
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 ~~March 31,~~June 30, 2008 OR

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

For the transition period from ___________ to __________

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:				[ ] Yes [X] No

Pacific Gas and Electric Company:				[ ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock Outstanding as of ~~May~~August 1, 2008:

PG&E Corporation					~~357,258,997~~358,556,042 shares (excluding 24,665,500 shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company					283,856,022

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~MARCH 31,~~JUNE 30, 2008

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1:1.	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	14
	NOTE 4:		Debt	17
	NOTE 5:		Shareholders' Equity	18
	NOTE 6:		Earnings Per Common Share	19
	NOTE 7:		Derivatives and Hedging Activities	20
	NOTE 8:		Fair Value Measurements	21
	NOTE 9:		Related Party Agreements and Transactions	25
	NOTE 10:		Resolution of Remaining Chapter 11 Disputed Claims	26
	NOTE 11:		Commitments and Contingencies	2726

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			33
	Forward-Looking Statements			35
	Results of Operations			37
	Liquidity and Financial Resources			4243
	Contractual Commitments			4647
	Capital Expenditures			4648
	Off-Balance Sheet Arrangements			4750
	Contingencies			4851
	Regulatory Matters			4851
	Risk Management Activities			5053
	Critical Accounting Policies			5255
	New Accounting Policies			5256
	Accounting Pronouncements Issued But Not Yet Adopted			5457
	Environmental Matters			5457
	Tax Matters			5559
	Legal Matters			5659

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			5760
ITEM 4.	CONTROLS AND PROCEDURES			5760

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			5860
ITEM 1A.	RISK FACTORS			5860
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			5861
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			61
ITEM 5.	OTHER INFORMATION			5963
ITEM 6.	EXHIBITS			5964
SIGNATURES				6165

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)
(in millions, except per share amounts)		Three Months Ended
		March 31,							Three Months Ended						Six Months Ended
		2008			2007				June 30,						June 30,
(in millions, except per share amounts)									2008			2007			2008			2007
Operating Revenues
Electric		$	2,514		$	2,175			$	2,645		$	2,359		$	5,159		$	4,534
Natural gas			1,219			1,181				933			828			2,152			2,009
Total operating revenues			3,733			3,356				3,578			3,187			7,311			6,543
Operating Expenses
Cost of electricity			1,027			723				1,097			884			2,124			1,607
Cost of natural gas			775			754				487			396			1,262			1,150
Operating and maintenance			1,036			920				991			922			2,027			1,842
Depreciation, amortization, and decommissioning			402			430				419			430			821			860
Total operating expenses			3,240			2,827				2,994			2,632			6,234			5,459
Operating Income			493			529				584			555			1,077			1,084
Interest income			26			52				33			37			59			89
Interest expense			(187	)		(190	)			(185	)		(185	)		(372	)		(375	)
Other income, net			2			4				1			10			3			14
Income Before Income Taxes			334			395				433			417			767			812
Income tax provision			110			139				140			148			250			287
Net Income		$	224		$	256			$	293		$	269		$	517		$	525
Weighted Average Common Shares Outstanding, Basic			355			349				356			350			355			350
Weighted Average Common Shares Outstanding, Diluted			356			351				357			352			356			352
Net Earnings Per Common Share, Basic		$	0.62		$	0.71			$	0.80		$	0.75		$	1.42		$	1.46
Net Earnings Per Common Share, Diluted		$	0.62		$	0.71			$	0.80		$	0.74		$	1.42		$	1.45
Dividends Declared Per Common Share		$	0.39		$	0.36			$	0.39		$	0.36		$	0.78		$	0.72

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

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
									(Unaudited)
		Balance At							Balance At
(in millions)		March 31, 2008 (Unaudited)			December 31, 2007				June 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	253		$	345			$	297		$	345
Restricted cash			1,305			1,297				1,322			1,297
Accounts receivable:
Customers (net of allowance for doubtful accounts of $61 million in 2008 and $58 million in 2007)			2,260			2,349
Customers (net of allowance for doubtful accounts of $59 million in 2008 and $58 million in 2007)										2,417			2,349
Regulatory balancing accounts			1,179			771				1,357			771
Inventories:
Gas stored underground and fuel oil			100			205				251			205
Materials and supplies			164			166				177			166
Income taxes receivable			105			61				52			61
Prepaid expenses and other			390			255				469			255
Total current assets			5,756			5,449				6,342			5,449
Property, Plant, and Equipment
Electric			25,920			25,599				26,693			25,599
Gas			9,738			9,620				9,860			9,620
Construction work in progress			1,664			1,348				1,432			1,348
Other			17			17				17			17
Total property, plant, and equipment			37,339			36,584				38,002			36,584
Accumulated depreciation			(13,117	)		(12,928	)			(13,297	)		(12,928	)
Net property, plant, and equipment			24,222			23,656				24,705			23,656
Other Noncurrent Assets
Regulatory assets			4,349			4,459				4,300			4,459
Nuclear decommissioning funds			1,932			1,979				1,914			1,979
Other			1,187			1,089				1,351			1,089
Total other noncurrent assets			7,468			7,527				7,565			7,527
TOTAL ASSETS		$	37,446		$	36,632			$	38,612		$	36,632

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

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
									(Unaudited)
		Balance At							Balance At
(in millions, except share amounts)		March 31, 2008 (Unaudited)			December 31, 2007				June 30, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings		$	73		$	519			$	156		$	519
Long-term debt, classified as current			754			-				600			-
Energy recovery bonds, classified as current			359			354				362			354
Accounts payable:
Trade creditors			1,070			1,067				1,133			1,067
Disputed claims and customer refunds			1,628			1,629				1,588			1,629
Regulatory balancing accounts			734			673				924			673
Other			497			394				388			394
Interest payable			675			697				744			697
Income taxes payable										12			-
Deferred income taxes			168			-				228			-
Other			1,706			1,374				1,926			1,374
Total current liabilities			7,664			6,707				8,061			6,707
Noncurrent Liabilities
Long-term debt			7,721			8,171				7,721			8,171
Energy recovery bonds			1,494			1,582				1,409			1,582
Regulatory liabilities			4,663			4,448				5,185			4,448
Asset retirement obligations			1,598			1,579				1,614			1,579
Income taxes payable			241			234				230			234
Deferred income taxes			3,053			3,053				3,178			3,053
Deferred tax credits			98			99				96			99
Other			1,969			1,954				1,969			1,954
Total noncurrent liabilities			20,837			21,120				21,402			21,120
Commitments and Contingencies (Notes 4, 5, 10, and 11)
Commitments and Contingencies
Preferred Stock of Subsidiaries			252			252				252			252
Preferred Stock
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued			-			-				-			-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 379,897,758 common and 1,381,424 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007			6,162			6,110
Common stock, no par value, authorized 800,000,000 shares, issued 381,076,783 common and 1,392,583 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007										6,211			6,110
Common stock held by subsidiary, at cost, 24,665,500 shares			(718	)		(718	)			(718	)		(718	)
Reinvested earnings			3,237			3,151				3,389			3,151
Accumulated other comprehensive income			12			10				15			10
Total common shareholders' equity			8,693			8,553				8,897			8,553
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	37,446		$	36,632			$	38,612		$	36,632

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

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)							Six Months Ended
		Three Months Ended							June 30,
(in millions)		March 31,							2008			2007
		2008			2007
Cash Flows From Operating Activities
Net income		$	224		$	256			$	517		$	525
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction			417			454				870			914
Deferred income taxes and tax credits, net			167			142				346			102
Other changes in noncurrent assets and liabilities			111			68				493			130
Net effect of changes in operating assets and liabilities:
Gain on sale of assets										-			(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable			89			235				(68	)		142
Inventories			107			75				(57	)		(22	)
Accounts payable			144			(86	)			121			(214	)
Income taxes receivable/payable			(37	)		58				21			(61	)
Regulatory balancing accounts, net			(356	)		(275	)			(351	)		(483	)
Other current assets			103			173				431			273
Other current liabilities			68			(117	)			(79	)		(46	)
Other			(2	)		(7	)			(3	)		(23	)
Net cash provided by operating activities			1,035			976				2,241			1,236
Cash Flows From Investing Activities
Capital expenditures			(853	)		(673	)			(1,712	)		(1,320	)
Net proceeds from sale of assets			6			4
Decrease (increase) in restricted cash			2			(11	)
Proceeds from sale of assets										12			8
Increase in restricted cash										(7	)		(13	)
Proceeds from nuclear decommissioning trust sales			164			181				636			548
Purchases of nuclear decommissioning trust investments			(117	)		(199	)			(665	)		(606	)
Net cash used in investing activities			(798	)		(698	)			(1,736	)		(1,383	)
Cash Flows From Financing Activities
Repayments under accounts receivable facility and working capital facility			(250	)		(300	)			(250	)		(300	)
Net repayment of commercial paper, net of discount of $4 million in 2007			(198	)		(425	)
(Repayment) issuance of commercial paper, net of $1 million discount in 2008 and $2 million in 2007										(114	)		109
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007			598			690				598			690
Long-term debt matured, redeemed, or repurchased			(300	)		-				(454	)		-
Rate reduction bonds matured			-			(75	)			-			(143	)
Energy recovery bonds matured			(83	)		(83	)			(165	)		(160	)
Common stock issued			39			26				82			89
Common stock dividends paid			(129	)		(123	)			(267	)		(242	)
Other			(6	)		26				17			14
Net cash used in financing activities			(329	)		(264	)
Net cash (used in) provided by financing activities										(553	)		57
Net change in cash and cash equivalents			(92	)		14				(48	)		(90	)
Cash and cash equivalents at January 1			345			456				345			456
Cash and cash equivalents at March 31		$	253		$	470
Cash and cash equivalents at June 30									$	297		$	366
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)		$	189		$	128			$	260		$	239
Income taxes paid (refunded), net			-			57				(60	)		282
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$	139		$	126			$	140		$	128
Capital expenditures financed through accounts payable			242			142				180			120

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							Three Months Ended						Six Months Ended
									June 30,						June 30,
(in millions)		March 31,							2008			2007			2008			2007
		2008			2007
Operating Revenues
Electric		$	2,514		$	2,175			$	2,645		$	2,359		$	5,159		$	4,534
Natural gas			1,219			1,181				933			828			2,152			2,009
Total operating revenues			3,733			3,356				3,578			3,187			7,311			6,543
Operating Expenses
Cost of electricity			1,027			723				1,097			884			2,124			1,607
Cost of natural gas			775			754				487			396			1,262			1,150
Operating and maintenance			1,036			919				991			921			2,027			1,840
Depreciation, amortization, and decommissioning			402			429				418			430			820			859
Total operating expenses			3,240			2,825				2,993			2,631			6,233			5,456
Operating Income			493			531				585			556			1,078			1,087
Interest income			24			48				33			35			57			83
Interest expense			(180	)		(182	)			(178	)		(178	)		(358	)		(360	)
Other income, net			19			9				7			15			26			24
Income Before Income Taxes			356			406				447			428			803			834
Income tax provision			120			145				134			154			254			299
Net Income			236			261				313			274			549			535
Preferred stock dividend requirement			3			3				4			4			7			7
Income Available for Common Stock		$	233		$	258			$	309		$	270		$	542		$	528

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

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
									(Unaudited)
		Balance At							Balance At
(in millions)		March 31, 2008 (Unaudited)			December 31, 2007				June 30, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	62		$	141			$	69		$	141
Restricted cash			1,305			1,297				1,322			1,297
Accounts receivable:
Customers (net of allowance for doubtful accounts of $61 million in 2008 and $58 million in 2007)			2,260			2,349
Customers (net of allowance for doubtful accounts of $59 million in 2008 and $58 million in 2007)										2,417			2,349
Related parties			2			6				-			6
Regulatory balancing accounts			1,179			771				1,357			771
Inventories:
Gas stored underground and fuel oil			100			205				251			205
Materials and supplies			164			166				177			166
Income taxes receivable			38			15				-			15
Prepaid expenses and other			387			252				468			252
Total current assets			5,497			5,202				6,061			5,202
Property, Plant, and Equipment
Electric			25,920			25,599				26,693			25,599
Gas			9,738			9,620				9,860			9,620
Construction work in progress			1,664			1,348				1,432			1,348
Total property, plant, and equipment			37,322			36,567				37,985			36,567
Accumulated depreciation			(13,102	)		(12,913	)			(13,282	)		(12,913	)
Net property, plant, and equipment			24,220			23,654				24,703			23,654
Other Noncurrent Assets
Regulatory assets			4,349			4,459				4,300			4,459
Nuclear decommissioning funds			1,932			1,979				1,914			1,979
Related parties receivable			28			23				27			23
Other			1,094			993				1,260			993
Total other noncurrent assets			7,403			7,454				7,501			7,454
TOTAL ASSETS		$	37,120		$	36,310			$	38,265		$	36,310

