tax payable							144			53
Deferred income taxes		161		4			396			257
Other		1,185		1,200			1,169			1,371
Total current liabilities		8,401		6,541			6,781			7,496
Noncurrent Liabilities
Long-term debt		7,536		7,891			9,585			9,041
Energy recovery bonds		1,310		1,582			1,120			1,213
Regulatory liabilities		4,456		4,448			3,770			3,657
Pension and other postretirement benefits							2,084			2,040
Asset retirement obligations		1,628		1,579			1,530			1,684
Income taxes payable		82		103			12			12
Deferred income taxes		3,421		3,104			3,546			3,449
Deferred tax credits		95		99			92			94
Other		1,974		1,838			2,119			2,064
Total noncurrent liabilities		20,502		20,644			23,858			23,254
Commitments and Contingencies
Shareholders' Equity
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 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	)
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2009 and 2008							1,322			1,322
Additional paid-in capital		2,150		2,220			2,861			2,331
Reinvested earnings		5,910		5,694			6,172			6,092
Accumulated other comprehensive income		21		13
Total shareholders' equity		9,661		9,125
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	38,564	$	36,310

See accompanying Notes to the Condensed Consolidated Financial Statements.
Accumulated other comprehensive loss							(209	)		(216	)
Total shareholders’ equity							10,404			9,787
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY						$	41,043		$	40,537

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY	PACIFIC GAS AND ELECTRIC COMPANY							PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS							CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
		(Unaudited)							(Unaudited)
		Nine Months Ended							Three Months Ended
		September 30,							March 31,
(in millions)		2008			2007				2009			2008
Cash Flows From Operating Activities
Cash Flows from Operating Activities
Net income		$	870		$	818			$	239		$	236
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction			1,337			1,417
Depreciation, amortization, and decommissioning										456			437
Allowance for equity funds used during construction										(25	)		(20	)
Deferred income taxes and tax credits, net			470			(35	)			234			160
Other changes in noncurrent assets and liabilities			55			270				(48	)		106
Gain on sale of assets			(1	)		(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable			(179	)		(82	)			298			88
Inventories			(153	)		(92	)			166			107
Accounts payable			(85	)		(315	)			(107	)		149
Income taxes receivable/payable			208			228				95			(20	)
Regulatory balancing accounts, net			(94	)		(238	)			(180	)		(356	)
Other current assets			(125	)		120				34			104
Other current liabilities			(80	)		35				(386	)		65
Other			(3	)		(32	)			1			(2	)
Net cash provided by operating activities			2,220			2,093				777			1,054
Cash Flows From Investing Activities
Cash Flows from Investing Activities
Capital expenditures			(2,691	)		(2,035	)			(1,079	)		(853	)
Proceeds from sale of assets			21			15				2			6
Increase in restricted cash			(3	)		(32	)
Decrease in restricted cash										11			2
Proceeds from nuclear decommissioning trust sales			1,121			703				387			164
Purchases of nuclear decommissioning trust investments			(1,161	)		(805	)			(412	)		(117	)
Net cash used in investing activities			(2,713	)		(2,154	)			(1,091	)		(798	)
Cash Flows From Financing Activities
Borrowings under accounts receivable facility and working capital facility			533			600
Repayments under accounts receivable facility and working capital facility			(250	)		(300	)
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			693			690
Long-term debt repurchased			(454	)		-
Rate reduction bonds matured			-			(217	)
Cash Flows from Financing Activities
Net repayments under revolving credit facility										-			(250	)
Net issuance (repayments) of commercial paper, net of discount of $2 million in 2009 and $1 million in 2008										96			(198	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008										538			598
Long-term debt matured or repurchased										(600	)		(300	)
Energy recovery bonds matured			(260	)		(251	)			(89	)		(83	)
Preferred stock dividends paid										(3	)		(3	)
Common stock dividends paid										(156	)		(142	)
Equity contribution			90			200				528			50
Common stock dividends paid			(426	)		(381	)
Preferred stock dividends paid			(10	)		(10	)
Other			(31	)		29				2			(7	)
Net cash provided by financing activities			409			451
Net cash provided by (used in) financing activities										316			(335	)
Net change in cash and cash equivalents			(84	)		390				2			(79	)
Cash and cash equivalents at January 1			141			70				52			141
Cash and cash equivalents at September 30		$	57		$	460
Cash and cash equivalents at March 31									$	54		$	62

Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)		$	436		$	416
Income taxes paid (refunded), net			(138	)		403
Cash (paid) received for:
Interest, net of amounts capitalized									$	(190	)	$	(189	)
Income taxes, net										163			-
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$	224		$	170			$	235		$	242

See accompanying Notes to the Condensed Consolidated Financial Statements.

See accompanying Notes to the Condensed Consolidated Financial Statements.

~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)~~

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility is primarily regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”).

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E ~~Corporation's~~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~~Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries ~~that~~as well as the ~~Utility is required to consolidate under applicable accounting standards and~~accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles ~~generally accepted~~ in the United States of America (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition and results of operations for the periods presented. The information at December 31, ~~2007~~2008 in both PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined Annual Report on Form 10-K for the year ended December 31, ~~2007.~~2008. PG&E ~~Corporation~~Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, ~~2007,~~2008, together with the information incorporated by reference into such report, is referred to in this Quarterly Report on Form 10-Q as the ~~“2007~~“2008 Annual Report.”

Except for the new and significant accounting policies described in Note 2 below, the accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the ~~2007~~2008 Annual Report.

The preparation of financial statements in conformity with GAAP requires management to make estimates and ~~assumptions. These estimates and~~ assumptions affect the reported amounts of revenues, expenses, assets and liabilities, the disclosure of contingencies, and include, but are not limited to, estimates and assumptions used in determining the Utility's regulatory asset and liability balances based on probability assessments of regulatory recovery, revenues earned but not yet billed, 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~~predict. Some of the more critical estimates and assumptions, discussed further below in these ~~estimates. PG&E Corporation~~notes, relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the ~~Utility's~~ Condensed Consolidated Financial Statements ~~reflect all adjustments management believes~~ are ~~necessary for~~appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the ~~fair presentation of their~~Utility’s financial condition and results of operations ~~for~~during the ~~periods presented. Interim~~ period ~~results of operations are not necessarily indicative of the results of operations for the full year.~~in which such change occurred.

This quarterly report should be read in conjunction with PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s audited Consolidated Financial Statements and Notes to the Consolidated Financial Statements in the ~~2007~~2008 Annual Report.

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

~~Fair Value Measurements~~Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133

~~On January 1,~~In March 2008, ~~PG&E Corporation~~the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends and expands the ~~Utility adopted the provisions~~disclosure requirements of SFAS No. ~~157, which defines fair value, establishes criteria when measuring fair value,~~133, “Accounting for Derivative Instruments and ~~expands~~Hedging Activities” (“SFAS No. 133”). SFAS No. 161 requires an entity to provide qualitative disclosures about ~~fair value measurements. SFAS No. 157 defines fair value as “the price~~its objectives and strategies for using derivative instruments and quantitative disclosures 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 determinedetail the fair value amounts of, ~~an asset or liability based~~and gains and losses on, ~~the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. Additionally,~~derivative instruments. SFAS No. ~~157 establishes a fair value hierarchy, which gives precedence to fair value measurements, calculated using observable inputs to those using unobservable inputs.~~161 also requires disclosures about credit-risk-related contingent features of derivative instruments. SFAS No. ~~157 requires entities to disclose fair-valued financial instruments according to the hierarchy in each reporting period after implementation. The provisions of SFAS No. 157 have been deferred to~~161 is effective prospectively for 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 financial statement impact of the implementation of SFAS No. 157.

~~Fair Value Option~~

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 have not elected the fair value option for any assets or liabilities as of 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 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 when reporting those amounts on a net basis. The provisions of FIN 39-1 are applied retrospectively. See2008. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

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

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

As of March 31, 2009 and December 31, 2008, PG&E Corporation’s $252 million preferred stock of subsidiary represents a noncontrolling interest in the Utility. PG&E Corporation has reclassified the noncontrolling interest from Preferred Stock of Subsidiaries to equity in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 160 for all periods presented. The Utility had no material noncontrolling interests in consolidated subsidiaries as of March 31, 2009 and December 31, 2008.

The presentation and disclosure requirements of SFAS No. 160 were applied retrospectively. Other than the change in presentation of noncontrolling interests, the adoption of SFAS No. 160 had no material impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

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

In September 2008, the FASB issued Emerging Issues Task Force (“EITF”) 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (“EITF 08-5”). EITF 08-5 clarifies the unit of account in determining the fair value of a liability under SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (“SFAS No. 107”), or SFAS No. 133. Specifically, it requires an entity to exclude any third-party credit enhancements that are issued with and are inseparable from a debt instrument from the fair value measurement of that debt instrument. EITF 08-5 is effective prospectively for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. EITF 08-5 did not have a material impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

Equity Method Investment Accounting Consideration — an amendment to Accounting Principles Board No. 18

In November 2008, the FASB issued EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”). EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost. Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than SFAS No. 141(R), “Business Combinations.” However, the investor of an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the ~~implementation~~investor’s share of the investee’s net assets exceeds the investor’s initial costs. An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings. EITF 08-6 is effective prospectively for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Consolidation of Variable Interest Entities

FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (“FIN ~~39-1.~~46R”), provides that an entity is a variable interest entity (“VIE”) if it does not have sufficient equity investment at risk or if the holders of the entity’s equity instruments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the holder subject to the majority of the risk of loss from a VIE’s activities must consolidate the VIE. However, if no holder has the majority of the risk of loss, then a holder entitled to receive a majority of the entity’s residual returns would consolidate the entity.

The majority of the Utility’s involvement with VIEs is through power purchase agreements. The Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a VIE owning one or more plants that sell substantially all of their output to the Utility. The Utility performs a qualitative assessment of power purchase agreements under FIN 46R, comparing the term of the contract to the remaining useful life of the plant to determine its absorption of the expected risks and rewards of the project, including production risk, commodity price risk, credit risk, and tax attributes.

At December 31, 2008, the Utility held a significant variable interest in one VIE. (See Note 2 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.) Additionally, during February 2009, the CPUC approved an agreement for the Utility to purchase as-available electric generation output from an approximately 250 megawatt (“MW”) solar photovoltaic facility for 25 years, beginning from the date of commercial operation. The 250 MW solar photovoltaic facility is a subsidiary of a publicly held company, and its activities are financed primarily through equity from investors and proceeds from non-recourse project-specific debt financing. The solar photovoltaic facility is a VIE and the Utility holds a significant variable interest through the power purchase agreement. Activities of the VIE consist of renewable energy production from a single facility for sale to third parties, and the facility is expected to become operational in 2012. The Utility is not considered the primary beneficiary of the VIE, as it will not absorb the majority of the VIE’s expected losses or residual returns. Accordingly, the Utility has not consolidated this VIE in its Condensed Consolidated Financial Statements. No payments for energy have been made to either VIE as of March 31, 2009.

These power purchase agreements do not expose the Utility to amounts in excess of the payments for as-available electricity. Future payments to these facilities are made based on the energy produced and are expected to be recoverable through customer rates. Additionally, no financial or other support was provided by the Utility to these VIEs as of March 31, 2009.

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 for PG&E Corporation ~~(consolidated)~~ and the Utility ~~(stand-alone)~~ for share-based incentive awards for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 and ~~2007:~~2008:

PG&E Corporation

Utility

Three Months Ended
September 30,

Three Months Ended
September 30,

(in millions)
2008

2007

2008

2007

Stock options $ 1 $ 2 $ - $ 1
Restricted stock 5 6 4 4
Performance shares - 15 - 10
Total compensation expense (pre-tax) $ 6 $ 23 $ 4 $ 15
Total compensation expense (after-tax) $ 4 $ 14 $ 2 $ 9

	PG&E Corporation				Utility					PG&E Corporation					Utility
	Nine Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,					Three Months Ended March 31,
(in millions)	2008		2007		2008		2007			2009		2008			2009		2008
Stock options	$	2	$	6	$	1	$	3		$	-	$	1		$	-	$	1
Restricted stock		19		19		13		12			2		9			2		5
Restricted stock units (1)											6		-			3		-
Performance shares		8		15		5		9			16		(4	)		10		(3	)
Total compensation expense (pre-tax)	$	29	$	40	$	19	$	24		$	24	$	6		$	15	$	3
Total compensation expense (after-tax)	$	17	$	24	$	11	$	14		$	14	$	4		$	9	$	2

(1) Beginning January 1, 2009, PG&E Corporation awarded restricted stock units (“RSUs”) instead of restricted stock as permitted by the PG&E Corporation 2006 Long-Term Incentive Plan. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day of March in 2010, 2011, and 2012, and the remaining 40% will vest on the first business day of March 2013. Each vested RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSUs recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.									(1) Beginning January 1, 2009, PG&E Corporation awarded restricted stock units (“RSUs”) instead of restricted stock as permitted by the PG&E Corporation 2006 Long-Term Incentive Plan. RSUs are hypothetical shares of stock that will generally vest in 20% increments on the first business day of March in 2010, 2011, and 2012, and the remaining 40% will vest on the first business day of March 2013. Each vested RSU is settled for one share of PG&E Corporation common stock. Additionally, upon settlement, RSUs recipients receive payment for the amount of dividend equivalents associated with the vested RSUs that have accrued since the date of grant.

Pension and Other Postretirement Benefits

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

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

Pension Benefits

Other Benefits

Three Months Ended
September 30,

Three Months Ended
September 30,

(in millions)
2008

2007

2008

2007

Service cost for benefits earned $ 59 $ 55 $ 7 $ 7
Interest cost 148 139 21 20
Expected return on plan assets (173 ) (178 ) (22 ) (23 )
Amortization of transition obligation (1)
- - 6 7
Amortization of prior service cost (1)
12 12 4 3
Amortization of unrecognized gain/(loss) (1)
1 1 (3 ) (1 )
Net periodic benefit cost $ 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 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.

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

The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three months ended March 31, 2009 and 2008 are as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2009			2008			2009			2008
Service cost for benefits earned	$	66		$	59		$	8		$	7
Interest cost		155			144			21			20
Expected return on plan assets		(145	)		(175	)		(17	)		(24	)
Amortization of transition obligation (1)		-			-			6			7
Amortization of prior service cost (1)		11			12			4			4
Amortization of unrecognized (gain) loss (1)		25			-			1			(4	)
Net periodic benefit cost	$	112		$	40		$	23		$	10
Less: transfer to regulatory account (2)		(71	)		1			-			-
Total	$	41		$	41		$	23		$	10

(1) In 2009 and 2008, 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),” 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 asset in 2009 and regulatory liability in 2008 in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”). (2) Under SFAS No. 71, the Utility recorded approximately $71 million in 2009 as an addition to the existing pension regulatory asset and approximately $1 million in 2008 as an addition to the existing pension regulatory liability to reflect the difference between pension expense or income for accounting purposes and pension expense or income for ratemaking, which is based on a funding approach.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three months ended March 31, 2009.

Accounting Pronouncements Issued But Not Yet Adopted

Disclosures about ~~Derivative Instruments and Hedging Activities -~~Employers’ Postretirement Benefit Plan Assets — an amendment ofto FASB Statement No. ~~133~~132(R)

In ~~March~~December 2008, the FASB issued FASB Staff Position (“FSP”) SFAS ~~No. 161, “Disclosures~~132(R)-1, “Employers’ Disclosures about ~~Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133”~~Postretirement Benefit Plan Assets” (“FSP SFAS ~~No. 161”~~132(R)-1”). FSP SFAS ~~No. 161~~132(R)-1 amends and expands the disclosure requirements of SFAS No. ~~133.~~132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” An entity is required to provide qualitative disclosures about ~~objectives~~how investment allocation decisions are made, the inputs and ~~strategies for using derivatives,~~valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. Additionally, quantitative disclosures onare required showing the fair value ~~amounts~~ of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and ~~gains and losses on derivative instruments, and disclosures relating to credit-risk-related contingent features in derivative agreements.~~a reconciliation for the period of plan assets that are measured using significant unobservable inputs. FSP SFAS ~~No. 161~~132(R)-1 is effective prospectively for fiscal years ~~beginning~~ending after ~~November~~December 15, ~~2008.~~2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 132(R)-1.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FSP SFAS 107-1 and APB No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP SFAS 107-1 and APB No. 28-1”). This FSP amends SFAS No. ~~161.~~107 and APB Opinion No. 28, “Interim Financial Reporting” to require disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods. An entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and where the carrying amount is classified in the Condensed Consolidated Balance Sheets. FSP SFAS 107-1 and APB No. 28-1 is effective prospectively for interim reporting periods after June 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 107-1 and APB No. 28-1.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP SFAS 115-2 and SFAS 124-2”). This FSP amends existing guidance related to other-than-temporary impairments to improve disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. Recognition and measurement guidance is not amended by this FSP. FSP SFAS 115-2 and SFAS 124-2 is effective prospectively for interim reporting periods after June 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 115-2 and SFAS 124-2.

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

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP SFAS 157-4”). This FSP amends SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), to provide guidance on estimating fair value when volume or level of activity for an asset or liability has significantly decreased when compared with normal market conditions. Guidance to identify circumstances when a transaction is not orderly, or is distressed or forced, is also provided. FSP SFAS 157-4 is effective prospectively for interim reporting periods after June 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 157-4.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

~~PG&E Corporation and the~~The Utility ~~account~~accounts for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility’s operations.

Under SFAS No. 71, incurred costs that would otherwise be charged to expense may be capitalized and recorded as regulatory assets if it is probable that the incurred costs will be recovered in future rates. The regulatory assets are amortized over future periods consistent with the inclusion of costs in authorized customer rates. If costs that a regulated enterprise expects to incur in the future are currently being recovered through rates, SFAS No. 71 requires that the regulated enterprise record those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future must be recorded as regulatory liabilities.Regulatory Assets

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

Long-Term Regulatory Assets

Long-term regulatory assets are ~~comprised~~composed of the following:

	Balance At				Balance At
(in millions)	September 30, 2008		December 31, 2007		March 31, 2009		December 31, 2008
Energy recovery bond regulatory asset	$	1,571	$	1,833
Regulatory assets for deferred income tax		827		732
Utility retained generation regulatory assets		817		947
Pension benefits					$	1,660	$	1,624
Energy recovery bonds						1,406		1,487
Deferred income tax						880		847
Utility retained generation						780		799
Price risk management						511		362
Environmental compliance costs		375		328		375		385
Unamortized loss, net of gain, on reacquired debt		223		269		219		225
Regulatory assets associated with plan of reorganization		108		122		90		99
Contract termination costs		86		96		78		82
Scheduling coordinator costs		66		90
Other		160		42		88		86
Total regulatory assets	$	4,233	$	4,459	$	6,087	$	5,996

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 Chapter 11 proceeding (“Chapter 11 Settlement Agreement”). The Utility expects to fully recover this asset by the end of 2012.

The regulatory assets for deferred income tax represent deferred income tax benefits previously passed through to customers and are offset by deferred income tax liabilities. Tax benefits to customers have been passed through, as the CPUC requires utilities under its jurisdiction to follow the “flow-through” method of passing certain tax benefits to customers. The “flow-through” method ignores the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.

In connection with the Chapter 11 Settlement Agreement, the Utility recognized a one-time non-cash gain of $1.2 billion related to the recovery of the Utility’s retained generation regulatory assets in 2004. The individual components of these regulatory assets are amortized over approximately 16 years.

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

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

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

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.

“Other” is primarily related to price risk management regulatory assets. The Utility enters into contracts to procure electricity and natural gas that are designed to reduce commodity price risks. Some of these price risk management contracts are accounted for as derivative instruments under SFAS No. 133 (seeSee Note 73 of the Notes to the ~~Condensed~~ Consolidated Financial ~~Statements). Changes~~Statements in the ~~fair value~~2008 Annual Report for further discussion 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~~long-term regulatory accounts to be recovered or refunded through regulated rates. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year.

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.assets.

Current Regulatory Assets

At ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~2008, the Utility had current regulatory assets of approximately ~~$317~~$612 million and ~~$131~~$355 million, respectively, consisting primarily of the current component 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. Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.

~~Regulatory Liabilities~~

~~Long-term regulatory liabilities are comprised of the following:~~

Balance At

(in millions)
September 30,
2008

December 31,
2007

Cost of removal obligation $ 2,694 $ 2,568
Employee benefit plans 626 578
Asset retirement costs 335 573
Public purpose programs 318 264
California Solar Initiative 206 159
Price risk management 105 124
Other 172 182
Total regulatory liabilities $ 4,456 $ 4,448

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

~~Employee benefit plan expenses represent~~Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of 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 other comprehensive income in the Condensed Consolidated Balance Sheets in accordance with SFAS No. 158. (Seefollowing:

	Balance At
(in millions)	March 31, 2009		December 31, 2008
Cost of removal obligation	$	2,805	$	2,735
Public purpose programs		307		259
Recoveries in excess of asset retirement obligation		271		226
California Solar Initiative		180		183
Price risk management		82		81
Gateway Generating Station		66		67
Environmental remediation insurance recoveries		41		52
Other		18		54
Total regulatory liabilities	$	3,770	$	3,657

See Note 23 of the Notes to the ~~Condensed~~ Consolidated Financial Statements ~~and~~in the ~~2007~~2008 Annual Report for further ~~discussion.) These balances will be charged against expense to~~discussion of the ~~extent that future expenses exceed amounts recoverable for~~long-term 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 program costs that are expected to be incurred in the future.~~

California Solar Initiative liabilities represent revenues 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.

~~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 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.liabilities.

Current Regulatory Liabilities

As of ~~September 30,~~March 31, 2009 and December 31, 2008, the Utility had current regulatory liabilities of approximately ~~$310~~$263 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 $280and $313 million, respectively, 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 actual billed and unbilled revenues and the ~~Utility's~~Utility’s authorized revenue requirements ~~and~~for the period. The Utility also uses cost regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs ~~recovered, or collected (primarily commodity cost).~~and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.

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

Current Regulatory Balancing Accounts

	Receivable (Payable)
	Balance At
(in millions)	March 31, 2009			December 31, 2008
Utility generation	$	444		$	164
Modified transition cost		227			214
Energy resource recovery		200			384
Distribution revenue adjustment mechanism		185			40
Transmission revenue		170			173
Gas purchase and distribution		(126	)		(8	)
Public purpose programs		(231	)		(263	)
Energy recovery bonds		(219	)		(231	)
Other		(5	)		(6	)
Total regulatory balancing accounts, net	$	645		$	467

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

Balance At

(in millions)
September 30,
2008

December 31,
2007

Electricity revenue and cost balancing accounts $ 1,059 $ 678
Natural gas revenue and cost balancing accounts 58 93
Total $ 1,117 $ 771
The modified transition cost balancing account is used to track the recovery of ongoing competition transition charge (“CTC”), primarily consisting of above-market costs associated with power purchase contracts that were being collected in CPUC-approved rates on or before December 20, 1995 (including costs incurred by the Utility with CPUC approval to restructure, renegotiate, or terminate the contracts). The recovery of ongoing CTC can continue for the term of the contract. The amount of above-market costs associated with the eligible power purchase contracts is determined each year in the energy resource recovery account (“ERRA”) forecast proceeding by comparing the ongoing CTC-eligible contract costs to a CPUC-approved market benchmark to determine whether there are stranded costs associated with these contracts.

~~Current Regulatory Balancing Account Liabilities~~The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs through the ERRA. The Utility files annual forecasts of energy procurement costs that it expects to incur during the following year, and rates are set to recover such expected costs. The ERRA tracks actual electric costs and recoveries of fuel and energy procurement costs, excluding the costs incurred under contracts entered into by the California Department of Water Resources (“DWR”) to purchase energy allocated to the Utility’s customers.

Balance At

(in millions)
September 30,
2008

December 31,
2007

Electricity revenue and cost balancing accounts $ 795 $ 618
Natural gas revenue and cost balancing accounts 111 55
Total $ 906 $ 673
The distribution revenue adjustment mechanism account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. Because the Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales, the Utility recognizes revenue evenly over the year even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales. During the summer months, the under-collection generally decreases as the volume of electricity sales increases with warmer weather.

~~During~~The transmission revenue balancing account represents the ~~nine months ended September 30, 2008,~~difference between electric transmission wheeling revenues received by the ~~under-collection in~~Utility from the ~~Utility's electricity revenue~~California Independent System Operator (“CAISO”) (on behalf of electric transmission wholesale customers) and ~~cost~~refunds to customers plus interest.

The gas purchase and distribution balancing accounts ~~increased~~track actual gas costs and recoveries, as well as the difference between the authorized and recovered gas base revenue requirement, which is intended to recover the portions of operation and maintenance expenses, depreciation, taxes, and return on invested capital that are associated with small commercial and residential (or “core”) customers.

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

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

At March 31, 2009 and 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~~“Other” consisted of various miscellaneous balancing ~~accounts increased from December 31, 2007 mainly due to seasonal demand changes.~~accounts.

NOTE 4: DEBT

PG&E Corporation

~~Convertible Subordinated~~Senior Notes

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

Credit Facility

At ~~September 30, 2008,~~March 31, 2009, PG&E Corporation had ~~outstanding~~a $200 million revolving credit facility, which included a commitment from Lehman Brothers Bank, FSB (“Lehman Bank”) that represented approximately ~~$280~~$13 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 optionor 7%, of the ~~holder) at any time prior to maturity into 18,558,059 shares of~~total borrowing capacity under the revolving credit facility. On April 27, 2009, PG&E Corporation ~~common stock, at~~amended the revolving credit facility and removed Lehman Bank as 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~~lender. As a result, total borrowing capacity under 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 $28 million, including $7 million paid on October 15, 2008.revolving credit facility is now $187 million.

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 (expense), net) in PG&E Corporation's Condensed Consolidated Statements of Income as a non-operating expense or income. At September 30, 2008, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $49 million, of which $28 million was classified in Current Liabilities - Other and $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 in Current Liabilities - Other and $37 million was classified 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.)

Utility

Senior Notes

On March ~~3, 2008,~~6, 2009, the Utility issued ~~$200~~$550 million principal amount of ~~5.625%~~6.25% Senior Notes due on November 30, 2017, increasing the total outstanding amount of 5.625% Senior Notes to $700 million. Also on March 3, 2008, the Utility issued $400 million principal amount of 6.35% Senior Notes due on February 15, 2038.

~~At 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 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 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 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.

On September 22, 2008, the CIEDB issued $50 million principal amount of pollution control bonds 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 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 September 20, 2010 at a price of 100% of the principal amount plus accrued interest. Thereafter, these series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on March 1, ~~and September 1.~~

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

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.2039.

Credit ~~Facilities~~Facility and Short-Term Borrowings

At ~~September 30, 2008, there were~~March 31, 2009, the Utility had approximately ~~$273~~$295 million of letters of credit ~~and $533 million of borrowings~~ outstanding ~~at a yield of 3.38%~~ under the Utility’s $2.0 billion ~~working capital~~revolving credit facility. The commitment from Lehman Bank represented approximately $60 million, or 3%, of the total borrowing capacity under the revolving credit facility. On April 27, 2009, the Utility amended the revolving credit facility and removed Lehman Bank as a lender. As a result, total borrowing capacity under the Utility’s revolving credit facility is now $1.94 billion.

In addition, the ~~working capital~~revolving credit facility provides liquidity support for commercial paper offerings. At ~~September 30, 2008,~~March 31, 2009, the Utility had ~~$802~~$385 million of commercial paper outstanding at an average yield of approximately ~~5.75%~~1.15%.

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~~“recovery property,"” to be paid a specified amount from a dedicated rate component. The total amount of ERB principal outstanding was ~~$1.7~~$1.5 billion at ~~September 30, 2008.~~March 31, 2009.

While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets (including the recovery property) of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

NOTE 5: ~~SHAREHOLDERS'~~ EQUITY

PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s changes in ~~shareholders'~~ equity for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 were as follows:

	PG&E Corporation			Utility			PG&E Corporation			Utility
(in millions)	Total Common Shareholders' Equity			Total Shareholders' Equity			Total Equity			Total Shareholders’ Equity
Balance at December 31, 2007	$	8,553		$	9,125
Balance at December 31, 2008							$	9,629		$	9,787
Net income		821			870			244			239
Common stock issued		150			-			129			-
Share-based compensation amortization		21			-			8			-
Common stock dividends declared and paid		(279	)		(426	)		-			(156	)
Common stock dividends declared but not yet paid		(140	)		-			(154	)		-
Preferred stock dividends		-			(10	)
Tax benefit from share-based payment awards		5			4
Preferred dividend requirement								-			(3	)
Preferred dividend requirement of subsidiary								(3	)		-
Tax benefit from employee stock plans								2			2
Other comprehensive income		8			8			7			7
Equity contribution		-			90			-			528
Balance at September 30, 2008	$	9,139		$	9,661
Balance at March 31, 2009							$	9,862		$	10,404

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~~three months ended ~~September 30, 2008,~~March 31, 2009, PG&E Corporation contributed equity of ~~$90~~$528 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

Dividends

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, PG&E Corporation paid common stock dividends totaling ~~$433 million, including $28 million to Elm Power Corporation.~~$143 million. On ~~September 17, 2008,~~February 18, 2009, the Board of Directors of PG&E Corporation declared a dividend of ~~$0.39~~$0.42 per share, totaling ~~$140~~$154 million, which was paid on ~~October~~April 15, ~~2008~~2009 to shareholders of record on ~~September 30, 2008.~~March 31, 2009.

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling ~~$10~~$3 million. On ~~September 17, 2008,~~February 18, 2009, the Board of Directors of the Utility declared a cash dividend, totaling $3 million, on its outstanding series of preferred stock, payable on ~~November~~May 15, ~~2008~~2009 to shareholders of record on ~~October 31, 2008.~~ April 30, 2009.

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”~~two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E ~~Corporation's~~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~~Corporation’s participating securities participate on a 1:1 basis with shares of common stock.

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

		Three Months Ended				Nine Months Ended					Three Months Ended
		September 30,				September 30,					March 31,
(in millions, except per share amounts)		2008		2007		2008		2007			2009		2008
Net income		$	304	$	278	$	821	$	803
Income Available for Common Shareholders											$	241	$	224
Less: distributed earnings to common shareholders			140		127		419		379			154		139
Undistributed earnings		$	164	$	151	$	402	$	424		$	87	$	85
Common shareholders earnings
Basic
Distributed earnings to common shareholders		$	140	$	127	$	419	$	379		$	154	$	139
Undistributed earnings allocated to common shareholders			156		143		382		402			83		81
Total common shareholders earnings, basic		$	296	$	270	$	801	$	781		$	237	$	220
Diluted
Distributed earnings to common shareholders		$	140	$	127	$	419	$	379		$	154	$	139
Undistributed earnings allocated to common shareholders			156		143		382		402			83		81
Total common shareholders earnings, diluted		$	296	$	270	$	801	$	781		$	237	$	220
Weighted average common shares outstanding, basic			357		352		356		350			364		355
9.50% Convertible Subordinated Notes			19		19		19		19			17		19
Weighted average common shares outstanding and participating securities, basic			376		371		375		369			381		374
Weighted average common shares outstanding, basic			357		352		356		350			364		355
Employee share-based compensation			1		1		1		2			2		1
Weighted average common shares outstanding, diluted			358		353		357		352			366		356
9.50% Convertible Subordinated Notes			19		19		19		19			17		19
Weighted average common shares outstanding and participating securities, diluted			377		372		376		371			383		375
Net earnings per common share, basic
Distributed earnings, basic (1)		$	0.39	$	0.36	$	1.18	$	1.08		$	0.42	$	0.39
Undistributed earnings, basic			0.44		0.41		1.07		1.15			0.23		0.23
Total		$	0.83	$	0.77	$	2.25	$	2.23		$	0.65	$	0.62
Net earnings per common share, diluted
Distributed earnings, diluted		$	0.39	$	0.36	$	1.17	$	1.08		$	0.42	$	0.39
Undistributed earnings, diluted			0.44		0.41		1.07		1.14			0.23		0.23
Total		$	0.83	$	0.77	$	2.24	$	2.22		$	0.65	$	0.62


(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.									(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.

2019

~~Options~~Stock options to purchase 26,592 and 7,285 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2009 and 2008, respectively, because the exercise prices of these options were greater than the average market price of PG&E Corporation common stock during these periods.

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

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility ~~enters into contracts~~faces market risk primarily related to ~~procure~~ electricity and natural gas ~~nuclear fuel,~~commodity prices. The CPUC and ~~firm~~the FERC allow the Utility to collect customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity ~~transmission rights. Some~~and natural gas. As these costs are passed through to customers, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of ~~these~~electricity and natural gas. Therefore, substantially all of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers.

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

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

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

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

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

These instruments are not held for speculative purposes and are subject to certain limitations imposed by regulatory requirements. These instruments enable the ~~definition~~Utility to reduce the volatility associated with electricity and natural gas costs incurred by the Utility and charged to its customers through rates.

Additionally, in order to fund its business operations, PG&E Corporation issued 9.50% Convertible Subordinated Notes with an outstanding value of approximately $252 million at March 31, 2009. The notes are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 16,702,194 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 PG&E Corporation Convertible Subordinated Notes have the right to receive pass-through dividends determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion price. In accordance with SFAS No. 133, the dividend participation rights of the Convertible Subordinated Notes are considered to be embedded derivative instruments ~~under~~and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements.

Commodity-Related Price Risk

As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers in rates all costs related to commodity-related price risk-related derivative instruments. Therefore, in accordance with the provisions of SFAS No. ~~133. All such~~71, all unrealized gains and losses associated with the fair value of these derivative instruments, including ~~instruments~~those designated as cash flow hedges, are deferred and recorded ~~at fair value and presented as price risk management~~within the Utility’s regulatory assets and liabilities on the ~~balance sheet (see table below).~~Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity-related price risk-related derivative instruments are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

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

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments under SFAS No. 133 and therefore are recorded at fair value within the Condensed Consolidated Balance Sheets. However, derivative instruments that are eligible for the normal purchase and normal sales exception under SFAS No. 133 are not required to be recorded at fair value. Derivative instruments that require the physical delivery of commodities, where quantities purchased are expected to be used by the Utility in the normal course of business and meet certain other criteria, are eligible for the normal purchase and normal sales exception. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the cash flow risk associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases under those power purchase agreements. These financial swaps are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets. Some of these contracts have been designated as cash flow hedges in accordance with the requirements of SFAS No. 133.

Electric Transmission Congestion Revenue Rights

The CAISO-controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to both physical and financial risk associated with transmission congestion.

Under FERC rules, the CAISO was required to make long-term firm transmission rights (“FTRs”) available by auction to the California investor-owned utilities and other load-serving entities to allow these entities to hedge both the physical transmission risk by providing scheduling priority on the transmission lines and the financial risk associated with CAISO-imposed congestion charges. The use of ~~applying~~FTRs was discontinued on April 1, 2009 when the CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update (“MRTU”). In lieu of FTRs, the CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve), and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility acquired CRRs in 2008 (via allocation and auction) in anticipation of the effectiveness of the MRTU. In the first quarter of 2009, the Utility acquired additional CRRs through both allocation and auction. Also, in the first quarter of 2009, the Utility acquired additional FTRs through auction in order to hedge its physical and financial risk until the MRTU became effective on April 1, 2009.

CRRs and FTRs are considered derivative instruments and are recorded at fair value within the Condensed Consolidated Balance Sheets. FTRs are recorded at zero value on the Condensed Consolidated Balance Sheets, reflecting the nullification of FTRs on March 31, 2009.

Natural Gas Procurement (Electric Portfolio)

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

Natural Gas Procurement (Core Customers)

The Utility enters into physical natural gas commodity contracts 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 or sold in the monthly and, to a lesser extent, daily spot market to balance such seasonal supply and demand.

The Utility has entered into various financial instruments, such as financial swap and option contracts, intended to reduce the cash flow variability associated with fluctuating natural gas purchase prices. The Utility manages its exposure to natural gas prices in accordance with its CPUC-approved annual core portfolio hedging implementation plan. These contracts are considered derivative instruments that are recorded at fair value within the Condensed Consolidated Balance Sheets. A portion of these contracts have been designated as cash flow hedges in accordance with the requirements of SFAS No. 133.

Other Risk

The dividend participation rights of the Convertible Subordinated Notes are considered embedded derivative instruments in accordance with the provisions of SFAS No. ~~71, unrealized changes~~133. Therefore, these rights are bifurcated from the Convertible Subordinated Notes and are recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Changes in the fair value are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as a non-operating expense or income (in Other income, net). Since January 1, 2009, PG&E Corporation has paid pass-through dividends totaling approximately $14 million, including $7 million paid on April 15, 2009.