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

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
									(Unaudited)
		Balance At							Balance At
(in millions, except share amounts)		March 31, 2008 (Unaudited)			December 31, 2007				June 30, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings		$	73		$	519			$	156		$	519
Long-term debt, classified as current			754			-				600			-
Energy recovery bonds, classified as current			359			354				362			354
Accounts payable:
Trade creditors			1,070			1,067				1,133			1,067
Disputed claims and customer refunds			1,628			1,629				1,588			1,629
Related parties			27			28				24			28
Regulatory balancing accounts			734			673				924			673
Other			481			370				373			370
Interest payable			668			697				744			697
Income taxes payable			3			-				42			-
Deferred income taxes			174			4				234			4
Other			1,525			1,200				1,740			1,200
Total current liabilities			7,496			6,541				7,920			6,541
Noncurrent Liabilities
Long-term debt			7,441			7,891				7,441			7,891
Energy recovery bonds			1,494			1,582				1,409			1,582
Regulatory liabilities			4,663			4,448				5,185			4,448
Asset retirement obligations			1,598			1,579				1,614			1,579
Income taxes payable			103			103				82			103
Deferred income taxes			3,095			3,104				3,214			3,104
Deferred tax credits			98			99				96			99
Other			1,862			1,838				1,863			1,838
Total noncurrent liabilities			20,354			20,644				20,904			20,644
Commitments and Contingencies (Notes 4, 5, 10, and 11)
Commitments and Contingencies
Shareholders' Equity
Preferred stock without mandatory redemption provisions:
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares			145			145				145			145
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares			113			113				113			113
Common stock, $5 par value, authorized 800,000,000 shares, issued 283,856,022 shares in 2008 and issued 282,916,485 shares in 2007			1,419			1,415				1,419			1,415
Common stock held by subsidiary, at cost, 19,481,213 shares			(475	)		(475	)			(475	)		(475	)
Additional paid-in capital			2,268			2,220				2,269			2,220
Reinvested earnings			5,785			5,694				5,952			5,694
Accumulated other comprehensive income			15			13				18			13
Total shareholders' equity			9,270			9,125				9,441			9,125
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	37,120		$	36,310			$	38,265		$	36,310

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

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)							Six Months Ended
		Three Months Ended							June 30,
(in millions)		March 31,							2008			2007
		2008			2007
Cash Flows From Operating Activities
Net income		$	236		$	261			$	549		$	535
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction			417			454				870			913
Deferred income taxes and tax credits, net			160			143				316			101
Other changes in noncurrent assets and liabilities			106			68				480			129
Net effect of changes in operating assets and liabilities:
Gain on sale of assets										-			(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable			88			237				(66	)		143
Inventories			107			75				(57	)		(22	)
Accounts payable			149			(99	)			123			(221	)
Income taxes receivable/payable			(20	)		41				57			(59	)
Regulatory balancing accounts, net			(356	)		(275	)			(351	)		(483	)
Other current assets			104			174				429			271
Other current liabilities			65			(98	)			(73	)		(48	)
Other			(2	)		(7	)			(3	)		(23	)
Net cash provided by operating activities			1,054			974				2,274			1,235
Cash Flows From Investing Activities
Capital expenditures			(853	)		(673	)			(1,712	)		(1,320	)
Net proceeds from sale of assets			6			4
Decrease (increase) in restricted cash			2			(11	)
Proceeds from sale of assets										12			8
Increase in restricted cash										(7	)		(13	)
Proceeds from nuclear decommissioning trust sales			164			181				636			548
Purchases of nuclear decommissioning trust investments			(117	)		(199	)			(665	)		(606	)
Net cash used in investing activities			(798	)		(698	)			(1,736	)		(1,383	)
Cash Flows From Financing Activities
Repayments under accounts receivable facility and working capital facility			(250	)		(300	)			(250	)		(300	)
Net repayment of commercial paper, net of discount of $4 million in 2007			(198	)		(425	)
(Repayment) issuance of commercial paper, net of discount of $1 million in 2008 and $2 million in 2007										(114	)		109
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007			598			690				598			690
Long-term debt matured, redeemed, or repurchased			(300	)		-				(454	)		-
Rate reduction bonds matured			-			(75	)			-			(143	)
Energy recovery bonds matured			(83	)		(83	)			(165	)		(160	)
Equity infusion from PG&E Corporation			50			-
Equity infusion										50			200
Common stock dividends paid			(142	)		(127	)			(284	)		(254	)
Preferred stock dividends paid			(3	)		(3	)			(7	)		(7	)
Other			(7	)		14				16			21
Net cash used in financing activities			(335	)		(309	)
Net cash (used in) provided by financing activities										(610	)		156
Net change in cash and cash equivalents			(79	)		(33	)			(72	)		8
Cash and cash equivalents at January 1			141			70				141			70
Cash and cash equivalents at March 31		$	62		$	37
Cash and cash equivalents at June 30									$	69		$	78
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized)		$	189		$	115			$	246		$	226
Income taxes paid (refunded), net			-			(30	)			(60	)		299
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$	242		$	142			$	180		$	120

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.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

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

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the unaudited Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's Condensed Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries and variable interest entities for which it is subject to a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

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

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities, and the disclosure of contingencies, and include, but are not limited to, estimates and assumptions used in determining the Utility's regulatory asset and liability balances based on probability assessments of regulatory recovery, revenues earned but not yet billed, the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Disputed Claims”) 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 liabilities, 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.)contingencies. A change in management's estimates or assumptions could have a material impact on PG&E Corporation and the Utility's financial condition and results of operations during the period in which such change occurred. As these estimates and assumptions involve judgments on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict, actual results may differ materially from these estimates. PG&E Corporation and the Utility's Condensed Consolidated Financial Statements reflect all adjustments management believes are necessary for the fair presentation of their financial condition and results of operations for the periods presented. Interim period results of operations are not necessarily indicative of the results of operations for the full year.

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

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

Fair Value Measurements

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

fair-valued instruments according to the hierarchy in each reporting period after implementation.

~~As a result of the adoption~~ The provisions of SFAS No. 157 ~~PG&E Corporation and the Utility recorded, on January 1,~~have been deferred to fiscal years beginning after November 15, 2008 a $48 million increase to price risk management assets (Current Assets – Prepaid Expenses and Other and Noncurrent Assets - Other) and regulatory liabilities (Current Liabilities - Other and Noncurrent Liabilities – Other) associated with the valuation of Congestion Revenue Rights (“CRRs”). Additionally, PG&E Corporation recorded a $6 million increase to Current Liabilities - Other and Noncurrent Liabilities - Other associated with the valuations of dividend participation rights, which impacted earnings.for nonrecurring, nonfinancial instruments shown at fair value.

See Note 8 for further discussion and the impact to the financial statements of implementation of SFAS No. 157 and fair value measurements.

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 did not elect the fair value option for any assets or liabilities as of June 30, 2008; therefore, the adoption of SFAS No. 159 did not impact the Condensed Consolidated Financial Statements.

Amendment of ~~FASB~~Financial Accounting Standards Board Interpretation No. 39

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board (“FASB”) Staff Position on Interpretation 39, “Amendment of FASB Interpretation No. 39” (“FIN 39-1”). Under FIN 39-1, a reporting entity is permitted to offset the ~~fair value amounts recognized for~~ cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The provisions of FIN 39-1 are applied retrospectively. Therefore, the impact of FIN 39-1 on PG&E Corporation and the Utility’s Consolidated Balance Sheets as of December 31, 2007 reflect a $65 million reclassification of cash collateral from Other Current Assets to Price Risk Management Instruments. In addition, PG&E Corporation and the Utility’s Condensed Consolidated Balance Sheets reflect a $155 million classification of cash collateral within Price Risk Management Instruments at March 31, 2008. See Note 7 for further discussion of FIN 39-1.

Share-Based Compensation

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

PG&E Corporation and the Utility use an estimated annual forfeiture rate of 2.5%, based on historic forfeiture rates, for purposes of determining compensation expense for share-based incentive awards. The following table provides a summary of total compensation expense (reduction to compensation expense) for PG&E Corporation (consolidated) and the Utility (stand-alone) for share-based incentive awards for the three and six months ended ~~March 31,~~June 30, 2008 and 2007:

	PG&E Corporation				Utility
	Three Months Ended June 30,				Three Months Ended June 30,
(in millions)	2008		2007		2008		2007
Stock options	$	-	$	2	$	-	$	1
Restricted stock		5		5		4		3
Performance shares		10		6		6		4
Total compensation expense (pre-tax)	$	15	$	13	$	10	$	8
Total compensation expense (after-tax)	$	9	$	8	$	6	$	5

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

Pension and Other Postretirement Benefits

PG&E Corporation

Utility

Three Months Ended
March 31,

Three Months Ended
March 31,

(in millions)
2008

2007

2008

2007

Stock options $ 1 $ 2 $ 1 $ 1
Restricted stock 9 8 5 5
Performance shares (4 ) (6 ) (3 ) (5 )
Total compensation expense (pre-tax) $ 6 $ 4 $ 3 $ 1
Total compensation expense (after-tax) $ 4 $ 2 $ 2 $ 1

~~Pension and Other Postretirement Benefits~~

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for certain employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for certain employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for certain employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all of their plans and use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee, to determine the fair value of the plan assets. To determine each plan’s projected benefit obligation, PG&E Corporation and the Utility use December 31 measurement date actuarial assumptions, as determined by an independent party.plans.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three and six months ended ~~March 31,~~June 30, 2008 and 2007 are as follows:

	Pension Benefits						Other Benefits							Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,							Three Months Ended June 30,						Three Months Ended June 30,
(in millions)	2008			2007			2008			2007				2008			2007			2008			2007
Service cost for benefits earned	$	59		$	59		$	7		$	7			$	59		$	59		$	7		$	7
Interest cost		144			135			20			20				144			135			20			20
Expected return on plan assets		(175	)		(177	)		(24	)		(24	)			(175	)		(177	)		(24	)		(24	)
Amortization of transition obligation (1)		-			-			7			6				-			-			7			6
Amortization of prior service cost (1)		12			12			4			4				12			12			4			4
Amortization of unrecognized (gain) loss (1)		-			-			(4	)		(3	)
Amortization of unrecognized gain (1)															-			-			(4	)		(3	)
Net periodic benefit cost	$	40		$	29		$	10		$	10			$	40		$	29		$	10		$	10


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

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


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

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

Accounting Pronouncements Issued But Not Yet Adopted

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

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

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

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

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

Under SFAS No. 71, incurred costs that would otherwise be charged to expense may be capitalized and recorded as regulatory assets if it is probable that the incurred costs will be recovered in 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.

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

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance At					Balance At
(in millions)	March 31, 2008		December 31, 2007			June 30, 2008		December 31, 2007
Energy recovery bond regulatory asset	$	1,749	$	1,833	$	1,668	$	1,833
Utility retained generation regulatory assets		928		947		909		947
Regulatory assets for deferred income tax		752		732		788		732
Environmental compliance costs		333		328		335		328
Unamortized loss, net of gain, on reacquired debt		266		269		261		269
Regulatory assets associated with plan of reorganization		112		122		110		122
Contract termination costs		93		96		89		96
Scheduling coordinator costs		78		90		80		90
Other		38		42		60		42
Total regulatory assets	$	4,349	$	4,459	$	4,300	$	4,459

The energy recovery bond (“ERB”) regulatory asset represents the refinancing of the settlement regulatory asset established under the December 19, 2003 settlement agreement among PG&E Corporation, the Utility, and the CPUC to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (the “Chapter 11 Settlement Agreement”). During the ~~three~~six months ended ~~March 31,~~June 30, 2008, the Utility recorded amortization of the ERB regulatory asset of approximately ~~$84~~$165 million. The Utility expects to fully recover this asset by the end of 2012.

As a result of the Chapter 11 Settlement Agreement, the Utility recognized a one-time non-cash gain of $1.2 billion related to the recovery of the Utility’s retained generation regulatory assets in 2004. The individual components of these regulatory assets are amortized over their respective lives, with a weighted average life of approximately 16 years. During the ~~three~~six months ended ~~March 31,~~June 30, 2008, the Utility recorded amortization of the Utility’s retained generation regulatory assets of approximately ~~$19~~$38 million.

The regulatory assets for deferred income tax represent deferred income tax benefits passed through to customers and are offset by deferred income tax liabilities. Tax benefits to customers have been passed through as the CPUC requires utilities under its jurisdiction to follow the “flow-through” method of passing certain tax benefits to customers. The “flow-through” method ignores the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 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 Chapter 11 Settlement Agreement include costs incurred in financing the Utility’s reorganization under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”) and costs to oversee the environmental enhancement projects of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization. The Utility expects to recover these costs over periods ranging from 5 to 30 years.

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

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

Finally, “Other” is primarily related to price risk management regulatory assets, with contract terms in excess of one year, to procure electricity and natural gas that are designed to reduce commodity price risks. These contracts are accounted for as derivative instruments under SFAS No. 133. Changes in the fair value of derivative instruments are deferred and recorded in regulatory accounts because they are recovered or refunded through regulated rates. Additionally, “Other” includes regulatory assets that represent timing differences between the recognition of ~~ARO~~asset retirement obligation (“ARO”) in accordance with GAAP and the amounts recognized for ratemaking purposes.

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,~~assets; unamortized loss, net of gain, on reacquired ~~debt,~~debt; and regulatory assets associated with the plan of reorganization.