Volume of Derivative Activity

As of March 31, 2009, the volume of PG&E Corporation’s and the Utility’s outstanding derivative ~~instruments are deferred and recorded to regulatory assets or liabilities. Under the same regulatory accounting treatment, changes~~contracts were as follows:

		Contract Volumes (1)
Underlying Product	Instruments	Less Than 1 Year		1 Year But Less Than 3 Years		3 Years But Less Than 5 Years		Over 5 Years (2)
Natural Gas (3) (MMBtus (4))	Forwards, Futures, and Swaps		336,621,564		161,031,167		20,600,000		-
	Options		156,232,065		138,070,000		20,600,000		-

Electricity (Megawatt-hours)	Forwards, Futures, and Swaps		6,882,548		7,358,609		5,996,652		6,666,744
	Options		19,392		10,408		10,464		11,200
	Congestion Revenue Rights		65,020,816		59,670,412		59,604,520		124,349,006

PG&E Corporation Equity Shares	Dividend Participation Rights		16,702,194		16,702,904		-		-

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

Presentation of Derivative Instruments in the ~~fair value of cash flow hedges are also recorded to regulatory assets or liabilities, rather than being deferred in accumulated other comprehensive income.~~Financial Statements

In PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s Condensed Consolidated Balance Sheets, ~~price risk management assets and liabilities associated with the Utility’s electricity and gas procurement activities~~derivative instruments are presented on a net basis by counterparty where the right of offset exists. ~~As PG&E Corporation and the Utility adopted~~In accordance with the provisions of FASB Staff Position on FASB Interpretation 39, “Amendment of FASB Interpretation No. 39” (“FIN ~~39-1 on~~39-1”), which was adopted 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 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)
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 ~~September 30, 2008,~~March 31, 2009, PG&E ~~Corporation~~Corporation’s and the ~~Utility had cash flow hedges with expiration dates through December 2012 for energy contract~~Utility’s outstanding derivative ~~instruments.~~balances were as follows:

	Gross Balances (1)
(in millions)	Derivatives Designated as Cash Flow Hedges (2)			Derivatives Not Designated as Hedges			Total			Netting (3)			Cash Collateral (3)		Total Derivative Balances on the Condensed Consolidated Balance Sheets
Commodity Risk (Corporation and Utility)
Current Assets – Prepaid expenses and other	$	-		$	62		$	62		$	(10	)	$	83	$	135
Other Noncurrent Assets – Other		-			107			107			(25	)		81		163
Current Liabilities – Other		(138	)		(299	)		(437	)		10			278		(149	)
Noncurrent Liabilities – Other		(229	)		(306	)		(535	)		25			150		(360	)
Total Commodity Risk	$	(367	)	$	(436	)	$	(803	)	$	-		$	592	$	(211	)

Other Risk Instruments (4) (PG&E Corporation Only)
Current Liabilities –Other	$	-		$	(26	)	$	(26	)	$	-		$	-	$	(26	)
Noncurrent Liabilities – Other		-			(7	)		(7	)		-			-		(7	)
Total Other Risk Instruments	$	-		$	(33	)	$	(33	)	$	-		$	-	$	(33	)
Total Derivatives	$	(367	)	$	(469	)	$	(836	)	$	-		$	592	$	(244	)

(1) See Note 8 of the Notes to the Condensed Consolidated Financial Statements for discussion of the valuation techniques used to calculate the fair value of these instruments.
(2) As of March 31, 2009, PG&E Corporation and the Utility had cash flow hedges with expiration dates through December 2012 for energy contract-related derivative instruments.
(3) Netting in accordance with FIN 39 and FSP FIN 39-1.
(4) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.

The ~~Utility also has derivative instruments for the physical delivery of commodities transacted~~dividend participation rights are not recoverable in customers’ rates. Therefore, changes in the ~~normal course~~fair value of ~~business. These derivative~~these instruments ~~are eligible for the normal purchase and sales exceptions under SFAS No. 133, and are not reflected in the Condensed Consolidated Balance Sheets.~~

~~Net realized gains or losses on derivative instruments, including those derivative instruments for which the normal purchase and sales exception has been elected,~~ are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income and impact net income.

For the ~~cost of electricity~~three-month period ended March 31, 2009, the gains and losses recorded on PG&E Corporation’s and the ~~cost of natural gas.~~ Utility’s derivative instruments were as follows:

(in millions)	Derivatives Designated as Cash Flow Hedges (1)		Derivatives Not Designated as Hedges			��	Total
Commodity Risk (PG&E Corporation and Utility)
Regulatory assets andliabilities (2)	$	16	$	(323	)		$	(307	)
Cost of electricity(3)		23		179				202
Cost of natural gas (3)		23		-				23
Total Commodity Risk	$	62	$	(144	)		$	(82	)
Other Risk Instruments (PG&E Corporation Only)
Other income, net	$	-	$	2			$	2
Total Other Risk	$	-	$	2			$	2

(1) As a result of applying the provisions of SFAS No. 71, unrealized gains and losses on cash flow hedges are recorded to regulatory assets or liabilities, rather than being deferred in accumulated other comprehensive income.
(2) As a result of applying the provisions of SFAS No. 71, unrealized gains and losses on the commodity risk-related derivative instrument are recorded to regulatory assets or liabilities, rather than being recorded to Condensed Consolidated Income Statement. Additionally, these amounts exclude the impact of cash collateral postings.
(3) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

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

The ~~dividend participation rights~~majority of ~~PG&E Corporation’s Convertible Subordinated Notes, considered to be~~the Utility’s commodity risk-related derivative instruments ~~are recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements in accordance with SFAS No. 133. (See Note 4~~contain collateral posting provisions tied to the Utility’s credit rating from each of the ~~Notes~~major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the ~~Condensed Consolidated Financial Statements for discussion~~Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

As of March 31, 2009, the ~~Convertible Subordinated Notes.)~~additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered is as follows:

(in millions)	As of March 31, 2009
Derivatives in a Liability Position with Credit-Risk-RelatedContingencies That Are Not Fully Collateralized	$	(652	)
Related Derivatives in an Asset Position		5
Collateral Posting in the Normal Course of Business Relatedto These Derivatives		161
Net Position of Derivative Contracts/Additional Collateral Posting Requirements (1)	$	(486	)

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

2123

NOTE 8: FAIR VALUE MEASUREMENTS

~~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,requires an entity ~~must now~~to determine the fair value of ~~an asset or liability~~assets and liabilities based on ~~the~~ assumptions that market participants would use in pricing the ~~asset~~assets 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,liabilities. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value and gives precedence to ~~fair value measurements calculated using~~ observable inputs ~~over those using unobservable inputs. Accordingly,~~in determining fair value. An instrument’s level within 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 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 derivatives (other than options) valued using exchange inputs and exchange traded derivatives (other than options) for which the markethierarchy 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 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 an entity from recognizing a day one gain or loss on derivative contracts based on the ~~use~~lowest level of ~~unobservable inputs. A day one gain or loss is the difference between the transaction price and~~any significant input to the fair value measurement. See Note 12 of the ~~contract on the day the derivative contract is executed (i.e., at inception). Prior~~Notes to the ~~adoption~~Consolidated Financial Statements in the 2008 Annual Report for further discussion of ~~SFAS No. 157, the Utility did not record any day one gains associated with Congestion Revenue Rights (“CRRs”) as the~~ fair value was based primarily on unobservable market data. (CRRs allow market participants, including load serving entities, to hedge the financial risk of congestion charges imposed by the California Independent System Operator (“CAISO”) in the day-ahead market to be established when the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) becomes effective.) The costs associated with 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 increase in price risk management assets and the related regulatory liabilities as of January 1, 2008.measurements.

The following table sets forth the fair value hierarchy by level of PG&E ~~Corporation~~Corporation’s and the Utility’s recurring fair value financial instruments as of ~~September 30, 2008.~~March 31, 2009. The instruments are classified based on the lowest level of input that is significant to the fair value measurement. PG&E ~~Corporation~~Corporation’s and the Utility’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PG&E Corporation	PG&E Corporation				PG&E Corporation
Fair Value Measurements as of September 30, 2008
Fair Value Measurements as of March 31, 2009					Fair Value Measurements as of March 31, 2009
(in millions)	Level 1	Level 2	Level 3	Total		Level 1			Level 2		Level 3		Total
Assets:
Money market investments (held by PG&E Corporation)	$ 192	$ -	$ 62	$ 254		$	211		$	-	$	8	$	219
Nuclear decommissioning trusts(1)	1,609	308	7	1,924			1,455			249		4		1,708
Price risk management instruments(2)	54	4	34	92
Rabbi trusts(3)	78	-	-	78
Rabbi trusts							59			-		-		59
Long-term disability trust	49	-	79	128			86			-		71		157
Assets Total	$ 1,982	$ 312	$ 182	$ 2,476		$	1,811		$	249	$	83	$	2,143
Liabilities:
Dividend participation rights	$ -		$ 49	$ 49		$	-		$	-	$	33	$	33
Price risk management instruments(2)							(51	)		86		176		211
Other	-		5	5			-			-		1		1
Liabilities Total	$ -		$ 54	$ 54		$	(51	)	$	86	$	210	$	245


(1) Excludes taxes on appreciation of investment value.	(1) Excludes taxes on appreciation of investment value.				(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.
(3) Excludes life insurance policies.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $229 million to Level 1, $123 million to Level 2, and $240 million to Level 3.					(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $229 million to Level 1, $123 million to Level 2, and $240 million to Level 3.

Utility	Utility					Utility
Fair Value Measurements as of September 30, 2008
Fair Value Measurements as of March 31, 2009						Fair Value Measurements as of March 31, 2009
(in millions)	(in millions)	Level 1	Level 2	Level 3	Total		Level 1			Level 2		Level 3		Total
Assets:	Assets:
Nuclear decommissioning trusts(1)	Nuclear decommissioning trusts(1)	$ 1,609	$ 308	$ 7	$ 1,924		$	1,455		$	249	$	4	$	1,708
Price risk management instruments(2)		54	4	34	92
Long-term disability trust	Long-term disability trust	49	-	79	128			86			-		71		157
Assets Total	Assets Total	$ 1,712	$ 312	$ 120	$ 2,144		$	1,541		$	249	$	75	$	1,865
Liabilities:	Liabilities:
Price risk management instruments (2)							$	(51	)	$	86	$	176	$	211
Other	Other	$ -	$ -	$ 5	$ 5			-			-		1		1
Liabilities Total	Liabilities Total	$ -	$ -	$ 5	$ 5		$	(51	)	$	86	$	177	$	212


(1) Excludes taxes on appreciation of investment value.	(1) Excludes taxes on appreciation of investment value.					(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.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $229 million to Level 1, $123 million to Level 2, and $240 million to Level 3.						(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $229 million to Level 1, $123 million to Level 2, and $240 million to Level 3.

PG&E ~~Corporation~~Corporation’s 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 on 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.adjustments. As of ~~September 30, 2008,~~March 31, 2009, the nonperformance and credit risk adjustment ~~represents~~represented approximately 1%3% 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.)

~~Trust Assets~~

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~~Financial Instruments

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

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

·	The fair values of the Utility’s fixed rate senior notes, fixed rate pollution control bond loan agreements, and the ERBs issued by PERF were based on quoted market prices obtained from the Bloomberg financial information system at March 31, 2009.

·	The fair value of PG&E Corporation’s 9.50% Convertible Subordinated Notes was determined by considering the prices of securities displayed as of the close of business on March 31, 2009 by a proprietary bond trading system that tracks and marks a broad universe of convertible securities, including the securities being assessed.

The ~~dividend participation rights of the Convertible Subordinated Notes are embedded derivative instruments in accordance with SFAS No. 133~~carrying amount and ~~therefore, are bifurcated from Convertible Subordinated Notes and recorded at~~ fair value inof PG&E ~~Corporation's~~Corporation’s and the Utility’s financial instruments are as follows (the table below excludes financial instruments with fair values that approximate their carrying values, as these instruments are presented at their carrying value in the 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.)Sheets):

	At March 31,				At December 31,
	2009				2008
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4):
PG&E Corporation	$	602	$	1,002	$	280	$	739
Utility		8,690		8,820		8,740		9,134
Energy recovery bonds (Note 4)		1,494		1,526		1,583		1,564

Level 3 Rollforward

The following table is a reconciliation of changes in fair value of PG&E Corporation’s instruments that have been classified as Level 3 in the fair value hierarchy for the ~~nine month~~three-month period ended ~~September 30, 2008:~~March 31, 2009:

PG&E Corporation
(in millions)
Money Market Investments
Price Risk Management Instruments
Nuclear Decommissioning Trusts (3)
Long-term Disability
Dividend Participation Rights
Other
Total
Asset (liability) Balance as of January 1, 2008 $ -
$ 115(1)
$ 8 $ 69
$ (68)(2)
$ (4) $120
Realized and unrealized gains (losses):
Included in earnings - - - - (2) - (2)
Included in regulatory assets and liabilities or balancing accounts - (81) (1) (12) - (1) (95)
Purchases, issuances, and settlements - - - 22 21 - 43
Transfers in (out) of Level 3
62
-
-
-
-
-
62
Asset (liability) Balance as of September 30, 2008
$ 62
$ 34
$ 7
$ 79
$ (49)
$ (5)
$ 128

Earnings for the period were impacted by a $2 million unrealized loss relating to assets or liabilities still held at September 30, 2008.

(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1.
(2) 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 expense to increase the value of the liability.
(3) Excludes taxes on appreciation of investment value.

Utility
(in millions)
Price Risk Management Instruments
Nuclear Decommissioning
Trusts (2)
Long-term Disability
Other
Total
Asset (liability) Balance as of January 1, 2008
$ 115(1)
$ 8 $ 69 $ (4) $188
Realized and unrealized gains (losses):
Included in earnings - - - - -
Included in regulatory assets and liabilities or balancing accounts (81) (1) (12) (1) (95)
Purchases, issuances, and settlements - - 22 - 22
Transfers in (out) of Level 3
-
-
-
-
-
Asset (liability) Balance as of September 30, 2008
$ 34
$ 7
$ 79
$ (5)
$ 115

Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008.

(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1
(2) Excludes taxes on appreciation of investment value.

	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market Instruments			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommissioning Trusts (1)			Long-term Disability			Other			Total
Asset (liability) Balance as of January 1, 2009	$	12		$	(42	)	$	(156	)	$	5		$	78		$	(2	)	$	(105	)
Realized and unrealized gains (losses):
Included in earnings		-			2			-			-			(7	)		-			(5	)
Included in regulatory assets and liabilities or balancing accounts		-			-			(20	)		(1	)		-			1			(20	)
Purchases, issuances, and settlements		(4	)		7			-			-			-			-			3
Transfers in to Level 3		-			-			-			-			-			-			-
Asset (liability) Balance as of March 31, 2009	$	8		$	(33	)	$	(176	)	$	4		$	71		$	(1	)	$	(127	)

(1) Excludes taxes on appreciation of investment value.

~~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~~Earnings for the ~~three month~~ period ~~ended September 30, 2008:~~

PG&E Corporation
(in millions)
Money Market Investments
Price Risk Management Instruments
Nuclear Decommissioning Trusts (1)
Long-term Disability
Dividend Participation Rights
Other
Total
Asset (liability) Balance as of June 30, 2008 $ - $ 382 $ 7 $ 95 $ (55) $ (6) $ 423
Realized and unrealized gains (losses):
Included in earnings - - - - (1) - (1)
Included in regulatory assets and liabilities or balancing accounts - (348) - (5) - 1 (352)
Purchases, issuances, and settlements - - - (11) 7 - (4)
Transfers in (out) of Level 3
62
-
-
-
-
-
62
Asset (liability) Balance as of September 30, 2008
$ 62
$ 34
$ 7
$ 79
$ (49)
$ (5)
$ 128

Earnings for the period were impacted by a $1 million unrealized loss relating to assets or liabilities still held at September 30, 2008.

(1) Excludes taxes on appreciation of investment value.

Utility
(in millions)
Price Risk Management Instruments
Nuclear Decommissioning Trusts (1)
Long-term Disability
Other
Total
Asset (liability) Balance as of June 30, 2008 $ 382 $ 7 $ 95 $ (6) $ 478
Realized and unrealized gains (losses):
Included in earnings - - - - -
Included in regulatory assets and liabilities or balancing accounts (348) - (5) 1 (352)
Purchases, issuances, and settlements - - (11) - (11)
Transfers in (out) of Level 3
-
-
-
-
-
Asset (liability) Balance as of September 30, 2008
$ 34
$ 7
$ 79
$ (5)
$ 115

Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008.

(1) Excludes taxes on appreciation of investment value.

were impacted by a $5 million unrealized loss relating to assets or liabilities still held at March 31, 2009.

PG&E Corporation and the Utility did not have any nonrecurring financial measurements that are within the scope of SFAS No. 157 as of ~~September 30, 2008.~~March 31, 2009.

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

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

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
(in millions)	2008		2007		2008		2007		2009		2008
Utility revenues from:
Administrative services provided to PG&E Corporation	$	-	$	1	$	2	$	3	$	1	$	1
Utility employee benefit assets due from PG&E Corporation		-		-		-		-
Interest from PG&E Corporation on employee benefit assets		-		-		-		1
Utility employee benefit due from PG&E Corporation										-		-
Utility expenses from:
Administrative services received from PG&E Corporation	$	34	$	31	$	86	$	83	$	19	$	24
Utility employee benefit assets due to PG&E Corporation		1		1		2		3
Utility employee benefit due to PG&E Corporation										6		7

At ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~2008, the Utility had a receivable of approximately ~~$27~~$31 million and $29 million, respectively, from PG&E Corporation included in Accounts receivable – Related parties and Other Noncurrent Assets – Related parties receivable on the Utility’s Condensed Consolidated Balance Sheets, and a payable of approximately ~~$33~~$19 million and ~~$28~~$25 million, respectively, to PG&E Corporation included in Accounts payable – Related parties on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

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

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

The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 2008 to March 31, 2009:

(in millions)
Balance at December 31, 2008	$	1,750
Interest accrued		20
Less: Settlements		(33	)
Balance at March 31, 2009	$	1,737

As of ~~September 30, 2008,~~March 31, 2009, the Utility’s ~~liability for the remaining~~ net disputed claims liability was approximately ~~$1.7 billion,~~$1,737 million, consisting of approximately ~~$1.6 billion~~$1,552 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets aswithin Accounts payable – Disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of ~~$0.6 billion~~$679 million (classified on the Condensed Consolidated Balance Sheets aswithin Interest payable) offset by an accounts receivable from the CAISO and ~~the~~ PX of approximately ~~$0.5 billion (included within Accounts receivable – Customers~~$494 million (classified on the Condensed Consolidated Balance ~~Sheets)~~Sheets within Accounts receivable – Customers). ~~These amounts do not include potential remaining refunds that may be due to~~

In connection with the Utility’s proceedings under Chapter 11, the Utility ~~as a result~~established an escrow account for the payment of the ~~FERC refund proceedings.~~

disputed claims, which is included within Restricted cash on the Condensed Consolidated Balance Sheets. As of ~~September 30, 2008,~~March 31, 2009, the Utility held ~~$1.2 billion~~$1,213 million in escrow, including ~~approximately $0.1 billion of~~interest earned, ~~interest,~~ for payment of the remaining net disputed ~~claims (classified as Restricted cash in the Condensed Consolidated Balance Sheets).~~claims.

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

~~The~~

On April 10, 2009, the Utility and the PX ~~have been negotiating the terms of~~entered into a proposed agreement ~~regarding~~under which the ~~potential~~Utility has agreed to 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 toin CAISO or PX markets as may be authorized by the FERC or a court of competent jurisdiction. The proposed agreement ~~would be~~is subject to approval by the FERC and by the bankruptcy courts that have jurisdiction ofover the Chapter 11 proceedings of the PX and the Utility. ~~Under the proposed agreement, the~~The Utility’s payment would reduce its liability for the remaining net disputed claims. To protect the Utility against the imposition of double liability, the proposed agreement ~~would provide~~provides that to the extent that both the PX and an individual electricity supplier have filed claims relating to the same transaction, such claim ~~would~~will 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 athe 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, including interest, that the Utility will be required to pay.

NOTE 11: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the ~~Utility's~~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.

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase 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 of electricity at the date of purchase. Forward prices as of ~~September 30, 2008~~March 31, 2009 are used to determine the undiscounted future expected payments for contracts with variable pricing terms. At ~~September 30, 2008,~~March 31, 2009, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)
2008	$	565
2009		2,384	$	1,576
2010		2,345		2,137
2011		2,309		2,249
2012		2,231		2,205
2013				2,098
Thereafter		18,639		21,784
Total	$	28,473	$	32,049

Payments made by the Utility under power purchase agreements amounted to approximately ~~$3,631~~$663 million and ~~$2,367~~$1,028 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and March 31, 2008, ~~and September 30, 2007,~~ respectively. The amounts above do not include payments related to the ~~California Department of Water Resources (“DWR”)~~DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying co-generation facilities and qualifying small power production facilities (“QFs”) are treated as capital leases. The following table shows the future fixed capacity payments due under ~~qualifying facility (“QF”)~~the QF contracts that are treated as capital leases. ~~These~~(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)
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

(in millions)
2009	$	43
2010		50
2011		50
2012		50
2013		50
Thereafter		206
Total fixed capacity payments	$	449
Less: Amount representing interest		105
Present value of fixed capacity payments	$	344

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

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

Natural Gas Supply and Transportation Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation to transport natural gas from the points at which the Utility takes delivery 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 ~~September 30, 2008,~~March 31, 2009, the Utility’s undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2008	$	429
2009		804	$	486
2010		93		300
2011		80		118
2012		49		49
2013				42
Thereafter		199		157
Total	$	1,654	$	1,152

Payments for natural gas purchases and gas transportation services amounted to approximately ~~$2,227~~$456 million and ~~$1,603~~$797 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and March 31, 2008, ~~and September 30, 2007,~~ respectively.

Contingencies

PG&E Corporation

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

Utility

Spent Nuclear Fuel Storage Proceedings

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

The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2. Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete, and the initial movement of spent nuclear fuel to dry cask storage is expected to begin in June 2009.

After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding that there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.

In October 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit. Although the appellant did not seek to obtain an order prohibiting the Utility from loading spent fuel, the petition stated that they may seek a stay of fuel loading at the facility. On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding. The Utility’s brief on appeal was filed on April 8, 2009. No date has been set for oral argument.

If the Utility is unable to begin loading spent nuclear fuel by October 2010 for Unit 1 or May 2011 for Unit 2 and if the Utility is otherwise unable to increase its on-site storage capacity, the Utility would have to curtail or halt operations until such time as additional safe storage for spent fuel is made available.

On August 7, 2008, the U.S. Court of Appeals for the Federal Circuit issued an appellate order in the litigation pending against the DOE in which the Utility and other nuclear power plant owners seek to recover costs that 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 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. Although various motions by the DOE for reconsideration are still pending, the judge in the lower court conducted a status conference on January 15, 2009 and has scheduled another conference for July 9, 2009. The Utility expects that the final award will be approximately $91 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. 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.

Application to Recover Hydroelectric Facility Divestiture Costs

On April ~~14, 2008, the Utility filed an application with~~16, 2009, the CPUC ~~requesting authorization~~approved a decision to authorize the Utility to recover approximately $47 million, including ~~$12.2~~approximately $12 million of interest, of costs that the ~~costs it~~Utility incurred in connection with ~~the Utility’s~~its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. The Utility filed the application on April 14, 2008. These efforts were undertaken ~~at the direction of~~as required by the CPUC in ~~preparation for~~connection with the ~~planned~~proposed divestiture of the facilities to further the development of a competitive generation market in California. ~~In 2003, the~~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.subsequently withdrew this requirement. The Utility continues to own its hydroelectric generation assets. ~~On May 19, 2008, the CPUC’s Division of Ratepayer Advocates ("DRA") filed a protest to the Utility's application. On August 14, 2008, the DRA and the~~The Utility ~~agreed~~expects that the ~~Utility had supported its request~~rate adjustments necessary to recover these authorized costs will be combined with ~~appropriate and reasonable evidence. PG&E Corporation and~~other rate adjustments in the ~~Utility~~Utility’s annual electric rate true-up proceeding. These rate changes are ~~unable~~expected to ~~predict whether the CPUC will approve recovery of these costs.~~become effective in January 2010.

~~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 nine months ended September 30, 2008. The DWR remains legallyEnergy Efficiency Programs and ~~financially responsible for its 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. 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.

Incentive Ratemaking

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. Until the DWR’s obligations under its power purchase contracts are terminated, the CPUC is prohibited by 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~~previously established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the ~~2006-2008~~2006–2008 and ~~2009-2011~~2009–2011 program cycles. ~~The~~Under the existing incentive ratemaking mechanism, the maximum amount of ~~incentives~~revenue that the Utility ~~may receive~~could earn — and the maximum amount ~~of any reimbursement obligations~~that the Utility ~~may incur~~could be required to reimburse customers over the ~~2006-2008~~2006–2008 program cycle — is $180 million. On December 18, 2008, based on their first interim claims, the CPUC awarded interim incentive earnings to the utilities for their 2006–2007 program performance, subject to a holdback until completion of final measurement studies and a final verification report for the entire three-year program cycle. The ~~financial impact will depend on the amount of any shareholder incentives~~CPUC awarded the Utility ~~may receive~~$41.5 million in shareholder incentive revenues, representing 35% of $119 million estimated shareholder incentive revenues for the Utility’s energy efficiency program performance in 2006–2007.

On January 29, 2009, the CPUC established a new rulemaking proceeding to modify the existing incentive ratemaking mechanism for programs beginning in 2009 and future years, to adopt a new framework to review the utilities’ 2008 program performance, and to conduct a final review of the utilities’ performance over the 2006–2008 program period. On April 14, 2009, the CPUC issued a ruling setting forth the scope and schedule for the new rulemaking proceeding. The CPUC ordered the parties to participate in a settlement conference to begin on May 6, 2009 to resolve the utilities’ interim claims for 2008 performance and the utilities’ final claims for the entire 2006–2008 program period. If a settlement is not reached, the CPUC schedule calls for hearings to begin in June 2009.

Whether or ~~the amount of any reimbursement obligations~~not the Utility ~~may~~will receive any of the remaining $77 million in incentives for the 2006 and 2007 program years, whether the Utility will receive any additional incentives or incur a reimbursement obligation in 2009 based on the ~~level of energy efficiency savings actually achieved over~~second interim claim for 2008 performance, and whether the ~~three-year program cycle and when the applicable accounting standard for recognizing incentives~~final true-up in 2010 will result in a positive or ~~reimbursement obligations is met.~~negative adjustment remain uncertain.

Nuclear Insurance

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”).~~3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $39.3 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.)

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

In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the ~~Nuclear Regulatory Commission~~NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53.3 million of liability insurance.

~~Severance~~

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 September 30, 2008, the Utility estimated future severance costs will range from $29 million to $48 million, given the uncertainty of each of these variables. The Utility has recorded a liability of $29 million as of September 30, 2008. The following table presents the changes in the liability from December 31, 2007:

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

Environmental Matters

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under environmental laws. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances at former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of possible clean-up costs. The Utility reviews its remediation liability on a quarterly basis. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure using current technology, and considering enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement, and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. The Utility estimates the upper end of this cost range using possible outcomes that are least favorable to the Utility. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the ~~Utility's~~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 ~~$575~~$587 million at ~~September 30, 2008,~~March 31, 2009, and approximately ~~$528~~$568 million at December 31, ~~2007.~~2008. The ~~$575~~$587 million accrued at ~~September 30, 2008~~March 31, 2009 consists of:

·	~~Approximately $222~~approximately $48 million for remediation at the ~~Hinkley and Topock~~Utility’s natural gas compressor ~~sites;~~site located near Hinkley, California;

·	~~Approximately $83~~approximately $162 million for remediation at the Utility’s natural gas compressor site located in Topock, Arizona, near the California border;

·	approximately $82 million related to remediation at divested generation facilities;

·	~~Approximately $221~~approximately $240 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 $49~~ approximately $55 million related to remediation costs for fossil decommissioning sites.

Of the approximately ~~$575~~$587 million environmental remediation liability, approximately ~~$126~~$137 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately ~~$359~~$363 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~~Utility’s ultimate obligations may be subject to refund to customers. Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable from customers.

The ~~Utility's~~Utility’s undiscounted future costs could increase to as much as ~~$940 million~~$1 billion if the other potentially responsible parties are not financially able to contribute to these costs or if the extent of contamination or necessary remediation is greater than anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The amount of approximately ~~$940 million~~$1 billion 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~~Utility’s Diablo Canyon power plant uses a process known as ~~“once through~~“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~~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~~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~~The U.S. Supreme Court ~~agreed to~~granted review of the cost-benefit question and in April 2009 issued a decision reversing the Second Circuit ~~decision~~and finding permissible the EPA’s use of cost-benefit analysis to set national compliance standards for cooling water intake systems and variances to those standards. The EPA is currently revising its regulations regarding ~~the cost-benefit test and a decision is expected by mid-2009.~~cooling water intake systems. 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~~

Hourly paid 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, employers who fail to provide the mandated meal period must provide 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 pay the employee for this time. In April 2007, the California Supreme Court ruled that the payment required under this law 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.

The collective bargaining agreement between the Utility and the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”), which covers approximately 10,300 employees, does not provide certain employee groups a continuous 30-minute meal period. In June 2007, the Utility and the IBEW agreed that covered employees whose eight-hour shifts do not allow for an uninterrupted 30-minute meal break would be paid one hour of pay for each 30-minute meal period missed going back 39 months. Further, in July 2007, the Utility and IBEW established a joint committee 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 instituted use of a new payroll time sheet to ensure all missed meals are accurately recorded by employees and paid for by the Utility.

In connection with those employees whose eight-hour shifts do not allow for an uninterrupted 30-minute meal period, the Utility has paid $24 million as of September 30, 2008. Additionally, at September 30, 2008, the Utility accrued $5.7 million for probable future 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 this matter may have a material adverse impact on PG&E Corporation and the Utility’s financial condition or results of operations.

Tax Matters

In accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” PG&E Corporation and the ~~first quarter~~Utility do not expect the total amount of ~~2008,~~unrecognized tax benefits to change significantly within the next 12 months.

On January 30, 2009, PG&E Corporation reached a ~~settlement~~tentative agreement with the Internal Revenue Service (“IRS”) ~~appellate division for~~to resolve refund claims related to the 1998 and 1999 tax years ~~1997-2000. On July 9, 2008, PG&E Corporation was notified~~ that, if approved by the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) ~~had approved~~, would result in a cash refund of approximately $200 million plus interest. The refund would result in net income of approximately $50 million. Because the ~~settlement.~~ agreement is subject to Joint Committee approval, PG&E Corporation has not recognized any benefit associated with the potential refund.

As a result of the October 2008 IRS audit settlement of tax years 2001 through 2004, 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. In addition, on June 27, 2008, PG&E Corporation agreed to the revenue agent reports (“RARs”) from the IRS that reflected this agreement and resolved all significant 2001-2002 audit issues, except for issues related to synthetic fuel tax credits, and all 2003-2004 audit issues. On August 26, 2008, PG&E Corporation signed a separate closing agreement that favorably resolved the issues related to the synthetic fuel tax credits. 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 resolution of 2001-2004 audits, PG&E Corporation expects to receive acash refund of approximately ~~$310~~$294 million ~~and recognize after-tax income~~ in ~~the fourth quarter of 2008 of approximately $230 million. Approximately $180~~March 2009 (after applying $80 million of the refund ~~will be allocated~~ to ~~the Utility and approximately $60 million of the after-tax~~make a 2008 estimated 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 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.payment).

~~As of September 30, 2008,~~Currently, PG&E Corporation ~~had $268~~has approximately $60 million of federal capital loss carry forwards based on tax returns as filed ~~primarily resulting from~~and after the ~~disposition of NEGT stock in 2004. The~~ resolution of IRS audit of tax years 2001 through 2004. Of the ~~2001-2004 audits will 1) reduce the capital loss carry forwards by approximately $51~~$60 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~~the end of 2009.

The IRS is currently auditing tax years ~~2005-2007. For tax year~~2005 through 2007. In 2008, PG&E Corporation ~~has been~~began participating in the ~~IRS’~~IRS’s Compliance Assurance Process (“CAP”), a real-time audit process intended to expedite the resolution of issues raised during audits. To date, no material adjustments have been proposed for either the 2005 through 2007 audit or for the 2008 CAP, except for adjustments to reflect the rollover impact of items settled from prior audits. In March 2009, PG&E Corporation and the IRS signed an agreement to permit PG&E Corporation’s participation in the 2009 CAP.

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~~approximately $200 million of California capital loss carry forwards based on tax returns as filed, the majority of which will expire if not used by ~~December 2008, will expire.~~
the end of 2009.

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~~“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~~accruals, and the estimates of any additional reasonably possible losses, are reviewed quarterly and adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing such contingencies, PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s policy is to exclude anticipated legal costs.

The accrued liability for legal matters is included in PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s Current Liabilities -– Other in the Condensed Consolidated Balance Sheets, and totaled approximately ~~$47~~$64 million at ~~September 30, 2008~~March 31, 2009 and approximately ~~$78~~$72 million at December 31, ~~2007.~~

2008. After ~~considering the above~~consideration of these accruals, PG&E Corporation and the Utility do not expect that losses associated with legal matters ~~will~~would have a material adverse impact on their financial condition ~~or results~~and result of operations.

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ITEM 2: ~~MANAGEMENT'S~~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 ~~September 30, 2008.~~March 31, 2009. The Utility had approximately ~~$39~~$41 billion in assets at ~~September 30, 2008~~March 31, 2009 and generated revenues of approximately ~~$11~~$3.4 billion in the ~~nine~~three months ended ~~September 30, 2008.~~March 31, 2009.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility generates revenues mainly through the sale and delivery of electricity and natural gas at rates set by the CPUC and the FERC. Rates are set to permit the Utility to recover its authorized “revenue requirements” from customers. Revenue requirements are designed to allow the Utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in ~~utility~~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~~Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, ~~2007,~~2008, which, together with the information incorporated by reference into such report, is referred to in this quarterly report as the ~~“2007~~“2008 Annual Report.” Significant developments that have occurred since the ~~2007~~2008 Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed in this Quarterly Report on Form 10-Q.

This is a combined quarterly report of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. PG&E ~~Corporation's~~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~~Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries ~~which~~as well as the ~~Utility is required to consolidate under applicable accounting standards and~~accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain. This combined ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of PG&E Corporation and the Utility should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report, as well as the MD&A, the audited Consolidated Financial Statements, and the Notes to the Consolidated Financial Statements incorporated by reference in the ~~2007~~2008 Annual Report.

Summary of Changes in Earnings per Common Share and ~~Net~~ Income Available for Common Shareholders for the Three ~~and Nine~~ Months Ended ~~September 30, 2008~~March 31, 2009

~~For the three months ended September 30, 2008,~~ PG&E Corporation’s diluted earnings per common share (“EPS”) for the three months ended March 31, 2009 was ~~$0.83~~$0.65 per share, compared to ~~$0.77~~$0.62 per share for the same period in ~~2007.~~2008. For ~~the nine months ended September 30, 2008, PG&E Corporation’s diluted EPS was $2.24 compared to $2.22 for the same period in 2007. PG&E Corporation’s net income for~~ the three months ended ~~September 30, 2008~~March 31, 2009, PG&E Corporation’s income available for common shareholders increased by approximately ~~$26~~$17 million, or 9%8%, to ~~$304~~$241 million, compared to ~~$278~~$224 million for the same period in ~~2007. For the nine months ended September 30, 2008, net income increased by approximately $18 million, or 2%, to $821 million, compared to $803 million for the same period in 2007.~~2008.

The increase in ~~diluted~~ EPS and ~~net~~ income available for ~~the three months ended September 30, 2008 compared to the same period in 2007~~common shareholders is primarily due to the Utility’s return on equity (“ROE”) on higher authorized capital investments (representing a ~~$22~~$26 million increase in ~~net~~ income available for common shareholders as compared to the same period in ~~the prior year)~~2009). ~~The increase in diluted EPS and net income~~In addition, results for the ~~nine~~three months ended ~~September 30, 2008 compared to~~March 31, 2009 reflected a benefit of approximately $25 million because the ~~same period~~Utility incurred lower storm- and outage-related expenses in ~~2007 is primarily due to~~ the ~~Utility’s ROE on higher authorized capital investments (representing a $73 million increase in net income~~three months ended March 31, 2009 as compared to the same period in ~~the prior year),~~2008.