Current Regulatory Assets

At ~~March 31,~~June 30, 2008 and December 31, 2007, the Utility had current regulatory assets of approximately ~~$85~~$93 million and $131 million, respectively, consisting primarily of price risk management regulatory assets with terms of less than one year. Price risk management regulatory assets relate to contracts, with terms less than one year, to procure electricity and natural gas that are designed to reduce commodity price ~~risks that~~risks. These contracts are accounted for as ~~derivatives~~derivative instruments under SFAS No. 133. ~~The costs and proceeds~~Changes in the fair value of ~~these~~ derivative instruments are deferred and recorded in regulatory accounts because they will be recovered or refunded through regulated ~~rates.~~rates in the future. 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				Balance At
(in millions)	March 31, 2008		December 31, 2007		June 30, 2008		December 31, 2007
Cost of removal obligation	$	2,628	$	2,568	$	2,650	$	2,568
Price risk management						803		124
Employee benefit plans		598		578		621		578
Asset retirement costs		497		573		455		573
Price risk management		314		124
Public purpose programs		276		264		285		264
California Solar Initiative		181		159		200		159
Other		169		182		171		182
Total regulatory liabilities	$	4,663	$	4,448	$	5,185	$	4,448

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

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

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

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

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

Price risk management regulatory liabilities relate to contracts to procure electricity and natural gas with terms in excess of one year designed to reduce commodity price risks that are accounted for as derivative instruments under SFAS No. 133. Changes in the fair value of derivative instruments are deferred and recorded in regulatory accounts because they are recovered or refunded through regulated rates.

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

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

Finally, “Other” is primarily related to amounts received from insurance companies to pay for hazardous substance remediation costs. The insurance recoveries are refunded to customers as a reduction to rates until customers are fully reimbursed for the amount of the costs ~~and~~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”). The liability for hazardous substance insurance recoveries is refunded to customers as a reduction to rates until they are fully reimbursed for total covered hazardous substance costs that they have paid to date. Gateway was acquired as part of a settlement with Mirant Corporation and the associated liability will be amortized over 30 years beginning in January 2009 when itGateway is anticipated to be placed in service.

Current Regulatory Liabilities

As of ~~March 31,~~June 30, 2008, the Utility had current regulatory liabilities of approximately ~~$823~~$1,016 million, consisting primarily of price risk management regulatory liabilities with terms of less than one ~~year, and unspent program funds returned by the California Energy Commission that will be refunded to customers.~~year. As of December 31, 2007, the Utility had current regulatory liabilities of approximately $280 million, primarily consisting of the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates. Current regulatory liabilities are included in Current Liabilities - Other in the Condensed Consolidated Balance Sheets.

Regulatory Balancing Accounts

The Utility uses revenue regulatory balancing accounts ~~as a mechanism~~ to ~~recover amounts incurred for certain costs, primarily commodity costs. Sales balancing accounts~~ accumulate differences between revenues and the Utility's authorized revenue ~~requirements. Cost~~requirements and cost regulatory balancing accounts to accumulate differences between incurred costs and ~~authorized revenue requirements. The Utility also can obtain CPUC approval for balancing account treatment of variances between forecasted and actual~~costs recovered, or collected (primarily commodity ~~costs and volumes. This approval eliminates the earnings impact from any revenue variances from adopted forecast levels.~~cost). Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities.

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

Current Regulatory Balancing Account Assets

	Balance At				Balance At
(in millions)	March 31, 2008		December 31, 2007		June 30, 2008		December 31, 2007
Electricity revenue and cost balancing accounts	$	1,129	$	678	$	1,277	$	678
Natural gas revenue and cost balancing accounts		50		93		80		93
Total	$	1,179	$	771	$	1,357	$	771

Current Regulatory Balancing Account Liabilities

Balance At
(in millions)
March 31,
2008

December 31,
2007

Electricity revenue and cost balancing accounts $ 554 $ 618
Natural gas revenue and cost balancing accounts 180 55
Total $ 734 $ 673

~~During the three months ended March 31, 2008, the under-collection in the Utility's electricity revenue and cost balancing account assets increased from December 31, 2007.~~ This change is primarily due to higher than forecasted procurement costs as a result of the Utility purchasing higher cost replacement power during the scheduled outage at the Diablo Canyon nuclear facility and termination of the contract between the California Department of Water Resources (“DWR”) and Calpine Corporation, which significantly reduced the volume of power provided by the DWR. Additionally, seasonal demand changes due to lower electric usage have increased this under-collection. The Utility expects this under-collection to decrease through additional revenue requirements authorized by the CPUC and increased electric usage during the summer months.

During the three months ended March 31, 2008, the over-collection in the Utility’s natural gas revenue and cost balancing account liabilities increased from December 31, 2007 mainly due to the increase in consumer demand for natural gas during the winter months. This is consistent with seasonal demand changes, and the over-collection is expected to decrease during the summer months when gas usage declines.

	Balance At
(in millions)	June 30, 2008		December 31, 2007
Electricity revenue and cost balancing accounts	$	828	$	618
Natural gas revenue and cost balancing accounts		96		55
Total	$	924	$	673

NOTE 4: DEBT

PG&E Corporation

Convertible Subordinated Notes

At ~~March 31,~~June 30, 2008, PG&E Corporation had outstanding approximately $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. Interest is payable semi-annually in arrears on June 30 and December 31. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,059 shares of PG&E Corporation common stock, at a conversion price of $15.09 per share. The conversion price is subject to adjustment for significant changes in the number of outstanding shares of PG&E Corporation’s common stock. In addition, holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion price. OnSince January ~~15, 2008 and April 15,~~1, 2008, PG&E Corporation has paid ~~a total of~~“pass-through dividends” totaling approximately ~~$14~~$21 million, ~~of “pass-through dividends.”~~including $7 million paid on July 15, 2008.

In accordance with SFAS No. 133, the dividend participation rights of the Convertible Subordinated Notes are considered to be embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation's Condensed Consolidated Financial Statements. Dividend participation rights are recognized as operating cash flows in PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. Changes in the fair value are recognized (in Other Income, Net) in PG&E Corporation's Condensed Consolidated Statements of Income as a non-operating expense or ~~income (in Other Income, Net).~~income. At ~~March 31,~~June 30, 2008, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately ~~$63~~$55 million, of which $27 million was classified ~~as a current liability (in~~in Current Liabilities - ~~Other)~~Other and ~~$36~~$28 million was classified ~~as a noncurrent liability (in~~in Noncurrent Liabilities - ~~Other)~~Other in the accompanying Condensed Consolidated Balance Sheets. At December 31, 2007, the total estimated fair value of the dividend participation rights, on a pre-tax basis, was approximately $62 million, of which $25 million was classified as a current liability ~~(in~~in Current Liabilities - ~~Other)~~Other and $37 million was classified as a noncurrent liability ~~(in~~in Noncurrent Liabilities - ~~Other)~~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 value, of which approximately $1 million was classified as a current liability (in Current Liabilities - Other) and $5 million was classified as a noncurrent liability (in Noncurrent Liabilities - Other) in the accompanying Condensed Consolidated Balance Sheets.fair value. (See Note 8 for further discussion of the implementation of SFAS No. 157.)

Utility

~~Statutory Liens~~

In the ordinary course of the Utility’s construction activities, contractors who work on and provide materials to projects may have certain statutory liens on such projects, which are released as construction progresses and payments are made for their work or materials.

Senior Notes

On March 3, 2008, the Utility issued $200 million principal amount of 5.625% Senior Notes due on November 30,

2017, ~~which increased~~increasing the total outstanding amount of ~~the~~ 5.625% Senior Notes ~~issued on December 4, 2007,~~ to $700 million. The Utility received proceeds of approximately $202 million from the offering, including a $3 million premium and net of $1 million in issuance costs. In addition, the Utility received approximately $3 million relating to accrued interest (the interest that has accumulated since the original issuance). Also on March 3, 2008, the Utility issued $400 million principal amount of 6.35% Senior Notes due on February 15, 2038. The Utility received proceeds of approximately $396 million from the offering, net of a $1 million discount and $3 million in issuance costs. The proceeds from the sale of the March 3, 2008 Senior Notes ~~offering~~offerings were used to repay outstanding commercial paper, for working capital purposes, and to fund capital expenditures.

At ~~March 31,~~June 30, 2008, there were $6.9 billion of Senior Notes outstanding.

Pollution Control Bonds

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

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

At ~~March 31,~~June 30, 2008, there were ~~$1.3~~$1.2 billion of pollution control bonds ~~outstanding (excluding the PC2005 bonds that were repurchased in March 2008).~~outstanding.

Working Capital Facility

At ~~March 31,~~June 30, 2008, there were approximately ~~$220~~$281 million of letters of credit and no borrowings outstanding under the Utility’s $2.0 billion working capital facility.

Commercial Paper Program

At ~~March 31,~~June 30, 2008, the Utility had ~~$73~~$156 million of commercial paper outstanding at an average yield of approximately ~~3.36%~~2.94%.

Energy Recovery Bonds

In furtherance of the Chapter 11 Settlement Agreement, PG&E Energy Recovery Funding LLC (“PERF”), a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion in 2005. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as "recovery property," to be paid a specified amount from a dedicated rate component. The total amount of ERB principal outstanding was ~~$1.9~~$1.8 billion at ~~March 31,~~June 30, 2008.

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

NOTE 5: SHAREHOLDERS' EQUITY

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

PG&E Corporation

Utility

(in millions)
Total Common Shareholders' Equity

Total
Shareholders' Equity

Balance at December 31, 2007 $ 8,553 $ 9,125
Net income 224 236
Common stock issued 39 -

							PG&E Corporation			Utility
(in millions)							Total Common Shareholders' Equity			Total Shareholders' Equity
Balance at December 31, 2007							$	8,553		$	9,125
Net income								517			549
Common stock issued								82			-
Share-based compensation amortization		10			-			15			-
Common stock dividends declared and paid		-			(142	)		(139	)		(284	)
Common stock dividends declared but not yet paid		(139	)		-			(140	)		-
Preferred stock dividends		-			(3	)		-			(7	)
Tax benefit from share-based payment awards		4			2			4			3
Other comprehensive income		2			2			5			5
Equity infusion		-			50			-			50
Balance at March 31, 2008	$	8,693		$	9,270
Balance at June 30, 2008							$	8,897		$	9,441

Dividends

During the ~~three~~six months ended ~~March 31,~~June 30, 2008, the Utility paid common stock dividends totaling ~~$153~~$305 million, including ~~$142~~$284 million of common stock dividends paid to PG&E Corporation and ~~$11~~$21 million of common stock dividends paid to PG&E Holdings, LLC, a wholly owned subsidiary of the Utility.

On ~~January 15,~~February 22, 2008, PG&E Corporation paid common stock dividends of $0.36 per share, totaling $137 million, including $9 million of common stock dividends paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. On April 15, 2008, PG&E Corporation paid common stock dividends ofdeclared its quarterly dividend at $0.39 per share, an increase of $0.03 per share over the previous level of $0.36 per share. During the six months ended June 30, 2008, PG&E Corporation paid common stock dividends totaling $284 million, including $18 million to its wholly owned subsidiary, Elm Power Corporation. On June 18, 2008, the Board of Directors of PG&E Corporation declared a dividend of $0.39 per share, totaling ~~$148~~$149 million, including $10 million ~~paid~~ to its wholly owned subsidiary, Elm Power ~~Corporation.~~Corporation that was paid on July 15, 2008 to shareholders of record on June 30, 2008.

~~On February 15,~~ During the six months ended June 30, 2008, the Utility paid cash dividends to holders of ~~various~~its outstanding series of preferred stock ~~in the aggregate amount of $3~~totaling $7 million. On ~~February 20,~~June 18, 2008, the Board of Directors of the Utility declared ~~dividends~~a cash dividend on ~~all~~its outstanding series of ~~its~~ preferred ~~stock. The dividends, totaling $4 million, are~~stock payable on ~~May~~August 15, 2008 to shareholders of record on ~~April 30,~~July 31, 2008.

NOTE 6: EARNINGS PER COMMON SHARE

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

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

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

	Three Months Ended				Three Months Ended				Six Months Ended
	March 31,				June 30,				June 30,
(in millions, except share amounts)	2008		2007
(in millions, except per share amounts)					2008		2007		2008		2007
Net income	$	224	$	256	$	293	$	269	$	517	$	525
Less: distributed earnings to common shareholders		139		126		139		127		278		253
Undistributed earnings	$	85	$	130	$	154	$	142	$	239	$	272
Common shareholders earnings
Basic
Distributed earnings to common shareholders	$	139	$	126	$	139	$	127	$	278	$	253
Undistributed earnings allocated to common shareholders						146		135		227		258
Total common shareholders earnings, basic					$	285	$	262	$	505	$	511
Diluted
Distributed earnings to common shareholders					$	139	$	127	$	278	$	253
Undistributed earnings allocated to common shareholders						146		135		227		258
Total common shareholders earnings, diluted					$	285	$	262	$	505	$	511
Weighted average common shares outstanding, basic						356		350		355		350
9.50% Convertible Subordinated Notes						19		19		19		19
Weighted average common shares outstanding and participating securities, basic						375		369		374		369
Weighted average common shares outstanding, basic						356		350		355		350
Employee share-based compensation						1		2		1		2
Weighted average common shares outstanding, diluted						357		352		356		352
9.50% Convertible Subordinated Notes						19		19		19		19

Undistributed earnings allocated to common shareholders 81 123
Total common shareholders earnings, basic $ 220 $ 249
Diluted
Distributed earnings to common shareholders $ 139 $ 126
Undistributed earnings allocated to common shareholders 81 123
Total common shareholders earnings, diluted $ 220 $ 249
Weighted average common shares outstanding, basic 355 349
9.50% Convertible Subordinated Notes 19 19
Weighted average common shares outstanding and participating securities, basic 374 368
Weighted average common shares outstanding, basic 355 349
Employee share-based compensation 1 2
Weighted average common shares outstanding, diluted 356 351
9.50% Convertible Subordinated Notes 19 19
Weighted average common shares outstanding and participating securities, diluted 375 370
Net earnings per common share, basic
Distributed earnings, basic (1)
$ 0.39 $ 0.36
Undistributed earnings, basic 0.23 0.35
Total $ 0.62 $ 0.71
Net earnings per common share, diluted
Distributed earnings, diluted $ 0.39 $ 0.36
Undistributed earnings, diluted 0.23 0.35
Total $ 0.62 $ 0.71

(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.