This increase in diluted EPS and income available for common shareholders was partially offset by ~~(1) higher storm and outage-related costs, largely due to severe winter weather that occurred in January 2008 (resulting in a $27~~approximately $26 million, ~~decrease in net income~~ as compared to the same period in 2008, attributable to higher uncollectible expenses due to the ~~prior year), (2)~~economic conditions in the Utility’s service territory, increased ~~operating~~employee severance costs, and ~~maintenance~~an increase in the liability for non-pension employee benefits reflecting recent stock market performance and lower assumed rates of return. Additionally, during the three months ended March 31, 2009, the Utility incurred higher expenses, to perform accelerated system-wide gas integrity surveys and associated ~~with the natural gas system (resulting in a $17~~remedial work which decreased income available from common shareholders by approximately $5 million, ~~decrease in net income~~ as compared to the same period in the prior 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 as compared to the same period in the prior year).2008.

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Key Factors Affecting Results of Operations and Financial Condition

PG&E ~~Corporation~~Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~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. Unlike the current GRC, which set revenue requirements for a four-year period (2007 through 2010), it is expected that the next GRC will set revenue requirements for the Utility’s electric and natural gas distribution operations and electric generation operations for a three-year period (2011 through 2013). From time to time, the Utility also files separate applications requesting the CPUC or the FERC to authorize additional revenue requirements for specific capital expenditure projects such as new power plants, gas or electric transmission facilities, installation of an advanced metering infrastructure, and reliability or system infrastructure improvements. The Utility’s revenues ~~can~~will also be affected by incentive ratemaking, ~~such as~~including the CPUC’s customer energy efficiency shareholder incentive mechanism. ~~The amount~~(See Note 11 of ~~incentives~~the Notes to the Condensed Consolidated Financial Statements.) In addition, the CPUC has authorized the Utility ~~may receive~~to recover 100% of its reasonable electric fuel and energy procurement costs and has established a timely rate adjustment mechanism to recover such costs. As a result, the ~~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~~Utility’s revenues and ~~2009-2011). (See “Regulatory Matters” below.) Finally, the outcome of regulatory proceedings may also~~costs can be affected by volatility in the prices of natural gas and ~~electricity as these costs are passed through to customers in the form of higher rates.~~electricity. (See “Risk Management Activities” below.)

·	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~~CPUC-authorized capital structure ~~including~~includes a 52% common equity ~~component, will be maintained through 2010.~~component. The ~~Utility’s current~~CPUC has authorized ~~cost of capital, including~~the Utility to earn a ROE of 11.35% on the equity component of its electric and natural gas distribution and electric generation rate ~~base,~~base. The Utility’s capital structure is set until 2011, and its cost of capital components, including an 11.35% ROE, will only be ~~maintained through 2010, unless~~changed before 2011 if the annual automatic adjustment mechanism established by the CPUC is triggered. If the 12-month October-through-September average yield for the Moody’s Investors Service utility bond index increases or decreases by more than 1% as compared to the applicable benchmark, the Utility can adjust its authorized cost of capital effective on January 1 of the following year. The Utility can also apply for an adjustment to either ~~the~~its capital structure or its cost of capital ~~sooner based on~~at any time in the event of extraordinary circumstances. ~~(See “Regulatory Matters” below.)~~

·	The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements are ~~primarily~~generally set ~~based on forecasted operating expenses and capital expenditures. The Utility’s revenue requirements are designed~~at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses as well as to earn an ROE ~~as well as to~~and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s net income available for shareholders. The Utility anticipates that it will incur higher expenses than originally forecasted in the GRC to maintain the aging infrastructure of its electric and natural gas systems and to improve operating and maintenance 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~~expenditures are higher ~~rate~~ than ~~forecasted,~~authorized levels, the Utility incurs associated depreciation, property tax, and interest ~~expense. The Utility~~expense but does not recover revenues to offset these expenses or earn an ROE onuntil the ~~higher level of~~ capital expenditures ~~until~~are added to rate base in future rate cases. Items that could cause higher expenses than provided for in the last GRC primarily relate to the Utility’s efforts to maintain its aging electric and natural gas systems infrastructure; to improve the reliability and safety of its electric and natural gas system; and to improve its information technology infrastructure, support, and security. In addition, the Utility expects that it will continue to incur higher costs to accelerate system-wide natural gas leak surveys and associated remedial work. (See “Results of Operations” below.) The ~~Utility’s financial condition~~Utility continually seeks to achieve operational efficiencies and ~~results of operations will be impacted by the amount of revenue requirements it is authorized~~improve reliability while creating future sustainable cost savings to ~~recover,~~offset these higher anticipated expenses. The Utility also seeks to make the amount and timing of its capital expenditures consistent with budgeted amounts and ~~whether the Utility is able to manage its operating costs and capital expenditures within authorized levels.~~ timing.

·	The Availability and Terms of Debt and Equity Financing. The amount and timing of the Utility’s future financing needs ~~for additional financing during 2008 and future years~~ will ~~be affected by~~depend on various factors, some of which include the conditions in the capital markets, the amount and timing of scheduled principal and interest payments on long-term debt, the amount and timing of planned capital expenditures, ~~as well as by~~and the amount and timing of interest payments related to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) The amount of the Utility’s ~~ability to make scheduled principal~~short-term financing will vary depending on the level of operating cash flows, seasonal demand for electricity and ~~interest payments, refinance debt, fund operations, deposit collateral in connection with its~~ natural gas, volatility in electricity and ~~electricity procurement hedging contracts,~~natural gas prices, and ~~make planned~~collateral requirements related to price risk management activity, among other factors. In order to maintain the Utility’s CPUC-authorized capital ~~expenditures, depends on the levels of its operating cash flow and access~~structure, PG&E Corporation will be required to contribute equity 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 $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 bears interest at 5.625%.Utility. The timing and amount of ~~PG&E Corporation’s~~these future equity contributions ~~to the Utility~~ will affect the timing and amount of any ~~PG&E Corporation~~future equity ~~issuances and/~~or debt issuances ~~which, in turn, will affect~~by PG&E ~~Corporation’s results~~Corporation. In March 2009, PG&E Corporation and the Utility issued $350 million and $550 million, respectively, of ~~operations and financial condition.~~senior unsecured notes. (See “Liquidity and Financial Resources” below.)

In addition to the key factors discussed above, PG&E ~~Corporation~~Corporation’s and the Utility’s future results of operations and financial condition are subject to the risk ~~factors discussed in the section entitled~~factors. (See “Risk Factors” in the ~~2007~~2008 Annual ~~Report and the section entitled “PART II Item 1A. Risk Factors” below.~~Report.)

3734

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~~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, estimated future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

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

·	the outcome of ~~regulatory proceedings, including~~ pending and future ~~ratemaking~~regulatory proceedings atand whether the ~~CPUC and the FERC;~~Utility is able to timely recover its costs through rates;

·	the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas ~~markets;~~markets, including the ability of the Utility and its counterparties to post or return collateral;

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

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

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

·	operating performance of the Diablo Canyon Power Plant (��Diablo Canyon”), the availability of nuclear fuel, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

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

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

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

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

·	the impact of changing wholesale electric or gas market rules, including 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, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on 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 outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the ~~2007~~2008 Annual ~~Report and the section entitled “PART II Item 1A. Risk Factors” below.~~Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

3835

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 and ~~2007:~~2008:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,							Three Months ended March 31,
(in millions)	2008			2007			2008			2007				2009			2008
Utility
Electric operating revenues	$	2,880		$	2,574		$	8,039		$	7,107			$	2,426		$	2,514
Natural gas operating revenues		794			705			2,946			2,714				1,005			1,219
Total operating revenues		3,674			3,279			10,985			9,821				3,431			3,733
Cost of electricity		1,282			998			3,406			2,606				883			1,027
Cost of natural gas		351			281			1,613			1,431				557			775
Operating and maintenance		982			950			3,009			2,788				1,059			1,036
Depreciation, amortization, and decommissioning		419			465			1,239			1,325				419			402
Total operating expenses		3,034			2,694			9,267			8,150				2,918			3,240
Operating income		640			585			1,718			1,671				513			493
Interest income		20			33			77			116				9			24
Interest expense		(170	)		(189	)		(528	)		(549	)			(173	)		(180	)
Other income (expense), net(1)		(5	)		9			14			28
Other income, net															21			19
Income before income taxes		485			438			1,281			1,266				370			356
Income tax provision		167			159			421			458				131			120
Income available for common stock	$	318		$	279		$	860		$	808
PG&E Corporation, Eliminations and Other(2)
Net Income															239			236
Preferred dividend requirement															3			3
Income available for common shareholders														$	236		$	233
PG&E Corporation, Eliminations, and Other(1)
Operating revenues	$	-		$	-		$	-		$	-			$	-		$	-
Operating expenses		1			3			2			6				-			-
Operating loss		(1	)		(3	)		(2	)		(6	)			-			-
Interest income		3			3			5			9				-			2
Interest expense		(8	)		(7	)		(22	)		(22	)			(8	)		(7	)
Other expense, net		(12	)		(2	)		(28	)		(6	)			(3	)		(14	)
Loss before income taxes		(18	)		(9	)		(47	)		(25	)			(11	)		(19	)
Income tax benefit		(4	)		(8	)		(8	)		(20	)			(16	)		(10	)
Net loss	$	(14	)	$	(1	)	$	(39	)	$	(5	)
Net gain (loss)														$	5		$	(9	)
Consolidated Total
Operating revenues	$	3,674		$	3,279		$	10,985		$	9,821			$	3,431		$	3,733
Operating expenses		3,035			2,697			9,269			8,156				2,918			3,240
Operating income		639			582			1,716			1,665				513			493
Interest income		23			36			82			125				9			26
Interest expense		(178	)		(196	)		(550	)		(571	)			(181	)		(187	)
Other income (expense), net(1)		(17	)		7			(14	)		22
Other income, net															18			5
Income before income taxes		467			429			1,234			1,241				359			337
Income tax provision		163			151			413			438				115			110
Net income	$	304		$	278		$	821		$	803
Net Income															244			227
Preferred dividend requirement of subsidiary															3			3
Income available for common shareholders														$	241		$	224


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

3936

Utility

The following presents the ~~Utility's~~Utility’s operating results for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 and ~~2007.~~2008.

Electric Operating Revenues

The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, the Utility relies on electricity provided under long-term contracts entered into by the California Department of Water Resources (“DWR”) to meet a material portion of the Utility’s customers’ demand (“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~~Utility’s electric operating revenues:

Three Months Ended Nine Months Ended

September 30,

September 30,

(in millions)
2008

2007

2008

2007

Electric revenues $ 3,255 $ 3,172 $ 9,044 $ 8,765
DWR pass-through revenues(1)
(375 ) (598 ) (1,005 ) (1,658 )
Total electric operating revenues $ 2,880 $ 2,574 $ 8,039 $ 7,107
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.

(2)These volumes exclude electricity provided by DWR.

	Three Months Ended
	March 31,
(in millions)	2009			2008
Electric operating revenues	$	2,821		$	2,841
DWR pass-through revenues (1)		(395	)		(327	)
Utility electric operating revenues	$	2,426		$	2,514

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

The Utility’s electric operating revenues ~~increased by approximately $306 million, or 12%,~~decreased in the three months ended ~~September 30, 2008 and~~March 31, 2009 by approximately ~~$932~~$88 million, or ~~13%~~approximately 4%, ~~in the nine months ended September 30, 2008,~~ compared to the same ~~periods~~period in ~~2007~~2008 mainly due to the following factors:

·	Electricity procurement costs passed through to customers ~~increased~~decreased by approximately $291 million in the three months ended September 30, 2008 and approximately $798 million in the nine months ended 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.$147 million. (See “Cost of Electricity” below.)

·	~~Electric operating revenues~~Public purpose program costs passed through to ~~fund~~customers decreased by approximately $29 million, as 2009 marks the beginning of a new program cycle that will run through 2011. Revenues and expenses increase as programs become more established and enrollment increases. The public purpose ~~and~~programs primarily consist of the electric energy efficiency ~~programs increased by approximately $36 million in the three months ended September 30, 2008~~programs; low-income energy efficiency programs; research, development, and ~~approximately $175 million in the nine months ended September 30, 2008 primarily due to an increase in expenses for these~~demonstration programs; and renewable energy programs. (See “Operating and Maintenance” below.)

These decreases were partially offset by the following:

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

·	~~Electric transmission revenues~~Revenues associated with separately funded projects placed in service, including Gateway Generating Station and the new steam generators at Diablo Canyon, increased by approximately $13 million in the three months ended September 30, 2008 and approximately $40 million in the nine months ended September 30, 2008, primarily due to an increase in rates as authorized in the current TO rate case.$46 million.

·	Other miscellaneous increases in electric operating revenues ~~increased by~~of 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 SmartMeterTM ~~advanced metering project (see “Capital Expenditures” below for further discussion of SmartMeter~~TM). $16 million.

These increases were partially offset by a decrease of approximately $76 million in the three months ended September 30, 2008 and approximately $210 million in the nine months ended September 30, 2008, representing the amount of revenue collected during the comparable periods in 2007 for payment of principal and interest on the rate reduction bonds (“RRBs”) that matured in December 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 the remainder of 2009 and 2010 are expected to increase as authorized by the CPUC in the 2007 GRC. The Utility’s electric operating revenues for future years are also expected to increase as authorized by the FERC in the TO rate cases. Additionally, on April 16, 2009, the CPUC approved a decision authorizing the Utility to recover approximately $47 million, including approximately $12 million of interest, of costs that the Utility incurred in connection with its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. (See “Regulatory Matters” below.)

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

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

Cost of Electricity

The ~~Utility's~~Utility’s cost of electricity includes electricity purchase costs, the cost of fuel used by its generation facilities, and the cost of fuel supplied to other facilities under tolling ~~agreements, and~~agreements. These costs are passed through to customers. The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See ~~Note~~Notes 7 and 8 of the Notes to the Condensed Consolidated Financial ~~Statements for further information.~~Statements.) ~~The Utility’s cost of purchased power, 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 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~~Utility’s cost of electricity and the total amount and average cost of purchased power:

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
(in millions)	2008			2007			2008			2007			2009			2008
Cost of purchased power	$	1,334		$	990		$	3,511		$	2,609		$	870		$	1,038
Proceeds from surplus sales allocated to the Utility		(90	)		(26	)		(225	)		(112	)		(31	)		(46	)
Fuel used in own generation		38			34			120			109
Fuel used in owned generation														44			35
Total cost of electricity	$	1,282		$	998		$	3,406		$	2,606		$	883		$	1,027
Average cost of purchased power per kWh(1)	$	0.091		$	0.088		$	0.089		$	0.087		$	0.079		$	0.088
Total purchased power (in millions of kWh)		14,726			11,291			39,377			29,975			10,987			11,757

(1) Kilowatt-hour

The ~~Utility's~~Utility’s total cost of electricity ~~increased by approximately $284 million, or 28%,~~decreased in the three months ended ~~September 30, 2008 and~~March 31, 2009 by approximately ~~$800~~$144 million, or ~~31%~~14%, ~~in the nine months ended September 30, 2008,~~ compared to the same ~~periods~~period in ~~2007. These increases were~~2008. This decrease was primarily ~~driven by increases~~due to a 10% decrease in the average cost of purchased power, as well as a 7% decrease in the total volume of purchased ~~power of 3,435 million kilowatt-hours (“kWh”), or 30%, for~~power. The decrease in the three months ended September 30, 2008 and 9,402 million kWh, or 31%, for the nine months ended 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 theaverage cost of purchased power was primarily driven by lower market prices for electricity and gas. Decreases in industrial and residential demand as well as milder weather in the ~~three and nine months ended September 30, 2008 compared~~first quarter of 2009 contributed to the same periods in 2007. In addition, during the nine months ended 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 increasedecreases in the volume of purchased ~~power for the same period in 2007 was lower.~~power.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power that the Utility produces, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or ~~expire. The Utility expects that its cost of electricity in 2008 will continue to increase compared to 2007 as~~renegotiated. In addition, the ~~Utility continues to purchase replacement power due to the DWR’s termination of its power purchase agreement with Calpine Corporation in December 2007. Output~~output from the Utility’s hydroelectric generation facilities is dependent on levels of precipitation and could impact the volume of purchased power. Volatility in natural gas prices ~~is expected to~~will also impact the Utility’s cost of ~~electricity for the remainder of 2008 and future years.~~ electricity.

The Utility’s future cost of electricity also may be affected by federal or state legislation or rules ~~which~~that may be adopted to regulate the emissions of greenhouse gases from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. ~~As directed by recent California legislation,~~In particular, costs are likely to increase in the ~~CPUC has already adopted an interim~~future when California’s statewide greenhouse gas emissions ~~performance standard that would apply to electricity procured or generated by the Utility.~~reduction law is implemented.

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout California for delivery to the ~~Utility's~~Utility’s distribution system, which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

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

		Three Months Ended				Nine Months Ended				Three Months Ended
		September 30,				September 30,				March 31,
(in millions)		2008		2007		2008		2007		2009		2008
Bundled natural gas revenues		$	709	$	620	$	2,699	$	2,469	$	923	$	1,142
Transportation service-only revenues			85		85		247		245		82		77
Total natural gas operating revenues		$	794	$	705	$	2,946	$	2,714	$	1,005	$	1,219
Average bundled revenue per Mcf(1) of natural gas sold		$	20.85	$	17.22	$	13.36	$	12.35	$	9.14	$	10.11
Total bundled natural gas sales (in millions of Mcf)			34		36		202		200		101		113


(1) One thousand cubic feet	(1) One thousand cubic feet

The ~~Utility's~~Utility’s natural gas operating revenues ~~increased by approximately $89 million, or 13%,~~decreased in the three months ended ~~September 30, 2008 and~~March 31, 2009 by approximately ~~$232~~$214 million, or 9%18%, ~~in the nine months ended September 30, 2008,~~ compared to the same ~~periods~~period in ~~2007. These increases were~~2008. This decrease was primarily due to ~~an increase~~a decrease in bundled natural gas revenues of approximately ~~$89~~$219 million, or ~~14%~~19%, in the three months ended September 30, 2008 and approximately $230 million, or 9%, in the nine months ended September 30, 2008. The increases in bundled natural gas revenues for both periods reflect an overall increaseas a result of decreases in the cost of natural gas, ~~over these periods of approximately $70 million and $182 million for the three and nine months ended September 30, 2008 (see~~which are passed through to customers. (See “Cost of Natural Gas” below)~~, an increase in~~. This decrease was partially offset by increased base revenue requirements as a result of attrition adjustments as authorized in the 2007 ~~GRC of approximately $6 million and $17 million for the three and nine months ended September 30, 2008, and an increase in natural gas revenues to fund the SmartMeter~~TM ~~advanced metering project of approximately $9 million and $17 million for the three and nine months ended September 30, 2008.~~GRC.

Future natural gas operating revenues will be impacted by changes in the cost of natural gas, the Utility’s gas transportation rates, natural gas throughput volume, and other factors. For 2008 through 2010, the Gas Accord IV settlement agreement provides afor an overall modest increase in the revenue requirements and rates for the Utility’s gas transmission and storage services. In addition, the Utility’s natural gas operating revenues for distribution are expected to increase through 2010 ~~due to~~as a result of revenue requirement increases authorized ~~GRC attrition adjustments and an increase~~by the CPUC in ~~authorized revenue requirements relating~~the 2007 GRC. Finally, the Utility may recognize incentive revenues to the ~~SmartMeter~~TM ~~advanced metering project.~~
extent that it achieves the CPUC’s energy efficiency goals.

Cost of Natural Gas

The ~~Utility's~~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 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~~Notes 7 and 8 of the Notes to the Condensed Consolidated Financial ~~Statements for further information.~~Statements.)

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

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
(in millions)	2008		2007		2008		2007		2009		2008
Cost of natural gas sold	$	314	$	239	$	1,517	$	1,299	$	515	$	754
Cost of natural gas transportation		37		42		96		132
Transportation cost of natural gas sold										42		21
Total cost of natural gas	$	351	$	281	$	1,613	$	1,431	$	557	$	775
Average cost per Mcf of natural gas sold	$	9.24	$	6.64	$	7.51	$	6.50	$	5.10	$	6.67
Total natural gas sold (in millions of Mcf)		34		36		202		200		101		113

The ~~Utility's~~Utility’s total cost of natural gas ~~increased~~decreased in the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 by approximately ~~$70~~$218 million, or ~~25%, and by approximately $182 million, or 13%~~28%, compared to the same ~~periods~~period in ~~2007,~~2008, primarily due to ~~increases~~a decrease in the average market price of natural gas ~~purchased~~and a decrease in the ~~three and nine months ended September 30, 2008. For the nine months ended September 30, 2008, the increase was partially offset by an approximately $23 million refund the Utility received as part~~volume of ~~a settlement with TransCanada’s Gas Transmission Northwest Corporation for 2007~~natural gas ~~transmission capacity rates.~~sold.

The ~~Utility's~~Utility’s future cost of natural gas ~~which will be passed through to customers,~~ will be impacted by ~~both North American and global~~the market ~~forces. Market forces include temperature variability, supply availability, customer demand, economic and financial conditions, liquefied~~price of natural gas, ~~availability,~~and changes in customer demand. In addition, the Utility’s future cost of gas also may be affected by federal or state legislation or rules to regulate the emissions of greenhouse gases from the Utility’s natural gas ~~storage,~~transportation and ~~industry perceptions of risks that may affect either availability or demand, such as~~distribution facilities and from natural gas consumed by the ~~possibility of hurricanes in the gas-producing regions of the Gulf of Mexico, or protracted heat waves that may increase gas-fired electric demand from high air conditioning loads.~~Utility’s customers.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the ~~Utility's~~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 ~~$32~~$23 million, or ~~3%, and approximately $221 million, or 8%~~2%, in the three ~~and nine~~ months ended ~~September 30, 2008, respectively,~~March 31, 2009 compared to the same ~~periods~~period in ~~2007. Expenses increased~~2008. Operating and maintenance expenses grew mainly due to a $39 million increase in wage and benefit-related costs, a $18 million increase in uncollectible customer accounts as a result of declining economic conditions and rising unemployment in the ~~following factors:~~

·	Public purpose program and customer energy efficiency incentive program expenses increased by approximately $48 million and $187 million in the three and nine months ended September 30, 2008 primarily due to increased customer participation and increased marketing of new and existing programs, including the California Solar Initiative program and the Self-Generation Incentive Program. Of these changes, approximately $36 million and $175 million, respectively, were recovered in electric operating revenues and less than $1 million and $14 million, respectively, were recovered in natural gas operating revenues. 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 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, the Utility has requested that the CPUC permit the Utility to recover approximately $8 million from its customers. There was no similar storm in the same period in 2007.

·	Labor costs increased by approximately $12 million and $29 million in the three and nine months ended 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 decreased by approximately $7 million and $12 million in the three and nine months ended September 30, 2008, respectively, due to increases in reserves during 2007 for which there were no similar increases in 2008.

·	Costs decreased by approximately $12 million in the three months ended September 30, 2008 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 $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 related to software maintenance contracts.

·	~~Advertising decreased by approximately $9 million and $10 million in the three and nine months ended September 30, 2008 as compared to the same period in 2007.~~

·	Costs decreased by approximately $12 million for the three and nine months ended September 30, 2008 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 Condensed Consolidated Financial Statements for a discussion of California labor code issues.)

·	Costs decreased by approximately $9 million for the 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 various employee positions.

Utility’s service territory, severance costs of $8 million incurred in connection with the consolidation of some regional facilities, and increased labor and other costs of $8 million related to accelerated natural gas leak surveys. In addition, ~~there was an aggregate increase~~operating and maintenance expenses for the three months ended March 31, 2008 reflected a decrease of approximately ~~$12 million and $7~~$29 million in the ~~three~~Utility’s accrual for employee vacation pay, contributing to the comparative increase in operating and ~~nine~~maintenance expenses for the three months ended ~~September 30,~~March 31, 2009. These increases were partially offset by decreases in public purpose program expenses of $38 million, and decreases in labor costs of $38 million compared to those incurred in 2008 ~~respectively, representing~~as a result of the January 2008 winter storm. Additionally, other miscellaneous operating and maintenance expenses ~~that changed from~~decreased by approximately $3 million, as compared to the ~~comparable periods~~same period in ~~2007.~~2008.

Operating and maintenance expenses are influenced by wage ~~inflation, benefits,~~inflation; benefits; property ~~taxes,~~taxes; the timing and length of Diablo Canyon refueling outages; storms, wild fires, and other events causing outages and damages in the Utility’s service territory; environmental remediation ~~costs,~~costs; legal ~~costs,~~costs; material ~~costs,~~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 laborinfrastructure 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.~~system. (See ~~"Risk Factors"~~“Risk Factors” in the ~~2007~~2008 Annual Report.) In particular, the Utility has begun work associated with system-wide gas leak surveys and targets completing this work in a little more than a year. The Utility forecasts that it will spend up to $100 million in 2009 to perform the accelerated gas leak surveys and associated remedial work. The Utility also expects that it will incur higher expenses in future periods to obtain or comply with ~~the~~permitting requirements, ofincluding costs associated with renewed FERC licenses for the Utility’s hydroelectric generation facilities. ~~The~~To help offset these increased costs, the Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable ~~cost-savings and to offset increased spending to address operational issues and increasing~~ cost ~~of materials.~~
savings.

Depreciation, Amortization, and Decommissioning

~~The Utility's~~In the three months ended March 31, 2009, the Utility’s depreciation, amortization, and decommissioning expenses ~~decreased~~increased by approximately ~~$46~~$17 million, or ~~10% in the three months ended September 30, 2008 and approximately $86 million, or 6%~~4%, ~~in the nine months ended September 30, 2008,~~ as compared to the same periods in 2007, mainly due to decreases in amortization expense of approximately $73 million and $197 million, respectively, related to the 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 recordedperiod in 2008. ~~These decreases were partially offset by increases~~There was a $26 million increase to depreciation expense ~~of approximately $27 million in the three months ended September 30, 2008 and approximately $111 million in the nine months ended September 30, 2008~~ primarily due to ~~plant~~capital additions and depreciation rate changes as authorized in the 2007 GRC and the current TO rate case. This increase was partially offset by decreases of approximately $9 million in decommissioning expense and amortization expense related to the energy recovery bonds (“ERBs”).

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 ~~September 30, 2008,~~March 31, 2009, the Utility’s interest income decreased by approximately ~~$13~~$15 million, or ~~39%~~63%, as compared to the same period in ~~2007. Interest income decreased by $10 million~~2008 primarily due to lower interest rates earned on ~~funds~~restricted cash held ~~in escrow~~ related to ~~disputed claims and a lower escrow balance reflecting settlements of~~Chapter 11 disputed claims. ~~There was an additional decrease~~(See Note 10 of ~~approximately $3 million in other interest income.~~

In the ~~nine months ended September 30, 2008, the Utility’s interest income decreased by approximately $39 million, or 34%, as compared~~Notes to the same period in 2007 when the Utility received approximately $16 million in interest income on a federal tax refund. In addition, there was a decrease of $26 million in interest income, primarily due to lower interest rates earned on funds held in escrow related to disputed claims and a lower escrow balance reflecting settlements of disputed claims. These decreases were partially offset by an increase of approximately $3 million in other interest.Condensed Consolidated Financial Statements.)

The Utility’s interest income in ~~2008~~2009 and future periods will be primarily affected by changes in the balance held in escrow related to disputed claims and changes in interest rate levels.

Interest Expense

In the three ~~and nine~~ months ended ~~September 30, 2008, there was a decrease of~~March 31, 2009, the Utility’s interest expense decreased by approximately ~~$19 million, or 10%, and $21~~$7 million, or 4%, ~~respectively,~~ as compared to the same ~~periods~~period in ~~2007.~~2008. Interest expense decreased primarily due to the following factors:

·	Interest expense decreased by approximately ~~$18~~$14 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 September 30, 2008, and approximately $21 million in the nine months ended September 30, 2008, due to the reduction in the outstanding balance of ERBs and the maturity of the RRBs in December 2007.

·	Interest expense on pollution control bonds decreased by approximately $6$7 million ~~in the three months ended September 30, 2008 and $13 million in the nine months ended September 30, 2008,~~ due to the repurchase of auction rate pollution control bonds in March and April ~~2008~~2008. The Utility partially refunded these bonds in September and ~~a decrease in~~October 2008. Additionally, interest expense decreased due to lower interest rates on outstanding variable rate pollution control bonds.

·	Interest expense decreased by approximately ~~$16~~$4 million ~~in the nine months ended September 30, 2008,~~ primarily due to lower interest rates affecting various balancing accounts.

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

These decreases were partially offset by additional interest expense of approximately ~~$16~~$22 million ~~in the three months ended September 30, 2008, and approximately $50 million in the nine months ended September 30, 2008,~~primarily related to ~~$1.2~~$2.4 billion in senior notes that were issued in 2008 and March ~~and December 2007 and $600 million in senior notes issued in March 2008.~~2009.

The Utility’s interest expense in ~~2008~~2009 and future periods will be impacted by changes in interest rates, as well as by changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is ~~issued (see~~issued. (See “Liquidity and Financial Resources” ~~below for further discussion).~~

~~Other Income (Expense), Net~~below.)

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~~In the three months ended March 31, 2009, the Utility’s income tax expense increased by approximately $8$11 million, or 5%9%, ~~for the three months ended September 30, 2008 and decreased by approximately $37 million, or 8%, for the nine months ended September 30, 2008,~~ as compared to the same ~~periods~~period in ~~2007.~~2008. The effective tax rates for the three months ended ~~September 30,~~March 31, 2009 and 2008 were 35.3% and ~~2007 were 34.1% and 36.0%~~33.6%, respectively. The ~~effective tax rates for the nine months ended September 30, 2008 and 2007 were 32.6% and 35.9%, respectively. The decreases in the~~lower effective tax rate ~~for~~in 2008 was primarily the result of an Internal Revenue Service (“IRS”) audit settlement included in the three ~~and nine~~ months ended ~~September 30, 2008 were primarily due to~~March 31, 2008. No similar amount was recorded in the ~~IRS’ approval of the Utility’s change~~same period 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”.)

2009.

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

PG&E ~~Corporation's~~Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E ~~Corporation's~~Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E ~~Corporation's~~Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 9.50% Convertible Subordinated Notes and 5.75% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 as compared to the same period in ~~2007.~~2008.

~~Other Expense, Net~~

PG&E Corporation's other expense increased by approximately $10 million, or 500%, for the three months ended September 30, 2008, and approximately $22 million, or 367%, for the nine months ended September 30, 2008 primarily due to an increase in investment losses in the rabbi trusts related to the 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,~~The Utility’s ability to fund ~~electricity~~operations depends on the levels of its operating cash flow and ~~natural gas purchases on behalf of customers, collateral requirements for commodity contracts and, for short periods of time,~~access to the capital ~~expenditures, among other things.~~markets. The ~~level~~levels of the ~~Utility's~~Utility’s operating cash and short-term debt ~~fluctuates~~fluctuate as a result of seasonal demand for electricity and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, ~~and the amount and timing of capital expenditures,~~ among other factors. The Utility generally utilizes long-term senior unsecured debt issuances and equity ~~issuances, while maintaining its CPUC-authorized capital structure,~~contributions from PG&E Corporation to fund debt maturities and capital ~~expenditures.~~expenditures, and relies on short-term debt to fund temporary financing needs.

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

Credit Facilities and Short-Term Borrowings

At March 31, 2009, PG&E Corporation ~~funds equity contributions to~~had a $200 million revolving credit facility and the Utility ~~through~~had a $2.0 billion revolving credit facility. Commitments from Lehman Brothers Bank, FSB (“Lehman Bank”) represented approximately $13 million, or 7%, and approximately $60 million, or 3%, of the ~~issuance~~total borrowing capacity under PG&E Corporation’s and the Utility’s revolving credit facilities, respectively. On April 27, 2009, PG&E Corporation and the Utility amended their revolving credit facilities and removed Lehman Bank as a lender. As a result, PG&E Corporation now has a $187 million revolving credit facility and the Utility has a $1.94 billion revolving credit facility.

The Utility has a $1.75 billion commercial paper program, the borrowings from which are used primarily to cover fluctuations in cash flow requirements. Liquidity support for these borrowings is provided by available capacity under the revolving credit facility. At March 31, 2009, the Utility had $385 million of commercial paper outstanding at an average yield of approximately 1.15%.

The following table summarizes PG&E Corporation’s and the Utility’s short-term borrowings and outstanding credit facilities at March 31, 2009:

(in millions)			At March 31, 2009
Authorized Borrower	Facility	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	Revolving credit facility	February 2012	$	200	(1)	$	-	$	-	$	-	$	200
Utility	Revolving credit facility	February 2012		2,000	(2)		295		-		385		1,320
Total credit facilities			$	2,200		$	295	$	-	$	385	$	1,520

(1) Includes a $50 million sublimit for letters of credit and $100 million sublimit for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days.
(2) Includes a $950 million sublimit for letters of credit and $200 million sublimit for swingline loans.

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary covenants for credit facilities of their type, including covenants limiting liens to those permitted under the senior notes’ indenture, mergers, sales of all or substantially all of the Utility’s assets, and other fundamental changes. In addition, both PG&E Corporation and the Utility are required to maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65%, and PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and ~~long-term debt.~~at least 70% of the voting securities of the Utility. At March 31, 2009, PG&E Corporation and the Utility met all of these requirements.

2009 Financings

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~~Notwithstanding 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~~were able to issue $350 million and $550 million, respectively, of senior unsecured notes in March 2009. Proceeds from the ~~Utility’s cash flow from operations, existing sources of liquidity, and access~~senior notes offerings were used 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, for general working capital purposes, 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 September 30, 2008, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $251 million and restricted cash of approximately $1.3 billion. At September 30, 2008, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $194 million;repay outstanding commercial paper, which the Utility had cash and cash equivalents of approximately $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 filed in the Utility’s reorganization proceeding under 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~~issued 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 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 $273~~pay off $600 million of letters of credit and $533 million of borrowings outstanding under its $2.0 billion working capital facility. The Utility also treats the amount of its outstanding commercial paper as a reduction to the amount available under its working capital facility. As of September 30, 2008, the Utility had $802 million of outstanding commercial paper. As of October 31, 2008, the Utility 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.~~notes that matured on March 1, 2009.

On October 21, 2008, the Utility issued $600 million principal amount of 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 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 on the October bonds was 1.75%. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for a further discussion of these bonds.) 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.

~~During the nine months ended September 30, 2008,~~ PG&E Corporation issued ~~4,023,421~~4,700,796 shares of common stock upon exercise of employee stock options ~~for the account of 401(k) participants,~~ and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating approximately ~~$150~~$96 million of ~~cash. In February 2008 and July 2008,~~cash through March 31, 2009. Also, in the first quarter of 2009, PG&E Corporation contributed ~~$50~~$528 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~~

Future Financing Needs

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

Assuming that PG&E Corporation and the Utility can access the capital markets on reasonable terms, PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures.

Dividends

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, the Utility paid common stock dividends totaling ~~$447~~$156 million ~~including $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, held approximately 7% of the Utility common stock. Effective August 29, 2008, PG&E Holdings LLC, was dissolved, and the shares subsequently cancelled.Corporation.

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, PG&E Corporation paid common stock dividends totaling $433 million, including $28 million to 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 was dissolved, and the shares subsequently cancelled.

$143 million. On ~~September 17, 2008,~~February 18, 2009, the Board of Directors of PG&E Corporation declared a dividend of ~~$0.39~~$0.42 per share, totaling ~~$140~~$154 million, which was paid on ~~October~~April 15, ~~2008~~2009 to shareholders of record on ~~September 30, 2008.~~March 31, 2009.

During the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling ~~$10~~$3 million. On ~~September 17, 2008,~~February 18, 2009, the Board of Directors of the Utility declared a cash dividend totaling $3 million on its outstanding series of preferred stock, payable on ~~November~~May 15, ~~2008,~~2009 to ~~preferred~~ shareholders of record on ~~October 31, 2008.~~April 30, 2009.