Weighted average common shares outstanding and participating securities, diluted		376		371		375		371
Net earnings per common share, basic
Distributed earnings, basic (1)	$	0.39	$	0.36	$	0.78	$	0.72
Undistributed earnings, basic		0.41		0.39		0.64		0.74
Total	$	0.80	$	0.75	$	1.42	$	1.46
Net earnings per common share, diluted
Distributed earnings, diluted	$	0.39	$	0.36	$	0.78	$	0.72
Undistributed earnings, diluted		0.41		0.38		0.64		0.73
Total	$	0.80	$	0.74	$	1.42	$	1.45


(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.

Options to purchase 7,285 shares of PG&E Corporation common stock were excluded from the computation of diluted EPS for the three and six months ended ~~March 31,~~June 30, 2008 ~~and 2007~~ 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

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

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

	Derivatives				Total Price Risk Management Derivatives				Price Risk Management Derivatives Designated as Cash Flow Hedges
(in millions)	March 31, 2008(1)		December 31, 2007(2)		June 30, 2008(1)		December 31, 2007(2)		June 30, 2008(3)		December 31, 2007(4)
Current Assets – Prepaid expenses and other	$	258	$	55	$	307	$	55	$	139	$	(2	)(5)
Other Noncurrent Assets – Other		260		171		418		171		162		42
Current Liabilities – Other						28		67		9		12
Noncurrent Liabilities – Other						37		20		-		3

Current Liabilities – Other 16 67
Noncurrent Liabilities – Other 21 20

(1) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $100 million decrease to Current Assets-Prepaid expenses and other, a $54 million decrease to Other Noncurrent Assets–Other, and a $1 million increase to Noncurrent Liabilities–Other.

(2) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $3 million increase to Current Assets-Prepaid expenses and other, a $46 million increase to Other Noncurrent Assets–Other, and a $16 million decrease to Current Liabilities–Other. These collateral amounts have been reclassified from Current Assets–Prepaid expenses as was presented in the 2007 Annual Report.

Derivative instruments may be designated as cash flow hedges when they hedge variable price risk associated with the purchase of commodities. Cash flow hedges are presented on a net basis by counterparty. The table below represents the portion of the derivative balances that were designated as cash flow hedges:

Cash Flow Hedges

(in millions)
March 31, 2008(1)

December 31, 2007(2)

Current Assets – Prepaid expenses and other $ 57 $ (2 ) (3)
Other Noncurrent Assets – Other 50 42
Current Liabilities – Other (2 ) (4) 12
Noncurrent Liabilities – Other - 3

(1) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $14 million decrease to Current Assets-Prepaid expenses and other and a $9 million decrease to Other Noncurrent Assets-Other.

(2) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $9 million increase to Other Noncurrent Assets-Other and a $7 million decrease to Current Liabilities-Other. These collateral amounts have been reclassified from Current Assets–Prepaid expenses as was presented in the 2007 Annual Report.

(3) $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.

(4) $2 million of the cash flow hedges in an asset position at March 31, 2008 relate to counterparties for which the total net derivatives position is a current liability.

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

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

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

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

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

As of ~~March 31,~~June 30, 2008, PG&E Corporation and the Utility had cash flow hedges with expiration dates through December 2012 for energy contract derivative instruments.

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

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

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

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, an entity must now determine the fair value of an asset or liability based on the assumptions that market participants would use in pricing the asset or liability, not those of the reporting entity itself. The identification of market participant assumptions provides a basis for determining what inputs are to be used for pricing each asset or liability. Additionally, SFAS No. 157 establishes a fair value hierarchy which gives precedence to fair value measurements calculated using observable inputs to those using unobservable inputs. Accordingly, the following levels were established for each input:

Level 1: “Inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.” Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments classified as Level 1 consist of financial instruments such as exchange traded 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 market is not active.

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

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

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

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

PG&E Corporation	PG&E Corporation									PG&E Corporation
Fair Value Measurements as of March 31, 2008
Fair Value Measurements as of June 30, 2008										Fair Value Measurements as of June 30, 2008
(in millions)		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets:
Nuclear Decommissioning Funds (1)		$	1,751	$	317	$	7	$	2,075		$	1,704	$	328	$	7	$	2,039
Price Risk Management Instruments(2)			45		137		299		481			169		109		382		660
Rabbi Trusts(3)			18		-		-		18			18		-		-		18
Long Term Disability Trust			29		-		103		132			25		-		95		120
Assets Total		$	1,843	$	454	$	409	$	2,706		$	1,916	$	437	$	484	$	2,837
Liabilities:
Dividend Participation Rights		$	-	$	-	$	63	$	63		$	-	$	-	$	55	$	55
Other			-		-		2		2			-		-		6		6
Liabilities Total											$	-	$	-	$	61	$	61


(1) Excludes taxes on appreciation of investment value and cash and cash equivalents.										(1) Excludes taxes on appreciation of investment value and cash and cash equivalents.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3.										(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3.
(3) Excludes life insurance policies.										(3) Excludes life insurance policies.

Utility
Fair Value Measurements as of June 30, 2008
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Nuclear Decommissioning Funds(1)	$	1,704	$	328	$	7	$	2,039
Price Risk Management Instruments(2)		169		109		382		660
Long-Term Disability Trust		25		-		95		120

Liabilities Total $ - $ - $ 65 $ 65

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

(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(95) million to Level 1, $(43) million to Level 2, and $(17) million to Level 3.

(3) Excludes life insurance policies.

Utility

Fair Value Measurements as of March 31, 2008

(in millions)
Level 1

Level 2

Level 3

Total

Assets:
Nuclear Decommissioning Funds (1)
$ 1,751 $ 317 $ 7 $ 2,075
Price Risk Management Instruments(2)
45 137 299 481
Long-Term Disability Trust 29 - 103 132
Assets Total $ 1,825 $ 454 $ 409 $ 2,688
Liabilities:
Other $ - $ - $ 2 $ 2
Liabilities Total $ - $ - $ 2 $ 2

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

(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(95) million to Level 1, $(43) million to Level 2, and $(17) million to Level 3.

Assets Total	$	1,898	$	437	$	484	$	2,819
Liabilities:
Other	$	-	$	-	$	6	$	6
Liabilities Total	$	-	$	-	$	6	$	6


(1) Excludes taxes on appreciation of investment value and cash and cash equivalents.
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3.

PG&E Corporation and the Utility’s fair value measurements incorporate various factors required under SFAS No. 157 such as the credit standing of the counterparties involved, PG&E Corporation and the Utility’s nonperformance risk on its liabilities, the applicable exit market, and specific risks inherent in the instrument. 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.

~~Price Risk Management Instruments~~

~~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, FTRs, and Demand Response (“DR”) Contracts are new and/or complex instruments that have immature or limited markets. FTRs allow market participants, including LSEs, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market prior to the operation of the MRTU day-ahead market. DRs primarily allow market participants, including LSEs, to manage their capacity requirements. In addition, DRs hedge financial risk associated with increased energy prices resulting from increased demand on the electricity grid. As these markets 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.

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 as 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 or dealer quotations. Such instruments are generally classified within Level 3 of the fair value hierarchy.

~~See Note 7 for further discussion of the price risk management instruments.~~

~~Trust Assets~~

The nuclear decommissioning funds, the rabbi trusts, 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 the Condensed Consolidated Financial Statements. The long-term disability trust is classified as Current Liabilities-Other in the Condensed Consolidated Financial Statements.

~~Dividend Participation Rights~~

The dividend participation rights of the Convertible Subordinated Notes are considered to be embedded derivative instruments in accordance with SFAS No. 133 and, therefore, are bifurcated. They are valued based on the net present value of estimated future cash flows using internal estimates of company dividends. These rights are recorded as Current Liabilities-Other and Noncurrent Liabilities-Other in the Condensed Consolidated Financial Statements. See Note 4 for further discussion of these instruments.

~~Level 3 Rollfoward~~Rollforward

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

PG&E Corporation	PG&E Corporation																			PG&E Corporation
(in millions)		Price Risk Management Instruments			Nuclear Decommissioning Funds(3)			Long-term Disability			Dividend Participation Rights			Other			Total				Price Risk Management Instruments			Nuclear Decommissioning Funds(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
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	)			-			-			-			(1	)		-			(1	)
Included in regulatory assets and liabilities or balancing accounts			184			(1	)		(6	)		-			2			179				267			(1	)		(7	)		-			(2	)		257
Purchases, issuances, and settlements			-			-			40			7			-			47				-			-			33			14			-			47
Transfers in/out of Level 3			-			-			-			-			-			-				-			-			-			-			-			-
Asset (Liability) Balance as of March 31, 2008		$	299		$	7		$	103		$	(63	)	$	(2	)	$	344
Asset (liability) Balance as of June 30, 2008																					$	382		$	7		$	95		$	(55	)	$	(6	)	$	423

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


(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 in accordance with the requirements of FIN 39-1 of $6 million.																				(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 in accordance with the requirements of FIN 39-1 of $6 million.
(2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions SFAS No. 157, resulting in a $6 million expense to increase the value of the liability.																				(2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions SFAS No. 157, resulting in a $6 million expense to increase the value of the liability.
(3)Excludes taxes on appreciation of investment value and cash and cash equivalents.																				(3)Excludes taxes on appreciation of investment value and cash and cash equivalents.

Utility
(in millions)	Price Risk Management Instruments			Nuclear Decommissioning Funds(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		267			(1	)		(7	)		(2	)		257
Purchases, issuances, and settlements		-			-			33			-			33
Transfers in/out of Level 3		-			-			-			-			-
Asset (liability) Balance as of June 30, 2008	$	382		$	7		$	95		$	(6	)	$	478

Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at the reporting date.


(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 in accordance with the requirements of FIN 39-1 of $6 million.
(2)Excludes taxes on appreciation of investment value and cash and cash equivalents.

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

PG&E Corporation
(in millions)	Price Risk Management Instruments		Nuclear Decommissioning Funds(1)		Long-term Disability			Dividend Participation Rights			Other			Total
Asset (liability) Balance as of March 31, 2008	$	299	$	7	$	103		$	(63	)	$	(2	)	$	344
Realized and unrealized gains (losses):
Included in earnings		-		-		-			1			-			1
Included in regulatory assets and liabilities or balancing accounts		83		-		(1	)		-			(4	)		78
Purchases, issuances, and settlements		-		-		(7	)		7			-			-
Transfers in/out of Level 3		-		-		-			-			-			-
Asset (liability) Balance as of June 30, 2008	$	382	$	7	$	95		$	(55	)	$	(6	)	$	423


Earnings for the period were ~~not~~ impacted by ~~changes in~~a $1 million unrealized ~~gains or (losses)~~gain relating to assets or liabilities still held at the reporting date.

Utility	Utility															Utility
(in millions)		Price Risk Management Instruments			Nuclear Decommissioning Funds(2)			Long-term Disability			Other			Total			Price Risk Management Instruments		Nuclear Decommissioning Funds(1)		Long-term Disability			Other			Total
Asset (Liability) Balance as of January 1, 2008		$	115	(1)	$	8		$	69		$	(4	)	$	188
Asset (liability) Balance as of March 31, 2008																	$	299	$	7	$	103		$	(2	)	$	407
Realized and unrealized gains (losses):
Included in earnings			-			-			-			-			-			-		-		-			-			-
Included in regulatory assets and liabilities or balancing accounts			184			(1	)		(6	)		2			179			83		-		(1	)		(4	)		78
Purchases, issuances, and settlements			-			-			40			-			40			-		-		(7	)		-			(7	)
Transfers in/out of Level 3			-			-			-			-			-			-		-		-			-			-
Asset (Liability) Balance as of March 31, 2008		$	299		$	7		$	103		$	(2	)	$	407
Asset (liability) Balance as of June 30, 2008																	$	382	$	7	$	95		$	(6	)	$	478

Earnings for the period were not impacted by changes in unrealized gains or (losses) relating to assets or liabilities still held at the reporting date.
Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at the reporting date.																Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at the reporting date.


(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 in accordance with the requirements of FIN 39-1 of $6 million.
(2)Excludes taxes on appreciation of investment value and cash and cash equivalents.
(1) Excludes taxes on appreciation of investment value and cash and cash equivalents.																(1) Excludes taxes on appreciation of investment value and cash and cash equivalents.