4743

Utility

Operating Activities

The ~~Utility's~~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~~Utility’s cash flows from operating activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ were as follows:

	Nine Months Ended						Three Months Ended
	September 30,						March 31,
(in millions)	2008			2007			2009			2008
Net income	$	870		$	818		$	239		$	236
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction		1,337			1,417
Depreciation, amortization, and decommissioning								456			437
Allowance for equity funds used during construction								(25	)		(20	)
Deferred income taxes and tax credits, net		470			(35	)		234			160
Other changes in noncurrent assets and liabilities		55			270			(48	)		106
Gain on sale of assets		(1	)		(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(179	)		(82	)		298			88
Inventories		(153	)		(92	)		166			107
Accounts payable		(85	)		(315	)		(107	)		149
Income taxes receivable/payable		208			228			95			(20	)
Regulatory balancing accounts, net		(94	)		(238	)		(180	)		(356	)
Other current assets		(125	)		120			34			104
Other current liabilities		(80	)		35			(386	)		65
Other		(3	)		(32	)		1			(2	)
Net cash provided by operating activities	$	2,220		$	2,093		$	777		$	1,054

In the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, net cash provided by operating activities ~~increased by~~decreased approximately ~~$127~~$277 million ~~from~~compared to the same period in ~~2007.~~

~~In the nine months ended September 30, 2008,~~2008. This decrease was primarily due to an increase in net ~~cash provided by operating~~collateral paid of approximately $457 million. The increase in net collateral paid, which is primarily related to price risk management 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~~a result 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 ~~operating~~the Utility’s exposure to counterparties’ credit risk, generally reflecting declining natural gas prices. Collateral payables and receivables are included in Other changes in noncurrent assets and liabilities, ~~positively impacted~~Other current assets, and Other current liabilities in the table above. This cash ~~flows during~~outflow was partially offset by tax refunds of approximately $163 million related to the ~~period:~~Utility’s portion of the settlement of the IRS audits of PG&E Corporation’s consolidated tax returns for tax years 2001 through 2004.

·	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 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 paid primarily related to price risk management activities increased by approximately $155 million between December 31, 2007 and September 30, 2008 as a result of changes in the Utility’s exposure to counterparties’ credit risk. Collateral payables and receivables are included in the Other changes in noncurrent assets and liabilities, Other current assets, and Other current liabilities in the table above.

·	Regulatory balancing accounts, net under-collection increased by approximately $94 million between December 31, 2007 and September 30, 2008, primarily due to an increase of approximately $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 also was partially offset by a refund of approximately $230 million the Utility received from the California Energy Commission (“CEC”). 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:

·	~~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, futureFuture operating cash flow will be impacted by the timing of cash collateral payments and receipts related to price risk management activity, among other 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.

On January 30, 2009, PG&E Corporation reached a tentative agreement with the IRS to resolve refund claims related to the 1998 and 1999 tax years that, if approved by the U.S. Congress’s Joint Committee on Taxation (“Joint Committee”), would result in a cash refund of approximately $200 million, plus interest. The ~~CPUC has established~~Joint Committee’s decision is currently expected in the second quarter of 2009, and if approved, PG&E Corporation expects to receive the refund by the end of 2009. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a ~~balancing account mechanism~~discussion of “Tax Matters.”) Additionally, the extension by the American Recovery and Reinvestment Act of 2009 of “bonus depreciation” for an additional year is expected to ~~adjust~~have a positive impact on operating cash flows in 2009 and 2010.

In addition, the Utility’s ~~electric~~future operating cash flow may also be impacted by the amount and timing of funding obligations associated with nuclear decommissioning and employee benefits. As a result of lower assumed rates ~~whenever the forecasted aggregate over-collections or under-collections~~ of return and declining investment returns, the Utility’s ~~electric procurement costs for the current year exceed 5%~~obligations to fund decommissioning of ~~the Utility's prior year~~its nuclear generation ~~revenues, excluding generation revenues for DWR contracts. In accordance with this mechanism, on August 21, 2008, the CPUC approved the Utility’s request~~facilities and to ~~collect from customers the forecasted 2008 end-of-year under-collection~~secure payment of ~~procurement costs, due mainly to rising natural gas costs~~employee benefits under pension 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.~~other postretirement benefit plans may increase. The Utility ~~will~~believes that it is probable that any increase in these obligations would be ~~updating its forecasted electricity procurement costs in November, for inclusion in the Annual Electric True-Up, which will adjust rates on January 1, 2009.~~recoverable through rates. (See “Regulatory Matters” below.)

Investing Activities

The ~~Utility's~~Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and 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~~Utility’s cash flows from investing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ were as follows:

	Nine Months Ended						Three Months Ended
	September 30,						March 31,
(in millions)	2008			2007			2009			2008
Capital expenditures	$	(2,691	)	$	(2,035	)	$	(1,079	)	$	(853	)
Proceeds from sale of assets		21			15			2			6
Increase in restricted cash		(3	)		(32	)
Decrease in restricted cash								11			2
Proceeds from nuclear decommissioning trust sales		1,121			703			387			164
Purchases of nuclear decommissioning trust investments		(1,161	)		(805	)		(412	)		(117	)
Net cash used in investing activities	$	(2,713	)	$	(2,154	)	$	(1,091	)	$	(798	)

Net cash used in investing activities increased by approximately ~~$559~~$293 million in the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 compared to the same period in ~~2007,~~2008. This increase was primarily due to an increase of approximately ~~$656~~$226 million in capital expenditures for installing the SmartMeter™ advanced metering infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

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

Financing Activities

The Utility’s cash flows from financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ were as follows:

Nine Months Ended

September 30,

(in millions)
2008

2007

Borrowings under accounts receivable facility and working capital facility $ 533 $ 600
Repayments under accounts receivable facility and working capital facility (250 ) (300 )
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 693 690
Long-term debt repurchased (454 ) -
Rate reduction bonds matured - (217 )
Energy recovery bonds matured (260 ) (251 )
Equity contribution 90 200
Common stock dividends paid (426 ) (381 )
Preferred stock dividends paid (10 ) (10 )
Other (31 ) 29
Net cash provided by financing activities $ 409 $ 451

	Three Months Ended
	March 31,
(in millions)	2009			2008
Net repayments under revolving credit facility	$	-		$	(250	)
Net issuance (repayments) of commercial paper, net of discount of $2 million in 2009 and $1 million in 2008		96			(198	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $12 million in 2009 and $2 million in 2008		538			598
Long-term debt matured or repurchased		(600	)		(300	)
Energy recovery bonds matured		(89	)		(83	)
Preferred stock dividends paid		(3	)		(3	)
Common stock dividends paid		(156	)		(142	)
Equity contribution		528			50
Other		2			(7	)
Net cash provided by (used in) financing activities	$	316		$	(335	)

In the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, net cash provided by financing activities ~~decreased~~increased by approximately ~~$42~~$651 million compared to the same period in ~~2007.~~2008. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which ~~depends~~depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

~~Operating Activities~~

With the exception of dividend payments, interest, the senior notes issuance of $350 million in March 2009, tax refunds of $131 million, and transactions between PG&E ~~Corporation's consolidated cash flows from operating activities consist mainly of billings to~~Corporation and 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,~~had no material cash flows on a stand-alone basis ~~did not have any material cash flow associated with operating activities~~ for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 and ~~2007.~~2008.

~~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 nine months ended 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 nine months ended 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~~Utility’s generation activities. In addition to those commitments disclosed in the ~~2007~~2008 Annual Report and those arising from normal business activities, PG&E ~~Corporation~~Corporation’s and the Utility’s commitments at ~~September 30, 2008~~March 31, 2009 include ~~$200~~$350 million of ~~5.625%~~5.75% Senior Notes issued by PG&E Corporation due ~~November 30, 2017, $400~~April 1, 2014, and $550 million of ~~6.35%~~6.25% Senior Notes ~~due February 15, 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,~~issued by the Utility ~~issued $600 million of 8.25% Senior Notes~~ due ~~October 15, 2018. In addition, on October 29,~~March 1, 2039. (See the 2008 ~~the California Pollution Control Financing Authority~~Annual Report 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.~~Statements.)

CAPITAL EXPENDITURES

The Utility expects that capital expenditures will total approximately $3.6 billion in 2008. During the nine month period ended September 30, 2008, the Utility incurred capital expenditures of approximately $2.7 billion. (See “Liquidity and Financial Resources – Investing Activities” above.) Depending on conditions in the capital ~~market,~~markets, the Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and ~~enhance~~improve system reliability, safety, and customer ~~service,~~service; to extend the life of or replace existing ~~infrastructure,~~infrastructure; and to add new infrastructure to meet already authorized ~~growth, and to implement various initiatives designed to achieve operating and cost efficiencies.~~growth. 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,~~February 23, 2009, a ruling was issued that establishes a schedule for the ~~Utility requested that the CPUC approve~~CPUC’s consideration of the Utility’s request for approval of a proposed six-year electric distribution reliability improvement ~~program~~program. Hearings have been scheduled to begin in August 2009, and ~~authorize~~a final decision is scheduled to be issued in January 2010. On March 17, 2009, the Utility ~~to collect revenues to recover forecasted~~filed revised forecasts of proposed capital expenditures totaling approximately $1.99 billion, a decrease from the original forecast of $2.3 billion, and proposed operating and maintenance expenses totaling approximately $59 million, a slight increase from the original forecast of $43 million, over the six-year period ~~beginning~~of 2010 through 2016.

SmartMeter™ Program

Since late 2006, the Utility has been installing an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility’s electric and gas customers. This infrastructure results in substantial cost savings associated with billing customers for energy usage, and enables the Utility to measure usage of electricity on ~~January 1, 2009.~~a time-of-use basis and to charge time-differentiated rates. The ~~amounts requested are incremental~~main goal of time-differentiated rates is to encourage customers to reduce energy consumption during peak demand periods and to reduce procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the ~~revenue requirement already authorized~~majority of the installation throughout its service territory by the end of 2011.

The CPUC authorized the Utility to recover the $1.74 billion estimated SmartMeter™ project cost, including an estimated capital cost of $1.4 billion. The $1.74 billion amount includes $1.68 billion for project costs and approximately $54.8 million for costs to market critical peak pricing programs primarily for residential customers, SmartRate, that are made possible by SmartMeter™ technology. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed $1.68 billion without a reasonableness review by the ~~Utility’s 2007 GRC.~~CPUC. The ~~program includes initiatives~~remaining 10% will not be recoverable in rates. If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review. Through March 31, 2009, the Utility has spent an aggregate of $824 million, including capital costs of $670 million, to install the SmartMeterTM system.

On March 12, 2009, the CPUC authorized the Utility to upgrade elements of its SmartMeter™ advanced metering infrastructure project. The CPUC authorized additional funding of $466.8 million, including $402 million of capital costs, to be recovered through an increased revenue requirement. The Utility intends to install upgraded electric meters with associated devices that would offer an expanded range of service features for electric customers that would support energy conservation and demand response options, such as the ability to present near-real-time energy consumption data to customers so that they could use energy more wisely in response to near-real-time energy data. These upgraded meters would also increase operational efficiencies for the Utility through, among other things, the ability to remotely connect and disconnect service to electric customers. In addition, the upgraded electric meters are designed to ~~decrease the frequency and duration of electricity outages in order to bring~~facilitate the Utility’s ~~reliability performance closer~~ability 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 requirementsincorporate future advanced metering technology innovations in a ~~separate balancing account so that the revenue requirement increase would be used only to recover costs associated with the proposed initiatives,~~timely 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.cost-effective manner.

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.~~

5146

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

Diablo Canyon Steam Generator Replacement Project

In November 2005, the CPUC authorized the Utility to replace the steam generators at the two nuclear operating units at Diablo Canyon (Units 1 and 2) and recover costs of up to $706 million from customers without further reasonableness review. The ~~CPUC~~Utility installed four of the new steam generators in Unit 2 during 2008 and completed installation of the remaining new generators for Unit 1 on March 7, 2009. As of March 31, 2009, the Utility has ~~previously~~incurred approximately $661 million. If costs exceed the authorized threshold, the CPUC 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 ~~$504~~up to $815 million, ~~through September 30, 2008. The Utility’s request~~subject to ~~recover additional expenditures of $572 million, including $463 million of additional capital expenditures to upgrade certain elements~~reasonableness review of the ~~Utility’s SmartMeter~~TM 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 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 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. The Utility had requested that the CPUC authorize the Utility to recover up to $850 million of forecasted capital costs associated with the construction of the unit. On September 22, 2008, a CPUC administrative law judge issued a proposed decision which recommends that the Utility’s application be dismissed on the basis that the Utility’s application failed to sufficiently demonstrate that conducting a competitive request for offers (“RFO”) would be infeasible.

~~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 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.

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. 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 the authority to enter into a contract for 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. A final decision is expected on November 6, 2008.full amount.

OFF-BALANCE SHEET ARRANGEMENTS

~~For financing and other business purposes,~~ PG&E Corporation and the Utility ~~maintain certain~~do not have any off-balance sheet arrangements that have had, or are not reflected in their Condensed Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E 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.

~~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 expectedreasonably likely to have, a current or future material ~~impact~~effect 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. The Utility ties many energy contracts to master agreements that require security (referred to as “credit collateral”)condition, changes in ~~the form~~financial condition, revenues or expenses, results of ~~cash, letters of credit, corporate guarantees of acceptable credit quality,~~operations, liquidity, capital expenditures, or ~~eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.~~

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

September 30, 2008 $ 378 $ 98 $ 281 2 $ 159
December 31, 2007 $ 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.
(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.capital resources.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies, including Chapter 11 disputed claims, tax matters, and environmental matters, which are discussed in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

This section of MD&A discusses developments that have occurred in significant pending regulatory proceedings discussed in the 2008 Annual Report and significant new pending regulatory proceedings that were initiated since the 2008 Annual Report was filed with the SEC. The ~~Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, the resolution~~outcome of ~~which may affect~~these proceedings could have a significant effect on PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s results of operations orand financial condition.

~~2008 Cost of Capital Proceeding~~Application to Recover Hydroelectric Facility Divestiture Costs

On ~~May 29, 2008,~~April 16, 2009, the CPUC ~~adopted~~approved a ~~uniform three-year cost~~decision to authorize the Utility to recover approximately $47 million, including approximately $12 million of ~~capital mechanism~~interest, of costs the Utility incurred in connection with its efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. The Utility filed the application on April 14, 2008. These efforts were undertaken as required by the CPUC in connection with the proposed divestiture of the facilities to further the development of a competitive generation market in California. The CPUC subsequently withdrew this requirement. The Utility continues to own its hydroelectric generation assets. The Utility expects that the rate adjustments necessary to recover these authorized costs will be combined with other rate adjustments in the ~~second phase of the 2008 Cost of Capital proceeding for the Utility and the other two California investor-owned~~Utility’s annual electric ~~utilities that will replace the annual cost of capital~~rate true-up proceeding. ~~Under the adopted mechanism, the utilities~~These rate changes are ~~required~~expected to ~~file full cost of capital applications by April 20 of every third year, beginning on April 20,~~become effective in January 2010.

~~Under~~Retirement Plan Contribution Application

Due to the ~~decision,~~ongoing upheaval in the economy, there have been negative impacts on the investment returns on assets held in trust to satisfy the Utility’s ~~2008 cost~~obligations to secure payment of ~~capital (including an 11.35% ROE) will be maintained through 2010, unless the automatic adjustment mechanism described below is triggered.~~employee benefits under pension and other postretirement benefit plans. The Utility’s ~~2008 capital structure (including~~recorded liabilities and, in some cases, its funding obligations, may increase as a ~~52% equity component) is authorized through 2010. The decision permits~~result of declining investment returns on trust assets and lower assumed rates of return. However, 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 (“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. The 12-month October 2007 through September 2008 average of the Moody's Investors Service utility bond index did not trigger a change in the 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~~it is probable that any increase in funding obligations would be recoverable through rates. On March 2, 2009, the Utility filed an application requesting that the CPUC approve a mechanism for annually adjusting gas and electric revenue requirements beginning in 2011 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~~cover contributions 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 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 license to construct the dry cask storage facility. The NRC concluded that the NRC staff’s supplemental environmental assessment, which concluded there would be no significant environmental impacts from potential terrorist acts directed at the dry cask storage facility, was supported by a reasonable analysis. Any party wishing to appeal the NRC’s order must file a notice of appeal within 60 days.

In addition, on August 7, 2008, the U.S. Court of Appeals for the Federal Circuit issued an appellate order in the 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 millionUtility’s retirement plan outside of the ~~$92 million incurred by the Utility through 2004. In ruling on the Utility’s appeal, the U.S. Court~~GRC, which would ensure timely recovery 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.any additional contributions.

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

~~Energy Efficiency Programs and Incentive Ratemaking~~

The schedule adopted by the CPUC 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 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 submitted in 2010 based on the Energy Division’s measurement and evaluation studies to be completed in 2010 but use the reported results submitted by the utilities 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 $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 measurement studies for the final true-up claim in 2010.

On November 4, 2008, a proposed decision was issued by the CPUC 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 issues its final verification report in January 2009 using recent updates to estimates of energy savings from the energy efficiency measures installed by the utilities on customer premises. If the proposed decision is adopted and the updated savings estimates are used to assess the 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 2009 for 2008 program performance be assessed using the recent updated savings estimates and be determined after the Energy Division issues a final verification report on the 2008 program year. If this final verification report is delayed, the alternate proposed decision would permit the 2009 interim claims for the 2008 program year to be based on the utilities’ reported results, subject to a holdback of at least 50%. The total amount of incentive claims for the completed three-year program period (2006-2008) would be subject to verification and adjustment based on the results of the measurement and evaluation studies to be completed in 2010.

~~It is expected that the CPUC will consider both of the 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 energy efficiency savings goals for the 2009-2011 program period will be considered on a gross basis (i.e., without deduction for customer energy savings not directly attributed to utility 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. On October 30, 2008, the CPUC assigned commissioner and the ALJ issued a ruling requiring the 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 order to take into account the recent updated energy savings estimates.

The amount of any shareholder incentives the Utility may receive (and the amount and timing of any reimbursement obligations the Utility may incur) for the 2009-2011 program cycle will depend on 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; and the level of energy efficiency savings actually achieved over the three-year program cycle.

~~Application to Recover Hydroelectric Generation Facility Divestiture Costs~~Electric Transmission Owner Rate Cases

On April ~~14, 2008,~~20, 2009, 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 determinedrequested 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 August 14, 2008, the DRA and the Utility agreed that the Utility had supported its request with appropriate and reasonable evidence. PG&E Corporation and the Utility are unable to predict whether the CPUC willFERC approve ~~recovery of these costs.~~

~~Electric Transmission Owner Rate Cases~~

~~On October 22, 2008, the FERC approved~~ an ~~all-party~~uncontested settlement in the Utility’s TO rate case that was filed inon July ~~2007.~~30, 2008. The settlement ~~sets~~proposes to set an annual ~~wholesale~~retail base ~~transmission~~ revenue requirement of ~~$706 million and a retail base transmission revenue requirement of $718~~$776 million effective March 1, ~~2008.~~2009. 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, if approved, will not impact the Utility’s results of operations or financial condition. ~~The~~If the settlement is approved by the FERC, the Utility will refund any ~~over –collected~~over-collected amounts to customers, with interest, through an adjustment to 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 an increase in the 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 increase in rates will be subject to refund pending final FERC approval of the requested increase in revenue requirements.2011.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility 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. The Utility is also exposed to credit risk: the risk that counterparties fail to perform their contractual obligations. For a comprehensive discussion of PG&E Corporation’s market risk, see the section entitled “Risk Management Activities” in the ~~2007~~2008 Annual Report.

Price Risk

~~Electric Transmission Congestion Rights~~Electricity Procurement

~~Among other features,~~On April 1, 2009, the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) ~~initiative provides~~became operative after having been delayed several times. Among other features, the MRTU established new day-ahead, hour-ahead, and real-time wholesale electricity markets, subject to bid caps that increase over time. The Utility expects to continue to rely primarily on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts, and its own electricity generation facilities, to meet customer demand. Therefore, a relatively small proportion of the Utility’s total customer demand must be met through purchases in the MRTU markets. As a result, exposure to price volatility in the new MRTU markets is reduced. The CAISO must implement several FERC-ordered changes to MRTU, some of which must be implemented by March 31, 2010. Market risks, if any, associated with these changes will be assessed as the design and timelines are finalized during 2009.

Electric Transmission Congestion Revenue Rights

In the CAISO’s new day-ahead market, the CAISO imposes electric transmission congestion costs and credits ~~will be~~that are determined ~~between any two locations and charged to the~~by reference points along transmissions paths at which power is delivered or withdrawn. The CAISO allows market participants, including load serving entities ~~taking energy that passes between those locations. The CAISO also will provide Congestion Revenue Rights~~such as the Utility, to acquire congestion revenue rights (“CRRs”) ~~to allow market participants, including load serving entities,~~ to hedge the financial risk of CAISO-imposed congestion ~~charges in the MRTU day-ahead market.~~charges. The CAISO releases CRRs through an annual and monthly process, each of which includes both an allocation phase (in which load serving entities receive CRRs at no ~~cost)~~cost based on the customer demand or “load” they serve) 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 September 30,~~in 2008 ~~and anticipates acquiring additional CRRs through the~~(via allocation and ~~auction phases prior to~~auction) in anticipation of the ~~MRTU effective date. Currently,~~effectiveness of the CAISO is targeting an MRTU implementation date of February 1, 2009. The CAISO Board of Governors will continue to evaluate whether that implementation date remains feasible as it approaches. DuringMRTU. In the ~~fourth~~first quarter of ~~2007,~~2009 the Utility ~~participated in an auction to acquire~~acquired additional ~~firm electricity transmission rights (“FTRs”) in order to hedge its financial risk until~~CRRs. CRRs are considered derivative instruments and are recorded at fair value within the ~~MRTU becomes effective.~~Condensed Consolidated Balance Sheets.

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 ~~$31~~$10 million at ~~September 30, 2008.~~March 31, 2009. The ~~Utility's~~Utility’s high, low, and average values-at-risk during the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 were approximately $34 million, ~~$17~~$9 million, and ~~$26~~$22 million, respectively.

Convertible Subordinated Notes

At ~~September 30, 2008,~~March 31, 2009, PG&E Corporation had outstanding approximately ~~$280~~$252 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~~16,702,194 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”~~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,~~2009, PG&E Corporation has paid ~~“pass-through dividends”~~pass-through dividends totaling approximately ~~$28~~$14 million, including $7 million paid on ~~October~~April 15, ~~2008.~~2009.

In accordance with ~~Statement of Financial Accounting Standards (“SFAS”)~~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 (expense), net) in PG&E Corporation’s Condensed Consolidated Statements of Income as a non-operating expense or income. At September 30, 2008, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $49 million, of which $28 million was classified in Current Liabilities - Other(See Notes 7 and $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 in Current Liabilities – Other and $37 million was classified 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.~~Statements.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At ~~September 30, 2008,~~March 31, 2009, 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~~three months ended ~~September 30, 2008~~March 31, 2009 by approximately ~~$7.1~~$0.9 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

The Utility manages credit risk associated with its wholesale customers and counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically, and a detailed credit analysis is performed at least annually. The Utility 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 March 31, 2009 and December 31, 2008:

(in millions)	Gross Credit Exposure Before Credit Collateral(1)	Credit Collateral	Net Credit Exposure(2)	Number of Wholesale Customers or Counterparties >10%	Net Exposure to Wholesale Customers or Counterparties >10%
March 31, 2009	$ 315	$ 63	$ 252	3	$ 192
December 31, 2008	$ 240	$ 84	$ 156	2	$ 107

(1) Gross credit exposure equals mark-to-market value on financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2) Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with 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~~2008 Annual Report. They include:

·	regulatory assets and liabilities;

·	~~unbilled revenues;~~

·	environmental remediation liabilities;

·	asset retirement obligations;

·	accounting for income taxes; and

·	pension and other postretirement ~~benefits.~~plans.

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

For the period ended ~~September 30, 2008,~~March 31, 2009, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and 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:

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

5849

Level 3 fair value measurements represent approximately 5% of the total net value of all fair value measurements of PG&E Corporation. During the three and nine months ended 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 associated with PG&E Corporation’s Convertible Subordinated Notes. The changes in the fair value of the dividend participation rights are reflected in Other income (expense), net in PG&E Corporation’s Condensed Consolidated Statements of Income. Additionally, changes in the fair value of the Level 3 instruments did not have a material effect on liquidity and capital resources as of 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 Trusts and Long Term Disability Trust~~

The nuclear decommissioning 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. The nuclear decommissioning trusts and the long-term disability trust also invest in long-term commingled funds, which are funds that consist of assets from several accounts that are intermingled. These commingled funds have liquidity restrictions and lack an active market for individual shares of the funds; therefore the trusts’ investments in these funds are classified as Level 3. The Level 3 nuclear decommissioning trust assets decreased from approximately $8 million at January 1, 2008 to approximately $7 million at September 30, 2008 and no material change was noted from June 30, 2008 to September 30, 2008. The decrease of approximately $1 million for the nine months ended September 30, 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 $79 million at September 30, 2008. This increase of approximately $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 $95 million at June 30, 2008 to approximately $79 million at September 30, 2008. This decrease of approximately $16 million for the three months ended September 30, 2008 was primarily due to 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 decreased from approximately $115 million as of January 1, 2008 to approximately $34 million as of September 30, 2008. This decrease of approximately $81 million was primarily due to a decrease in commodity prices on September 30, 2008 as compared to January 1, 2008. Additionally, the Level 3 price risk management instruments decreased from approximately $382 million as of June 30, 2008 to approximately $34 million at September 30, 2008. This decrease of approximately $348 million was primarily due to a decrease in commodity prices on September 30, 2008, as compared to 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 load serving entities, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market to be established when MRTU becomes effective. 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. Demand response contracts allow market participants, including 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 extrapolated to fit the terms of a contract, such as frequency of settlement or tenor. These instruments are classified within Level 3 of the fair value hierarchy.

~~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 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 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.)

~~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.~~

NEW ACCOUNTING ~~PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED~~POLICIES

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

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement ~~No. 133~~

~~In March 2008, the FASB issued SFAS~~of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging ~~Activities-an~~Activities — an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133. AnSFAS No. 161 requires an entity ~~is required~~ to provide qualitative disclosures about its objectives and strategies for using ~~derivatives,~~derivative instruments and quantitative disclosures onthat detail the fair value amounts of, and gains and losses on, derivative ~~instruments, and~~instruments. SFAS No. 161 also requires disclosures ~~relating to~~about credit-risk-related contingent features inof derivative ~~agreements.~~instruments. SFAS No. 161 is effective prospectively for fiscal years beginning after November 15, 2008. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

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

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

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

Equity Method Investment Accounting Consideration — an amendment to Accounting Principles Board No. 18

In November 2008, the FASB issued EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”). EITF 08-6 applies to investments accounted for under the equity method and requires an entity to measure its equity investment initially at cost. Generally, contingent consideration associated with an equity method investment should only be included in the initial measurement of that investment if it is required to be recognized by specific authoritative guidance other than SFAS No. 141(R), “Business Combinations.” However, the investor of an equity method investment could be required to recognize a liability for the related contingent consideration features if the fair value of the investor’s share of the investee’s net assets exceeds the investor’s initial costs. An equity method investor is required to recognize other-than-temporary impairments of an equity method investment and shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance shall be recognized in earnings. EITF 08-6 is effective prospectively for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. Adoption of EITF 08-6 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Disclosures about Employers’ Postretirement Benefit Plan Assets — an amendment to FASB Statement No. 132(R)

In December 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP SFAS 132(R)-1”). FSP SFAS 132(R)-1 amends and expands the disclosure requirements of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” An entity is required to provide qualitative disclosures about how investment allocation decisions are made, the inputs and valuation techniques used to measure the fair value of plan assets, and the concentration of risk within plan assets. Additionally, quantitative disclosures are required showing the fair value of each major category of plan assets, the levels in which each asset is classified within the fair value hierarchy, and a reconciliation for the period of plan assets that are measured using significant unobservable inputs. FSP SFAS 132(R)-1 is effective prospectively for fiscal years ending after December 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 132(R)-1.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FSP SFAS 107-1 and APB No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP SFAS 107-1 and APB No. 28-1”). This FSP amends SFAS No. ~~161.~~107 and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosures about the fair value of financial instruments for interim reporting periods that were previously only required for annual reporting periods. An entity is required to disclose the fair value of financial assets and liabilities together with the related carrying amount and where the carrying amount is classified in the Condensed Consolidated Balance Sheets. FSP SFAS 107-1 and APB No. 28-1 is effective prospectively for interim reporting periods after June 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 107-1 and APB No. 28-1.

Recognition and Presentation of Other-Than-Temporary Impairments

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

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP SFAS 157-4”). This FSP amends SFAS No. 157, “Fair Value Measurements,” to provide guidance on estimating fair value when the volume or level of activity for an asset or liability has significantly decreased when compared with normal market conditions. Guidance to identify circumstances when a transaction is not orderly, or is distressed or forced, is also provided. FSP SFAS 157-4 is effective prospectively for interim reporting periods after June 15, 2009. PG&E Corporation and the Utility are currently evaluating the impact of FSP SFAS 157-4.

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ITEM 3:3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~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~~Management’s Discussion and Analysis of Financial Condition and Results of Operations).

ITEM 4: 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s disclosure controls and procedures as of ~~September 30, 2008,~~March 31, 2009, PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities ~~and~~ Exchange Act of 1934 (“~~the~~1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E ~~Corporation~~Corporation’s and the Utility’s management, including PG&E ~~Corporation~~Corporation’s and the ~~Utility's~~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~~control over financial reporting that occurred during the quarter ended ~~September 30, 2008~~March 31, 2009 that have materially affected, or are reasonably likely to materially affect, PG&E ~~Corporation~~Corporation’s or the ~~Utility's~~Utility’s internal ~~controls~~control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

~~Solano~~Complaints Filed by the California Attorney General and the City and County ~~District Attorney’s Office~~of San Francisco

On March 10, 2009, the San Francisco Superior Court dismissed the California Attorney General’s lawsuit filed in 2002 against PG&E Corporation and several of its present and former directors. The Attorney General alleged that the defendants had engaged in unfair or fraudulent business acts or practices in violation of Section 17200 of the California Business and Professions Code. Among other allegations, the Attorney General alleged that past transfers of funds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC. Following a neutral evaluation of the Attorney General’s claims by a former California Supreme Court justice, the Attorney General and the defendants jointly requested that the complaint be dismissed. The dismissal is with prejudice, meaning that the Attorney General cannot re-file the complaint. On April 23, 2009, the City and County of San Francisco dismissed its similar lawsuit against PG&E Corporation. For more information ~~regarding the resolution of this matter,~~about these matters, see ~~“PART II, Item 1. Legal Proceedings” in~~ PG&E ~~Corporation~~Corporation’s and Pacific Gas and Electric Company’s ~~(“Utility”) combined Quarterly~~joint Annual Report on Form ~~10-Q~~10-K for the ~~quarter~~year ended ~~March~~December 31, 2008.

ITEM 1A. RISK FACTORS

~~The~~A discussion of the ~~Utility’s efforts to store spent nuclear fuel appearing~~significant risks associated with investments in the ~~2007 Annual Report~~securities of PG&E Corporation and the Utility is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations –— Risk Factors” ~~under~~in the ~~following caption~~ “~~The operation and decommissioning~~2008 Annual Report. There have been no material changes in the risks related to an investment in PG&E Corporation’s or the Utility’s securities that have been disclosed in the 2008 Annual Report. In addition, the section 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”)this report entitled “Forward-Looking Statements” appearing 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.

~~The discussion under the heading “Management’s~~Part I, Item 2: Management’s Discussion and Analysis of ~~the~~ Financial Condition and Results of Operations, ~~- Risk Factors” in~~lists some of the ~~2007 Annual Report under the following caption~~ ~~“The Utility relies on access to the capital markets. There can be no assurance~~factors that ~~the Utility will be able to successfully finance its planned capital expenditures on favorable terms or rates”~~ ~~is updated as follows to reflect the recent events in the financial markets:~~

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. Like many companies, the Utility relies on the capital markets to 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 marketscould affect PG&E Corporation’s and the ~~costs and terms~~Utility’s future results of available financing depend on many factors, including changes in the Utility’s credit ratings, changes in 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 not available to fund the Utility’s operations and ~~planned capital expenditures. If the Utility is unable, in part or in whole, to fund its operations and planned capital expenditures there could be a material adverse effect on~~financial condition. Although PG&E Corporation and the ~~Utility’s~~Utility are not able to predict all the factors that may affect future results, ~~of operations, cash flows~~the listed factors and ~~financial condition.~~the risks discussed in the 2008 Annual Report could cause actual results to differ materially from the results expected or anticipated by management as expressed or implied by the forward-looking statements made in the 2008 Annual Report and in this report.

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 ~~third~~ quarter ~~of 2008,~~ended March 31, 2009, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the third quarter of 2008, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding. On July 25, 2008, PG&E Corporation contributedmade equity ~~of $40~~contributions totaling $528 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

During the quarter ended March 31, 2009, PG&E Corporation issued 1,855,865 shares of common stock at a conversion price of $15.09 per share in an unregistered offering upon conversion of $28 million principal amount of PG&E Corporation 9.50% Convertible Subordinated Notes originally issued in an unregistered offering in 2002.

Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period	Total Number of Shares Purchased			Average Price Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1 through January 31, 2009		36,672	(1)	$	38.81		-	$	-
February 1 through February 28, 2009		-			-		-		-
March 1 through March 31, 2009		-			-		-		-
Total		36,672		$	38.81		-	$	-


(1) Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock.

During the first quarter of 2009, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

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

The ~~Utility's~~ Utility’s earnings to fixed charges ratio for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 was ~~3.33 and 2.99, respectively.~~2.71. The ~~Utility's~~Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the three ~~and nine~~ months ended ~~September 30, 2008~~March 31, 2009 was ~~3.27 and 2.94, respectively.~~2.66. 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~~Utility’s Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the ~~Utility's~~Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the three months ended March 31, 2009 was 2.60. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.

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ITEM 6. EXHIBITS

43.1	~~Fourth~~Bylaws of PG&E Corporation amended as of January 1, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 3.3)

3.2.	Bylaws of Pacific Gas and Electric Company amended as of January 1, 2009 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 3.5)

4.1	Sixth Supplemental Indenture, dated as of ~~October 21, 2008~~March 6, 2009 relating to the ~~Utility’s~~ issuance of ~~$600,000,000~~$550,000,000 aggregate principal amount of ~~its 8.25%~~Pacific Gas and Electric Company’s 6.25% Senior Notes due ~~October 15, 2018~~March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated ~~October 21, 2008~~March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Current Report on Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
10.1*	Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)

1010.2	~~Separation~~Form of Restricted Stock Unit Agreement ~~between William T. Morrow and Pacific Gas and Electric Company dated July 8, 2008~~for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

10.3*	Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

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

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

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

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

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

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

* 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.

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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 and 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: ~~November~~May 6, ~~2008~~2009

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EXHIBIT INDEX

43.1	~~Fourth~~Bylaws of PG&E Corporation amended as of January 1, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 3.3)

3.2.	Bylaws of Pacific Gas and Electric Company amended as of January 1, 2009 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 3.5)

4.1	Sixth Supplemental Indenture, dated as of ~~October 21, 2008~~March 6, 2009 relating to the ~~Utility’s~~ issuance of ~~$600,000,000~~$550,000,000 aggregate principal amount of ~~its 8.25%~~Pacific Gas and Electric Company’s 6.25% Senior Notes due ~~October 15, 2018~~March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated ~~October 21, 2008~~March 6, 2009 (File No. 1-2348), Exhibit 4.1)
4.2	First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Current Report on Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
10.1*	Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)

1010.2	~~Separation~~Form of Restricted Stock Unit Agreement ~~between William T. Morrow and Pacific Gas and Electric Company dated July 8, 2008~~for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

10.3*	Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

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

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

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

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

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

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

* 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.

	PG&E Corporation				Utility
	Three Months Ended September 30,				Three Months Ended September 30,
(in millions)	2008		2007		2008		2007
Stock options	$	1	$	2	$	-	$	1
Restricted stock		5		6		4		4
Performance shares		-		15		-		10
Total compensation expense (pre-tax)	$	6	$	23	$	4	$	15
Total compensation expense (after-tax)	$	4	$	14	$	2	$	9

	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.

PG&E Corporation
(in millions)	Money Market Investments	Price Risk Management Instruments	Nuclear Decommissioning Trusts (3)	Long-term Disability	Dividend Participation Rights	Other	Total
Asset (liability) Balance as of January 1, 2008	$ -	$ 115(1)	$ 8	$ 69	$ (68)(2)	$ (4)	$120
Realized and unrealized gains (losses):
Included in earnings	-	-	-	-	(2)	-	(2)
Included in regulatory assets and liabilities or balancing accounts	-	(81)	(1)	(12)	-	(1)	(95)
Purchases, issuances, and settlements	-	-	-	22	21	-	43
Transfers in (out) of Level 3	62	-	-	-	-	-	62
Asset (liability) Balance as of September 30, 2008	$ 62	$ 34	$ 7	$ 79	$ (49)	$ (5)	$ 128

Earnings for the period were impacted by a $2 million unrealized loss relating to assets or liabilities still held at September 30, 2008.


(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1.
(2) 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 expense to increase the value of the liability.
(3) Excludes taxes on appreciation of investment value.

(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

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

	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

	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