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

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services are priced at their fully loaded costs (i.e., direct cost of good or service plus all applicable indirect charges and overheads). 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. The Utility's significant related party transactions and related receivable (payable) balances were as follows:


	Three Months Ended				Receivable / (Payable) Balance Outstanding at				Three Months Ended				Six Months Ended				Receivable (Payable) Balance Outstanding at
	March 31,				March 31,		December 31,		June 30,				June 30,				June 30,		December
(in millions)	2008		2007		2008		2007		2008		2007		2008		2007		2008		2007
Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	1	$	2	$	2	$	1	$	1	$	2	$	2	$	-	$	2
Utility employee benefit assets due from PG&E Corporation		-		-		28		27		-		-		-		-		27		27
Interest from PG&E Corporation on employee benefit assets										-		1		-		1		-		-
Utility expenses from:

Utility expenses from:
Administrative services received from PG&E Corporation $ 24 $ 24 $ (27 ) $ (28 )
Utility employee benefit asset contributions provided to PG&E Corporation - 1 - -

Administrative services received from PG&E Corporation		$	28			$	28			$	52			$	52			$	(24	)		$	(28	)
Utility employee benefit assets due to PG&E Corporation			1				1				1				2				-				-

NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

~~In connection with~~Various electricity suppliers filed claims in the Utility’s ~~reorganization~~proceeding under Chapter 11 ofseeking payment for energy supplied to the ~~U.S. Bankruptcy Code, on April 12, 2004,~~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 ~~deposited approximately $1.7 billion into escrow for the payment of certain~~ disputes (“Disputed ~~Claims that had been made by generators and power suppliers for transactions that occurred during the 2000-2001 California energy crisis. The Disputed Claims~~Claims”), are being addressed in various FERC and judicial proceedings ~~seeking refunds on behalf of California electricity purchasers (including~~in which the State of California, the Utility, and ~~the Utility)~~other electricity purchasers, are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the ~~Power Exchange (“PX”)~~PX wholesale electricity markets between May 2000 and June 2001. ~~Many issues raised in these~~

While the FERC and judicial proceedings ~~including~~have been pending, the extent of the FERC's refund authority, and the amount of potential refunds after taking into account certain costs incurred by the electricity suppliers have not been resolved. It is uncertain when these proceedings will be concluded.

The Bankruptcy Court retains jurisdiction over the Utility’s escrowed funds (in addition, the Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of (1) the Chapter 11 Settlement Agreement, (2) the Utility’s plan of reorganization under Chapter 11, and (3) the Bankruptcy Court's order confirming the plan of reorganization).

~~The~~ Utility ~~has~~ entered into a number of settlements with various electricity suppliers ~~resolving~~to resolve some of these Disputed Claims and to resolve the Utility's refund claims against these electricity suppliers. ~~The Bankruptcy Court has approved the release of $0.8 billion from escrow in connection with these settlements.~~

Through March 31, 2008, the Utility has received consideration of approximately $625 million under these settlements as reduction to the Utility's PX liability. The Utility also has received consideration of approximately $587 million through cash proceeds and the acquisition of the Gateway generating facility. 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.

~~During~~ The proceeds from these settlements, after deductions for contingencies based on the ~~quarter ended March 31, 2008,~~outcome of the ~~Utility received approximately $1 million in cash-equivalent reductions~~various refund offset and interest issues being considered by the FERC, will continue to ~~its PX liability and, in April 2008, received an additional $51 million. These amounts will~~ be refunded to customers ~~through~~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 (after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC).~~ customers.

As of ~~March 31,~~June 30, 2008, the ~~amount of~~Utility’s liability for the ~~accrual for~~ remaining net Disputed Claims was approximately ~~$1.1~~$1.7 billion, consisting of approximately $1.6 billion of remaining Disputed Claims (classified on the Condensed Consolidated Balance Sheet as accounts ~~payable-Disputed Claims primarily payable to~~payable) and interest accrued at the ~~CAISO and~~FERC-ordered rate of $0.6 billion (classified on the ~~PX,~~Condensed Consolidated Balance Sheet as interest payable) offset by an accounts receivable from the CAISO and the PX of approximately $0.5 ~~billion. The~~billion (included within accounts receivable on the Condensed Consolidated Balance Sheet). These amounts do not include potential remaining refund amounts that may be due to the Utility as a result of the FERC refund proceedings.

As of June 30, 2008, the Utility held $1.2 billion ~~(including interest)~~ in escrow, asincluding approximately $0.1 billion of ~~March 31, 2008,~~earned interest, for payment of the remaining net Disputed ~~Claims. The amount held in escrow is classified~~Claims (classified as Restricted ~~cash~~Cash in the Condensed Consolidated Balance ~~Sheets.~~Sheet).

~~As of March 31, 2008, interest~~Interest accrues on the ~~net~~liability for Disputed Claims ~~balance, calculated~~ at the FERC-ordered ~~interest~~ rate, ~~amounted to approximately $614 million (classified as Interest payable in~~which is higher than the ~~Condensed Consolidated Balance Sheets). The~~ rate ~~of interest actually~~ earned by the Utility on the ~~escrowed amounts, however, is less than~~escrow balance. Although the ~~FERC-ordered interest rate. The~~ Utility has been collecting the difference between the ~~earned amount~~accrued interest and the ~~accrued~~earned interest from customers, this amount ~~from customers. These amounts are~~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 ~~generators,~~Disputed Claims, the Utility would refund to customers any excess net interest collected from customers. The ~~ultimate~~ amount of any interest that the Utility may be required to pay will depend on the final ~~amount of refunds determined~~amounts to be ~~owed~~paid by the Utility with respect to the ~~Utility.~~Disputed Claims.

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

NOTE 11: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility's operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, 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 electricity and makes payments under existing power purchase agreements. At ~~March 31,~~June 30, 2008, the undiscounted future expected power purchase agreement payments based on ~~March 31,~~June 30, 2008 forward prices were as follows:

(in millions)
2008	$	1,989	$	1,526
2009		2,447		2,877
2010		2,199		2,653
2011		2,129		2,609
2012		2,015		2,481
Thereafter		16,588		19,924
Total	$	27,367	$	32,070

Payments made by the Utility under power purchase agreements amounted to approximately ~~$1,028~~$2,284 million and ~~$655~~$1,504 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 30, 2007, respectively. The amounts above do not include payments related to the ~~DWR~~California Department of Water Resources (“DWR”) purchases ~~since~~for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

The following table shows the future fixed capacity payments due under qualifying facility (“QF”) contracts that are treated as capital leases. These amounts are also included in the third-party power purchase agreements table above. The fixed capacity payments are discounted to their present value in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.

(in millions)
2008	$	43	$	29
2009		50		50
2010		50		50
2011		50		50
2012		50		50
Thereafter		253		253
Total fixed capacity payments		496		482
Less: Amount representing interest		125		(120	)
Present value of fixed capacity payments	$	371	$	362

Minimum lease payments associated with the lease obligation are included in Cost of Electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. 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 ~~March 31,~~June 30, 2008, the Utility's undiscounted obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2008 $ 1,247
2009 599
2010 93
2011 80
2012 49
Thereafter 199
Total $ 2,267

(in millions)
2008	$	1,074
2009		915

2010		93
2011		80
2012		49
Thereafter		199
Total	$	2,410

Payments for natural gas purchases and gas transportation services amounted to approximately ~~$797~~$1,589 million and ~~$728~~$1,230 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 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~~Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company. PG&E Corporation's sole remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. At ~~March 31,~~June 30, 2008, PG&E Corporation’s potential exposure under this guarantee was immaterial and PG&E Corporation has not made any provision for this guarantee.

Utility

Application to Recover Hydroelectric Facility Divestiture Costs

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

California Department of Water Resources Contracts

Electricity purchased under the DWR allocated contracts with various generators provided approximately ~~16.6%~~15.2% of the electricity delivered to the Utility's customers for the ~~three~~six months ended ~~March 31,~~June 30, 2008. The DWR remains legally and financially responsible for its electricity procurement contracts. The Utility acts as a billing and collection agent of the DWR's revenue requirements from the Utility's customers.

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

·	After assumption, the Utility's issuer rating by Moody’s Investors Service (“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.

~~On February 28, 2008, the~~The CPUC ~~issued a decision that states the CPUC will proactively~~has been holding various workshops with interested parties to investigate whether DWR can terminate its obligations under the power purchase contracts, by assignment or otherwise.

Incentive Ratemaking for Energy Efficiency Programs

The CPUC has established an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. The maximum amount of incentives that the Utility may receive and the amount of any reimbursement obligations the Utility may incur over the 2006-2008 program cycle is $180 million. The ~~actual amount and timing of the~~ financial impact will depend on the amount of any shareholder incentives the Utility may receive or the amount of any reimbursement obligations the Utility may incur based on the level of energy efficiency savings actually achieved over the three-year program cycle ~~the amount of the savings attributable to the Utility’s energy efficiency programs,~~ and when the applicable accounting standard for recognizing incentives or reimbursement obligations is met.

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”). The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $38.5 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Under the Terrorism Risk Insurance Program Reauthorization Act of 2007 (“TRIPRA”), acts of terrorism may be “certified” by the Secretary of the Treasury. For a certified act of terrorism, NEIL can obtain compensation from the federal government and will provide up to the full policy limits to the Utility for an insured loss. If one or more non-certified acts of terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion within a 12-month period plus the additional amounts recovered by NEIL for these losses from reinsurance. (TRIPRA extends the Terrorism Risk Insurance Act of 2002 through December 31, 2014.)

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for Diablo Canyon. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 megawatts (“MW”) or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $15 million per incident until the Utility has fully paid its share of the liability. Since Diablo Canyon has two nuclear reactors, each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $30 million per incident. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before August 20, 2008.

In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the Nuclear Regulatory Commission 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 ~~March 31,~~June 30, 2008, the Utility estimated future severance costs will range from ~~$34~~$32 million to ~~$48~~$52 million, given the uncertainty of each of these variables. The Utility has recorded a liability of ~~$34~~$32 million as of ~~March 31,~~June 30, 2008. The following table presents the changes in the liability from December 31, 2007:

(in millions)
Balance at December 31, 2007	$	30		$	30
Additional severance accrued		6			15
Less: Payments		(2	)		(13	)
Balance at March 31, 2008	$	34
Balance at June 30, 2008				$	32

Environmental Matters

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

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of ~~reasonably likely~~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 ~~reasonably~~ possible outcomes that are least favorable to the Utility. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives.

The Utility had an undiscounted and gross environmental remediation liability of approximately ~~$555~~$538 million at ~~March 31,~~June 30, 2008, and approximately $528 million at December 31, 2007. The ~~$555~~$538 million accrued at ~~March 31,~~June 30, 2008 consists of:

·	Approximately ~~$228~~$221 million for remediation at the Hinkley and Topock natural gas compressor sites;

·	Approximately ~~$90~~$83 million related to remediation at divested generation facilities;

·	Approximately ~~$185~~$182 million related to remediation costs for the Utility’s generation and other facilities, third-party disposal sites, and manufactured gas plant sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites); and

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

Of the approximately ~~$555~~$538 million environmental remediation liability, approximately ~~$133~~$126 million has been included in prior rate setting proceedings. The Utility expects that an additional amount of approximately ~~$335~~$328 million will be recoverable in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

greater than ~~anticipated.~~anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The amount of approximately ~~$912~~$895 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

The Utility's Diablo Canyon power plant uses a process known as “once through cooling” that takes in water from the ocean to cool the generating facility and discharges the heated water back into the ocean. There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the U.S. Environmental Protection Agency (“EPA”) ~~published~~issued regulations ~~under~~to implement Section 316(b) of the Clean Water Act that apply to existing electricity generation facilities that use over 50 million gallons of water per day, which typically include some form of "once-through" cooling in which water from natural bodies of water is used to cool a generating facility and the heated water is discharged back into the source. The Utility's Diablo Canyon power plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The EPA regulations are intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations ~~allow site-specific compliance measures if~~provided each facility with a ~~facility's cost~~number of compliance ~~is significantly greater than either the benefits to be achieved or the compliance costs considered by the EPA.~~options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also ~~allow~~allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In response to the EPA regulations, ~~in March 2008,~~ the California State Water Resources Control Board (“Water Board”) ~~published~~issued a ~~revised draft of its~~ proposed policy ~~for California’s implementation~~to address once through cooling. The Water Board’s current proposal would require the installation of Section 316(b) that was originally issued in June 2006 and that proposes to eliminate the EPA’s site-specific compliance options, although the draft state policy would permit environmental restoration as a compliance option forcooling towers at nuclear facilities ifby January 1, 2021, unless the installation of cooling towers would conflict with a nuclear safety requirement.

Various parties separately challenged the EPA's regulations and in ~~court and the EPA regulations were suspended. The cases were consolidated in~~January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”)~~. In January 2007, the~~ 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 ~~held that a cost-benefit test could not~~ ~~be used to comply with performance standards or to obtain a variance from~~in July 2007 the ~~standards. The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard.~~EPA suspended its regulations. In April 2008, the U.S. Supreme Court ~~indicated it will~~agreed to review the Second Circuit decision regarding the cost-benefit ~~test. It~~test and a decision is ~~uncertain when the Supreme Court will issue a decision.~~expected by mid-2009. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo ~~Canyon.~~Canyon and may incur a material charge.

California Labor Code Issues

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

In April 2007, the California Supreme Court ruled that this California law requiring employers to pay an employee an additional hour of pay for each work day that a required meal period is not provided is a “wage” rather than a penalty, subject to a three-year statute of limitations rather than the one-year statute of limitations for penalty payments. Prior to this decision, the Utility believed that its collective bargaining agreement with the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”), which did not provide certain employee groups a continuous 30-minute meal period, preempted state law.

In July 2007, the Utility established a joint committee composed of the IBEW and Utility representatives to review the Utility’s current collective bargaining agreements to ensure compliance with California labor law in light of the California Supreme Court’s ruling. In June 2007, the Utility and the IBEW reached an agreement under which employees whose eight-hour shifts do not allow for an uninterrupted 30-minute meal break will be paid one hour of pay for each 30-minute meal period missed going back 39 months. In ~~connection with this agreement,~~July 2007, the Utility ~~has expensed approximately $23 million through March 31, 2008 for payments~~established a joint committee composed of the IBEW and Utility representatives to ~~approximately 2,076 employees.~~review the Utility’s current collective bargaining agreements to ensure compliance with California labor law in light of the California Supreme Court’s ruling. The Utility is continuing to investigate whether other employees may be entitled to payment for a missed or delayed meal. ~~Until this investigation is complete,~~In connection with these matters, the Utility has paid approximately $24 million as of June 30, 2008. At June 30, 2008, the Utility has accrued an additional $5.1 million for probable future payments. The Utility is unable to ~~determine~~estimate the additional amount of loss ~~that~~ it may incur in connection with this matter. The ultimate outcome of ~~this matter~~these matters may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition or results of operations.

Tax Matters

In the first quarter of 2008, PG&E Corporation ~~finalized~~reached a settlement with the Internal Revenue Service (“IRS”) appellate division for tax years 1997-2000. On July 9, 2008, PG&E Corporation was notified that the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) had approved the settlement. This settlement did not result in material changes to the amount of unrecognized tax benefits ~~at December 31, 2007~~ that PG&E Corporation ~~recognized~~recorded under FASB Interpretation No. 48, “Accounting for Uncertainty in Income ~~Taxes” (“FIN 48”).~~Taxes.”

~~In addition, during the first quarter of~~

On June 20, 2008, PG&E Corporation reached ~~a tentative settlement~~an agreement with the IRS regarding a change in accounting method related to the capitalization of indirect service costs for tax years ~~2001-2002 that would resolve issues raised~~2001-2004. This agreement resulted in a $29 million benefit from a reduction in interest expense accrued on unrecognized tax benefits partially offset by a $15 million liability associated with unrecognized state tax benefits, for a net tax benefit of approximately $14 million. On June 27, 2008, PG&E Corporation agreed to a revenue agent report (“RAR”) from the IRS ~~with respect~~that reflected this agreement and resolved all 2001-2002 audit issues, except a dispute relating to ~~several significant deductions taken by PG&E Corporation related to losses sustained at NEGT. The IRS has indicated that it intends to allow deductions in its audits of~~ PG&E Corporation’s tax returns for tax years 2003-2004 that it disallowed in tax years 2001–2002. The tentative settlement also would resolve certain issues related to the Utility. Remaining issues that are not part of the tentative settlement, including whether PG&E Corporation is entitledentitlement to $104 million inof synthetic fuel tax credits, ~~will be~~which was referred to the IRS appellate ~~division.~~

division, and all 2003-2004 audit issues. The IRS ~~has indicated that~~will forward the RAR to the IRS appellate division, and it ~~intends to complete its audit examination of tax years 2003-2004 by the third quarter of 2008. The settlement of the 2001-2002 audit~~will be finalized when PG&E Corporation and the ~~2003-2004 audit would~~IRS appellate division resolve the issue regarding synthetic fuel tax credits. At that time, the RAR will be ~~subject~~submitted to ~~approval by~~ the ~~U.S. Congress’~~ Joint Committee ~~on Taxation.~~for approval.

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

The IRS is currently auditing tax years 2005-2006. PG&E Corporation ~~expects the IRS to begin~~filed its ~~audit~~federal return for tax ~~years 2005-2006 during the second quarter of~~year 2007 in July 2008. ~~The audit for the 2007~~Beginning in tax year ~~will begin shortly after~~2008, PG&E Corporation ~~files its tax return by September 15, 2008. Finally, the 2008 tax year will be under audit as part of~~began participating in the IRS’ Compliance Assurance Process, a real-time audit ~~process.~~process intended to expedite the resolution of issues raised during audits.

Currently, PG&E Corporation has ~~$247~~$268 million of federal capital loss carry forwards based on tax returns as filed, primarily resulting from the disposition of NEGT stock in ~~2004, which,~~2004. The majority of the federal capital loss carry forwards, if not used by December 2009, will expire. The settlement of the ~~2001-2002 audit together with the completion of the 2003-2004 audit could~~2001-2004 audits may result in utilization of a significant portion of the federal capital loss carry forwards. However, because the settlement ofis subject to the ~~2003-2004 audit remains uncertain, no~~Joint Committee’s approval, PG&E Corporation has not recognized any benefits ~~have been recognized.~~from the federal capital loss carry forwards.

The California Franchise Tax Board is currently auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns. To date, no material adjustments have been proposed. In addition to the federal capital loss carry forwards, PG&E Corporation has $2.1 billion of California capital loss carry forwards based on tax returns as filed, the majority of which, if not used by December 2008, will expire.

Legal Matters

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

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

The accrued liability for legal matters is included in PG&E Corporation's and the Utility's Current Liabilities - Other in the Condensed Consolidated Balance Sheets, and totaled approximately ~~$56~~$51 million at ~~March 31,~~June 30, 2008 and approximately $78 million at December 31, 2007.

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

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 ~~March 31,~~June 30, 2008. The Utility had approximately ~~$37.1~~$38.3 billion in assets at ~~March 31,~~June 30, 2008 and generated revenues of approximately ~~$3.7~~$7.3 billion in the ~~three~~six months ended ~~March 31,~~June 30, 2008.

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

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

Summary of Changes in Earnings per Common Share and Net Income for the Three and Six Months Ended ~~March 31,~~June 30, 2008

For the three months ended June 30, 2008, PG&E Corporation’s diluted earnings per common share (“EPS”) ~~for the three months ended March 31, 2008~~ was ~~$0.62 per share,~~$0.80 compared to ~~$0.71 per share~~$0.74 for the same period in 2007. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, PG&E Corporation’s diluted EPS was $1.42 compared to $1.45 for the same period in 2007. PG&E Corporation’s net income ~~decreased~~for the three months ended June 30, 2008 increased by approximately ~~$32~~$24 million, or ~~13%~~9%, to ~~$224~~$293 million, compared to ~~$256~~$269 million for the same period in 2007. For the six months ended June 30, 2008, net income decreased by approximately $8 million, or 2%, to $517 million, compared to $525 million for the same period in 2007.

The ~~decrease~~increase in diluted EPS and net income for the three months ended ~~March 31,~~June 30, 2008 compared to the same period in 2007 is primarily due to (1) the Utility’s return on equity (“ROE”) on higher ~~expenses associated with~~authorized capital investments (representing a $23 million increase in net income as compared to the ~~extended~~same period in the prior year), and (2) lower refueling ~~outage~~expenses at the Diablo Canyon nuclear ~~facility~~generating facilities (“Diablo Canyon”) than the prior year due to ~~replace~~ the ~~steam generators~~timing of the outage (resulting in ~~Unit 2 (representing~~ a ~~$27~~$21 million increase in net income). These increases to net income were partially offset by increased operating and maintenance expenses associated with the natural gas system (resulting in a $6 million decrease in net income as compared to the same period in the prior year). ~~There was no comparable refueling outage~~

The decrease in diluted EPS and net income for the ~~first quarter of 2007. In addition, the Utility incurred higher storm-related costs in the first quarter of~~six months ended June 30, 2008 compared to the ~~first quarter of~~same period in 2007 is primarily due to (1) higher storm and outage-related costs, largely due to severe winter weather that occurred in January 2008 ~~(representing~~(resulting in a ~~$25~~$26 million decrease in net income as compared to the same period in the prior year)~~. These decreases~~, (2)

increased refueling expenses at Diablo Canyon as compared to the same period in the prior year 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~~income), (3) increased operating and ~~EPS were partially offset by an increase~~maintenance expenses associated with the natural gas system (resulting in a $10 million decrease in net income), and (4) other increased expenses (resulting in a $16 million decrease in net income). Most of the decreases in net income was offset by the Utility’s ~~return~~ROE on ~~equity (“ROE”) on~~higher authorized capital investments ~~authorized by the CPUC in the Utility’s General Rate Case (“GRC”) and by the FERC in the Utility’s transmission owner (“TO”) rate case~~ (representing a ~~$28~~$51 million increase in net income as compared to the same period in the prior year).

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its

authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation's and the Utility's results of operations and financial condition, including:

·	The Outcome of Regulatory Proceedings 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 based on its costs of service, in proceedings such as the ~~GRC~~General Rate Case (“GRC”) filed with the CPUC and transmission owner (“TO”) rate cases filed with the FERC. On July 30, 2008, the Utility filed a new TO rate ~~cases.~~case requesting a retail revenue requirement of approximately $849 million and a rate increase, effective October 1, 2008, to recover the costs associated with significant electric transmission infrastructure expansion and replacement. From time to time, the Utility also files separate applications requesting the CPUC or the FERC to authorize additional revenue requirements for specific projects, such as new power plants, gas or electric transmission projects, and the advanced metering infrastructure. On May 15, 2008, the Utility requested that the CPUC approve additional funding to improve customer service and reliability beyond the level assumed in the last GRC. The Utility’s revenues can also be affected by incentive ratemaking, such as the CPUC’s customer energy efficiency shareholder incentive mechanism. ~~The CPUC expects to adopt revised assumptions for evaluating and measuring energy savings by June 30, 2008 and to complete its verification of installed energy efficiency measures by July 15, 2008.~~ The amount of incentives the Utility may receive and the amount of any reimbursement obligations the Utility may incur will depend on the level of energy efficiency savings actually achieved over the three-year program cycles (2006-2008 and 2009-2011) and the effectiveness of the utilities’ programs in achieving the savings, based on the revised assumptions and verification results. Among other anticipated regulatory filings, the Utility’s application to the CPUC for funding authorization for its 2009-2011 energy efficiency programs is due June 23, 2008.. (See “Regulatory Matters” below.) Finally, the outcome of regulatory proceedings may also be affected by increases in the prices of natural gas and electricity as these costs are passed through to customers in the form of higher rates.

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

·	The Ability of the Utility to Control Costs ~~While Improving Reliability~~. The Utility’s revenue requirements are primarily set based on forecasted operating expenses and capital expenditures. The Utility’s revenue requirements are designed to allow the Utility to earn an ROE, as well as to recover depreciation, tax, and interest expense associated with authorized capital expenditures. Material differences ~~between~~in the amount or timing of forecasted and actual ~~amounts or timing of~~operating expenses and capital expenditures can materially affect the Utility’s ability to earn its authorized rate of ~~return.~~return and the amount of PG&E Corporation’s net income available for shareholders. In particular, the Utility anticipates that it will incur higher expenses than originally forecasted in the GRC in connection with the operations and maintenance of its natural gas system and maintenance of aging infrastructure. The Utility ~~implemented various initiatives designed~~intends to increase cost efficiencies, achieve operational excellence, and improve customer service. One major initiative involving new work processes, information systems and technology has resulted in delays and increased costs to respond to customer requests for new service, although the Utility has made progress in remedying the problems. ~~The Utility will~~ continue its efforts to identify and implement ~~additional~~initiatives to achieve operational efficiencies to ~~achieve~~create future sustainable cost-savings and to offset increased spending related to ~~address operational issues~~the natural gas system and the increasing cost of materials. (See “Results of Operations – Operating and Maintenance” below.) ~~In addition to~~ When capital ~~expenditures authorized by the CPUC~~is placed in ~~the GRC and by the FERC in the TO~~service at a higher rate ~~cases, the CPUC has authorized~~than forecasted, the Utility ~~to make substantial capital expenditures for the SmartMeter~~TM advanced metering project, to invest in new generation resources, and to improve existing generation facilities. The Utility has incurred, and anticipates that it will continue to incur, a higher level of capital expenditures than the authorized amounts. Although the Utility incurs associated depreciation, property tax, and interest ~~expense associated with this higher level of capital expenditures, the Utility’s authorized revenue requirements do~~expense. The Utility does not ~~provide for the recovery of~~recover an ROE on the higher level of capital expenditures until added to rate base in future rate cases. The Utility’s financial condition and results of operations will be impacted by the amount of revenue requirements it is authorized to recover, the amount and timing of its capital expenditures, and whether the Utility is able to manage its operating costs and capital expenditures within authorized revenues.

The Amount and Timing of Debt and Equity Financing Needs. During the first quarter of 2008, the Utility issued $600 million of long-term debt to finance capital expenditures and for working capital. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s needs for additional financing during 2008 and future years will be affected by the amount and timing of capital expenditures, as well as by the amount and timing of interest payments related to the remaining disputed claims that were made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Disputed Claims”). (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) In addition, the Utility’s financing needs will be affected by when certain pollution control bonds aggregating $454 million that the Utility repurchased during March and April 2008 ~~are~~can be resold. The Utility’s financial condition and results of operations will be affected by the interest rates, timing, and terms and conditions of any such ~~financing.~~financings. The timing and amount of PG&E Corporation’s future equity contributions to the Utility will affect the timing and amount of any ~~new~~ PG&E Corporation equity issuances and/or debt issuances which, in turn, will affect PG&E Corporation’s results of operations and financial condition. (See “Liquidity and Financial Resources” below.)

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

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

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

·	operating performance of Diablo Canyon, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;

·	whether the Utility can maintain the cost ~~efficiencies~~savings it has recognized from ~~its completed initiatives to improve its business processes and customer service~~operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures;

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

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

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

·	the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;

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

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

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

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

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

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

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

RESULTS OF OPERATIONS

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

		Three Months ended March 31,							Three Months Ended						Six Months Ended
		2008			2007				June 30,						June 30,
(in millions)									2008			2007			2008			2007
Utility
Electric operating revenues		$	2,514		$	2,175			$	2,645		$	2,359		$	5,159		$	4,534
Natural gas operating revenues			1,219			1,181				933			828			2,152			2,009
Total operating revenues			3,733			3,356				3,578			3,187			7,311			6,543
Cost of electricity			1,027			723				1,097			884			2,124			1,607
Cost of natural gas			775			754				487			396			1,262			1,150
Operating and maintenance			1,036			919				991			921			2,027			1,840
Depreciation, amortization, and decommissioning			402			429				418			430			820			859
Total operating expenses			3,240			2,825				2,993			2,631			6,233			5,456
Operating income			493			531				585			556			1,078			1,087
Interest income			24			48				33			35			57			83
Interest expense			(180	)		(182	)			(178	)		(178	)		(358	)		(360	)
Other income, net(1)			16			6				3			11			19			17
Income before income taxes			353			403				443			424			796			827
Income tax provision			120			145				134			154			254			299
Income available for common stock		$	233		$	258			$	309		$	270		$	542		$	528
PG&E Corporation, Eliminations, and Other(2)
PG&E Corporation, Eliminations and Other(2)
Operating revenues		$	-		$	-			$	-		$	-		$	-		$	-
Operating expenses			-			2				1			1			1			3
Operating loss			-			(2	)			(1	)		(1	)		(1	)		(3	)
Interest income			2			4				-			2			2			6
Interest expense			(7	)		(8	)			(7	)		(7	)		(14	)		(15	)
Other expense, net			(14	)		(2	)			(2	)		(1	)		(16	)		(3	)
Loss before income taxes			(19	)		(8	)			(10	)		(7	)		(29	)		(15	)
Income tax benefit			(10	)		(6	)
Income tax provision (benefit)										6			(6	)		(4	)		(12	)
Net loss		$	(9	)	$	(2	)		$	(16	)	$	(1	)	$	(25	)	$	(3	)
Consolidated Total
Operating revenues		$	3,733		$	3,356			$	3,578		$	3,187		$	7,311		$	6,543
Operating expenses			3,240			2,827				2,994			2,632			6,234			5,459
Operating income			493			529				584			555			1,077			1,084
Interest income			26			52				33			37			59			89
Interest expense			(187	)		(190	)			(185	)		(185	)		(372	)		(375	)
Other income, net(1)			2			4				1			10			3			14
Income before income taxes			334			395				433			417			767			812
Income tax provision			110			139				140			148			250			287
Net income		$	224		$	256			$	293		$	269		$	517		$	525


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

Utility

The following presents the Utility's operating results for the three and six months ended ~~March 31,~~June 30, 2008 and 2007.

Electric Operating Revenues

The Utility provides electricity to residential, industrial, and small and large commercial customers through its own generation facilities and through contracts with third parties under power purchase agreements. 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.~~services, as well as amounts charged to customers to recover the cost of public purpose programs, energy efficiency programs, and demand side management.

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

		Three Months Ended							Three Months Ended						Six Months Ended
		March 31,							June 30,						June 30,
(in millions)		2008			2007				2008			2007			2008			2007
Electric revenues		$	2,841		$	2,726			$	2,948		$	2,868		$	5,789		$	5,594
DWR pass-through revenues (1)			(327	)		(551	)			(303	)		(509	)		(630	)		(1,060	)
Total electric operating revenues		$	2,514		$	2,175			$	2,645		$	2,359		$	5,159		$	4,534
Total electricity sales (in Gigawatt hours)(2)			17,336			14,778				18,141			16,177			35,477			30,955


(1) These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income.	(1) These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income.							(1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income.
(2)These volumes exclude electricity provided by DWR.								(2)These volumes exclude electricity provided by DWR.

The Utility’s electric operating revenues increased by approximately $286 million, or 12%, in the three months ended ~~March 31,~~June 30, 2008 byand approximately ~~$339~~$625 million, or ~~approximately 16%~~14%, in the six months ended June 30, 2008, compared to the same ~~period~~periods in 2007 mainly due to the following factors:

·	Electricity procurement costs, which are passed through to customers, increased by approximately ~~$298 million.~~$208 million in the three months ended June 30, 2008 and approximately $505 million in the six months ended June 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 scheduled outage at Diablo Canyon, and increases in purchased power prices. (See “Cost of Electricity” below.)

·	Electric operating revenues ~~from~~to fund public purpose and energy efficiency programs increased by approximately ~~$73~~$62 million ~~due to new programs, such as~~in the ~~California Solar Initiative program,~~three months ended June 30, 2008 and ~~expenditures relating to existing programs.~~approximately $138 million in the six months ended June 30, 2008. (See ~~Note 3 of the Notes to the Condensed Consolidated Financial Statements.~~“Operating and Maintenance” below.)

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

·	Electric transmission revenues increased by approximately ~~$15~~$12 million in the three months ended June 30, 2008 and approximately $27 million in the six months ended June 30, 2008, primarily due to an increase in rates as authorized in the current TO rate case.

·	Other electric operating revenues, including revenues to recover costs related to the Diablo Canyon steam generator replacement project and revenues to fund the Smart MeterTM advanced metering project, increased by approximately $43 million in the three months ended June 30, 2008 and approximately $39 million in the six months ended June 30, 2008. (See “Capital Expenditures” below.)

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

·	~~Revenues intended to cover payment of the Rate Reduction bonds (“RRBs”) and associated bond expenses decreased by approximately $70 million due to the maturity of the RRBs~~ during these periods for payment of principal and interest on the Rate Reduction Bonds (“RRBs”) that matured in December 2007.

·	~~Other electric operating revenues, including revenues collected for payment of the Energy Recovery Bonds (“ERBs”) due to their declining balance, decreased by approximately $3 million.~~

The Utility’s electric operating revenues for ~~the period 2008 through~~2009 and 2010 are expected to increase, as authorized by the CPUC in the 2007 GRC. The Utility’s electric operating revenues for ~~2008 and~~ future years are also expected to increase as authorized by the FERC in the TO rate cases. In addition, the Utility expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including the new Utility-owned generation projects and the SmartMeterTM advanced metering project. Revenues would also increase to the extent the CPUC approves the Utility’s proposal for other capital projects. (See “Capital Expenditures” below.) Revenue requirements associated with new or expanded public purpose, ~~programs, such as the California Solar Initiative, will result in increased electric operating revenues. Revenue requirements associated with~~energy efficiency, and demand response ~~(“DR”)~~ programs ~~such as the Air Conditioning Direct Load Control program,~~ will also result in increased electric operating revenues.

Finally, ~~because the Utility’s electric operating revenues includes amounts collected from customers to recover the Utility’s electricity procurement costs,~~ future electric operating revenues will be impacted by changes in the Utility’s cost of electricity which the Utility expects will increase. In particular, electric operating revenues will increase to reflect the additional $531 million of revenue requirements the CPUC has authorized the Utility to collect from customers to pay for additional procurement costs the Utility expects to incur in 2008 to purchase electricity that previously had been provided to the Utility's customers under a power purchase agreement between the DWR and Calpine Corporation. This contract was terminated in December 2007. Because the Utility acts as an agent for the DWR, amounts collected from the Utility’s customers to recover the DWR’s revenue requirements under the terminated contract had been excluded from the Utility's electric operating revenues. As the Utility purchases replacement power, the Utility's electric operating revenues will increase as ~~it recovers~~ the ~~cost~~Utility’s electricity procurement costs increase, as discussed under “Cost of ~~the replacement power from customers.~~Electricity” below.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase ~~costs, hedging~~ costs and the cost of fuel used by its generation facilities or supplied to other facilities under tolling agreements. ItThe Utility’s cost of purchased power and the cost of fuel used in Utility-owned generation are passed through to customers. The Utility’s cost of electricity excludes 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 ~~Utility’s cost of purchased power and the cost of fuel used in Utility-owned generation are passed through to customers. The~~ cost of electricity provided under power purchase agreements between the DWR and various power suppliers is also excluded from the ~~Utilty's~~Utility’s cost of electricity.

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

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
(in millions)	2008			2007			2008			2007			2008			2007
Cost of purchased power	$	1,038		$	726		$	1,140		$	892		$	2,178		$	1,620
Proceeds from surplus sales allocated to the Utility		(46	)		(40	)		(90	)		(46	)		(135	)		(88	)
Fuel used in owned generation		35			37
Fuel used in own generation								47			38			81			75
Total cost of electricity	$	1,027		$	723		$	1,097		$	884		$	2,124		$	1,607
Average cost of purchased power per kWh	$	0.088		$	0.090		$	0.089		$	0.084		$	0.088		$	0.087
Total purchased power (in millions of kWh)		11,757			8,054			12,862			10,629			24,652			18,683

The Utility's total cost of electricity increased by approximately $213 million, or 24%, in the three months ended ~~March 31,~~June 30, 2008 and by approximately ~~$304~~$517 million, or ~~42%~~32%, in the six months ended June 30, 2008, compared to the same ~~period~~periods in 2007. ~~This increase was~~These increases were primarily driven by ~~a 3,703 million kilowatt-hour (“kWh”), or 46%, increase~~increases in the total volume of purchased ~~power.~~power of 2,233 million kilowatt-hours (“kWh”), or 21%, for the three months ended June 30, 2008 and 5,969 million kWh, or 32%, for the six months ended June 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. ~~The~~In addition, during the three and six months ended June 30, 2008, the Utility ~~also~~ increased the volume of power it purchased from third parties ~~due to~~during the ~~scheduled~~extended outage at Diablo Canyon Unit 2 ~~throughout~~that lasted from February through mid-April 2008. (See “Operating and ~~March for~~Maintenance” below.) In comparison, because the refueling ~~and~~outage of Diablo Canyon Unit 1 occurred entirely during May 2007, the ~~steam generator replacement. No similar outage occurred~~increase in the ~~first quarter~~volume of purchased power for the same periods in 2007 was lower. Higher market prices also contributed to an increase in the cost of purchased power for the three and six months ended June 30, 2008 compared to the same periods in 2007. ~~(See “Capital Expenditures” below.)~~

~~The Utility's cost~~Various factors will affect the Utility’s future costs of electricity, ~~in 2008 and future years will depend upon~~including the market prices for electricity and natural gas, ~~prices,~~ the level of hydroelectric and nuclear power that the Utility produces, the cost of procuring more renewable energy, ~~and~~ changes in customer ~~demand. In addition,~~demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts are terminated or expired. The Utility expects that its cost of electricity in 2008 will ~~be impacted by~~continue to increase as the Utility continues to purchase replacement power due to the DWR’s termination of ~~DWR contracts.~~

its power purchase agreement with Calpine Corporation in December 2007. The Utility also anticipates lower output from the Utility’s hydroelectric generation facilities caused by lower than normal precipitation resulting in increases of purchased power. In addition, rising natural gas prices are expected to increase the Utility’s cost of electricity for the remainder of 2008 and future years. The Utility’s future cost of electricity also may be affected by federal or state legislation or rules which may be adopted to regulate the emissions of greenhouse gases from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. As directed by recent California legislation, the CPUC has

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

Natural Gas Operating Revenues

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

The Utility's natural gas customers consist of two categories: core and non-core customers. The core customer class is comprised mainly of residential and smaller commercial customers. The non-core customer class is comprised of industrial and larger commercial customers. The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from either the Utility or alternate energy service providers. The Utility does not procure natural gas for non-core customers. When the Utility provides both transportation and natural gas supply, the Utility refers to the combined service as bundled natural gas ~~service. Because the Utility sells most of its transportation services under volumetric rates, the Utility is exposed to volumetric revenue risk.~~

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

	Three Months Ended					Three Months Ended				Six Months Ended
	March 31,					June 30,				June 30,
(in millions)	2008		2007			2008		2007		2008		2007
Bundled natural gas revenues	$	1,142	$	1,103		$	849	$	746	$	1,990	$	1,849
Transportation service-only revenues		77		78			84		82		162		160
Total natural gas operating revenues	$	1,219	$	1,181		$	933	$	828	$	2,152	$	2,009
Average bundled revenue per Mcf of natural gas sold	$	10.11	$	9.85
Average bundled revenue per Mcf(1) of natural gas sold						$	15.72	$	14.08	$	11.92	$	11.21
Total bundled natural gas sales (in millions of Mcf)		113		112			54		53		167		165


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

The Utility's natural gas operating revenues increased by approximately $105 million, or 13%, in the three months ended ~~March 31,~~June 30, 2008 and by approximately ~~$38~~$143 million, or 3%7%, in the six months ended June 30, 2008, compared to the same ~~period~~periods in 2007. ~~This was~~These increases were primarily due to an increase in bundled natural gas revenues of approximately ~~$39~~$103 million, or 4%14%, in the three months ended June 30, 2008 and approximately $141 million, or 8%, in the six months ended June 30, 2008, as a result of ~~increases in the~~increasing cost of natural ~~gas, which~~gas. These costs are passed through to customers. In addition, ~~this increase was~~natural gas operating revenues increased approximately $10 million due to ~~increased~~a shareholder incentive award earned by the Utility under the Core Procurement Incentive Mechanism (“CPIM”). (See the 2007 Annual Report for further discussion of the CPIM.) Finally, the increases in bundled natural gas revenues for both periods reflect an increase in base revenue requirements as a result of attrition adjustments as authorized in the 2007 GRC, an increase in natural gas revenues to fund the SmartMeterTM advanced metering project, and an increase in ~~revenue requirements relating~~natural gas operating revenues to ~~the SmartMeter~~TM ~~project.~~fund public purpose and energy efficiency programs.

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 ~~for an overall~~a 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 are expected to increase through 2010 ~~as a result of~~due to authorized GRC attrition adjustments and an increase in authorized revenue ~~requirement increases authorized by the CPUC in the 2007 GRC and as a result of revenue requirement increases~~requirements relating to the SmartMeterTM advanced metering project.

Cost of Natural Gas

The Utility's cost of natural gas includes the purchase costs of natural gas and transportation costs on interstate pipelines and intrastate pipelines, but excludes the transportation costs for non-core customers, which are included in Operating and Maintenance expense in the Condensed Consolidated Statements of Income.

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

	Three Months Ended				Three Months Ended				Six Months Ended
	March 31,				June 30,				June 30,
(in millions)	2008		2007		2008		2007		2008		2007
Cost of natural gas sold	$	754	$	706	$	448	$	354	$	1,202	$	1,060
Cost of natural gas transportation		21		48		39		42		60		90
Total cost of natural gas	$	775	$	754	$	487	$	396	$	1,262	$	1,150
Average cost per Mcf of natural gas sold	$	6.67	$	6.30	$	8.30	$	6.68	$	7.20	$	6.42
Total natural gas sold (in millions of Mcf)		113		112

Total natural gas sold (in millions of Mcf)

167

165

The Utility's total cost of natural gas increased in the three and six months ended ~~March 31,~~June 30, 2008 by approximately ~~$21~~$91 million, or 3%23%, and by approximately $112 million, or 10%, compared to the same ~~period~~periods in 2007, primarily due to ~~an increase~~increases in the average market price of natural gas purchased ~~of approximately $0.37 per thousand cubic feet (“Mcf”), or 6%.~~in the three and six months ended June 30, 2008. Average market prices were higher in the ~~beginning of~~three and six months ended June 30, 2008 ~~because the temperature was colder~~due to higher demand in the ~~central~~national market, lower imports of liquefied natural gas, and ~~eastern regions~~the higher global cost of ~~the United States,~~crude oil and other energy commodities, as compared to the same ~~period~~periods in 2007. ~~This~~For the six months ended June 30, 2008, the increase was partially offset by a refund the Utility received as part of a settlement with TransCanada’s Gas Transmission Northwest Corporation for 2007 gas transmission capacity ~~rates as approved by the FERC.~~rates.

The Utility's future cost of natural gas, ~~in subsequent periods,~~ which will be passed through to customers, will be impacted by both North American and global market forces. Market forces include supply availability, customer demand, ~~liquid~~liquefied natural gas availability, natural gas storage, and industry perceptions of risks that may affect either availability or demand, such as the possibility of hurricanes in the gas-producing regions of the Gulf of Mexico or of protracted heat waves that may increase gas-fired electric demand from high air conditioning loads.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility's costs to operate and maintain its electricity and natural gas facilities, customer accounts and service expenses, public purpose program expenses, and administrative and general expenses. ~~Generally, these expenses are offset by corresponding revenues authorized by the CPUC and the FERC in various proceedings.~~

The Utility’s operating and maintenance expenses increased by approximately ~~$117~~$70 million, or ~~13%~~8%, and approximately $187 million, or 10%, in the three and six months ended ~~March 31,~~June 30, 2008, respectively, compared to the same period in 2007. Expenses increased mainly due to the following factors:

·	~~Customer~~ Public purpose program and customer energy efficiency incentive program expenses increased by approximately ~~$76~~$67 million and $140 million in the three and six months ended June 30, 2008, respectively. These changes were primarily due to increased customer participation and increased marketing of new and existing programs. Of these changes, approximately $62 million and $138 million, respectively, are recovered in electric operating revenues and approximately $6 million and $14 million, respectively, are recovered in natural gas operating revenues. The excess of revenue over expense is primarily due to the recovery during 2008 for costs incurred during the second half of 2007 related to the SmartACTM Program.

·	Labor costs increased by approximately $11 million and $17 million in the three and six months ended June 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.

·	Costs related to injuries and damages not specifically related to gas or electric lines of business increased by approximately $8 million for both the ~~planned refueling outage at Diablo Canyon Unit 2 were approximately $45 million~~three and six months ended June 30, 2008 as a result of a favorable settlement in ~~2008.~~2007. There was no similar ~~outage during the first quarter of 2007.~~settlement in 2008.

·	Labor costs increased by approximately $6 million for system-wide repair and restoration of electric distribution systems for the three months ended June 30, 2008. For the six months ended June 30, 2008, labor costs increased by approximately $38 million for the repair and restoration of electric distribution systems and responding to customer inquiries as a result of the January 2008 winter storm. Of the approximately $38 million in costs, the Utility is seeking recovery of approximately $12 million in eligible costs in its March 28, 2008 Catastrophic Events Memorandum Account application. There was no similar storm in the same period in 2007.

·	The timing of the planned outages at Diablo Canyon favorably impacted the results for the three months ended June 30, 2008 compared to the same period in 2007. There was a decrease in maintenance costs of approximately $35 million because the planned outage of Diablo Canyon Unit 1 occurred during the second quarter of 2007, while costs for the planned outage of Diablo Canyon Unit 2 were incurred primarily in the first quarter of 2008.

~~The above increases, totaling $159 million, were offset by~~In addition, there was an aggregate increase of $13 million and decrease of ~~$42~~$16 million ~~representing changes~~ in the ~~accrued liability for certain litigation matters~~three and six months ended June 30, 2008, respectively, representing other miscellaneous operating and maintenance expenses that ~~were lower than~~changed from the comparable period in 2007. ~~None of the items comprising the aggregate decrease were individually material.~~

Operating and maintenance expenses are influenced by wage inflation, benefits, property taxes, the timing and length of Diablo Canyon refueling outages, environmental remediation costs, legal costs, material costs, and various other administrative and general expenses. The Utility anticipates that it will incur higher material, permitting, and labor costs in the future as well as higher costs to operate and maintain its aging infrastructure. The Utility may make additional payments to employees for missed or delayed meals to comply with California labor law as the Utility’s investigation into this matter continues. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of California labor code issues.) In addition, the Utility ~~may~~anticipates that it will incur costs, not included in forecasts used to set rates in the GRC, to ~~address safety~~improve operating and ~~reliability issues~~maintenance processes used in ~~the Utility's electric and~~its natural gas ~~distribution~~ system ~~depending~~following the discovery that some operating and maintenance activities were not effective. The amount of these additional expenses will depend on the outcome of ~~its~~the Utility’s continuing review of ~~its~~these operating ~~practices~~ and ~~procedures following recent electric transformer failures and the discovery that some natural gas~~ maintenance ~~records did not accurately reflect field conditions.~~activities. (See "Risk Factors" in the 2007 Annual Report.) The Utility also expects that it will incur higher expenses in ~~subsequent~~future periods to comply with the requirements of renewed FERC licenses for the Utility’s hydroelectric generation ~~licenses and to complete the construction of the dry cask storage facility at Diablo Canyon.~~facilities. The Utility ~~will~~intends to continue its efforts to identify and implement ~~additional~~initiatives to achieve operational efficiencies to ~~achieve~~create future sustainable cost-savings and to offset increased spending to address operational issues and increasing cost of materials.

Depreciation, Amortization, and Decommissioning

~~In the three months ended March 31, 2008, the~~The Utility's depreciation, amortization, and decommissioning expenses decreased by approximately ~~$27~~$12 million, or ~~6%,~~3% in the three months ended June 30, 2008 and approximately $39 million, or 5% in the six months ended June 30, 2008, as compared to the same ~~period~~periods in 2007, mainly due to ~~a decrease~~decreases in amortization expense of approximately ~~$64~~$60 million and $124 million, respectively, related to the ~~RRB~~rate reduction bond (“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 ~~was~~has been recorded in 2008. ~~This decrease was~~These decreases were partially offset by ~~other~~increases to depreciation ~~amortization,~~expense of approximately $48 million in the three months ended June 30, 2008 and ~~decommissioning expenses, which~~approximately $85 million in the six months ended June 30, 2008. Depreciation expense increased ~~by approximately $37 million,~~ primarily ~~relating~~due to plant additions and depreciation rate changes as authorized in ~~2007 and authorization of~~ the 2007 GRC and the current TO rate case.

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

Interest Income

In the three months ended ~~March 31,~~June 30, 2008, the Utility’s interest income decreased by approximately ~~$24~~$2 million, or ~~50%~~6%, as compared to the same period in 2007. ~~The Utility received approximately $16~~A $10 million decrease in ~~the three months ended March 31, 2007 related to the settlement of Internal Revenue Service (“IRS”) refund claims with no similar refund in 2008. In addition, other~~ interest income ~~decreased by approximately $8 million,~~was primarily due to lower interest rates earned ~~due to lower interest rates~~ on funds held in escrow related to Disputed Claims and a lower escrow balance reflecting settlements of Disputed Claims. The decrease was partially offset by an increase of approximately $8 million in other interest, including a decision to allow recovery of interest income on a regulatory asset established for the recovery of certain scheduling coordinator (“SC”) costs.

In the six months ended June 30, 2008, the Utility’s interest income decreased by approximately $26 million, or 31%, as compared to the same period in 2007 ~~that reduced~~when the ~~amounts~~Utility received approximately $16 million in interest income on a federal tax refund received in 2007. In addition, there was a decrease of $16 million in interest income, primarily due to lower interest rates earned on funds held in ~~escrow.~~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 $6 million in other interest, including a decision to allow recovery of interest income on a regulatory asset established for the recovery of certain SC costs.

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

Interest Expense

In the three and six months ended ~~March 31,~~June 30, 2008, there was no change in the Utility’s interest expense, ~~decreased by~~and a decrease of approximately $2 million, or 1%, respectively, as compared to the same ~~period~~periods in ~~2007,~~2007. Interest expense decreased primarily due to the following factors:

·	Interest expense decreased by approximately $9$7 million in the three months ended June 30, 2008, and approximately $28 million in the six months ended June 30, 2008, due to the reduction in the outstanding ~~ERBs~~balance of energy recovery bonds and the maturity of the RRBs in December 2007.

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

·	Other interest expense decreased by approximately $5$2 million in the three months ended June 30, 2008, and approximately $1 million in the six months ended June 30, 2008, primarily due to lower commercial paper interest rates and a lower average outstanding commercial paper balance.

These decreases were ~~partially~~ offset by an additional approximately ~~$18~~$16 million in the three months ended June 30, 2008, and approximately $34 million in the six months ended June 30, 2008, in interest expense related to ~~$1.8~~$1.2 billion in Senior Notes issued in 2007 and $600 million in Senior Notes issued in March 2008.

The Utility’s interest expense in 2008 and future periods will be impacted by changes in interest rates as the Utility’s short-term debt and a portion of its long-term debt bear variable interest rates, as well as by changes in the amount of debt outstanding, including for debt ~~expected to be issued in subsequent periods~~maturities and to finance capital ~~expenditures.~~expenditures in future periods.

Income Tax Expense

~~In the three months ended March 31, 2008, the~~The Utility's income tax expense decreased by approximately ~~$25~~$20 million, or ~~17%,~~13% for the three months ended June 30, 2008 and by approximately $45 million, or 15% for the six months ended June 30, 2008, as compared to the same period in 2007. The $50 million reduction in pre-tax income decreased income tax expense by approximately $18 million. In addition, income tax expense decreased by $9 million as a result of an IRS audit settlement reached during the three months ended March 31, 2008. No similar amount was recorded in the same period in 2007. These decreases were partially offset by an increase in income tax expense of approximately $2 million, mainly due to a decrease in tax-deductible decommissioning expense in the three months ended March 31, 2008 compared to the same periodperiods in 2007. The effective tax rates for the three months ended ~~March 31,~~June 30, 2008 and 2007 were ~~33.6%~~30.0% and ~~35.7%~~36.0%, respectively. The effective tax rates for the six months ended June 30, 2008 and 2007 were 31.6% and 35.9%, respectively. The decrease in the effective tax rates for both the three and six months ended June 30, 2008 are primarily due to the Internal Revenue Service (“IRS”) approval of the Utility’s change in accounting method for the capitalization of indirect service costs for tax years 2001-2004, which resulted in a reduction of accrued interest on uncertain tax positions. (See “Tax Matters” for further discussion.) For the six months ended June 30, 2008, an IRS audit settlement reached in January 2008 also decreased the effective tax rate. There was no similar settlement recorded in the same periods in 2007.

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

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

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

Other Expense, Net

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

LIQUIDITY AND FINANCIAL RESOURCES

Overview

At ~~March 31,~~June 30, 2008, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately ~~$253~~$297 million and restricted cash of approximately $1.3 billion. At ~~March 31,~~June 30, 2008, PG&E Corporation on a

stand-alone basis had cash and cash equivalents of approximately ~~$191~~$228 million; the Utility had cash and cash equivalents of approximately ~~$62~~$69 million and restricted cash of approximately $1.3 billion. Restricted cash primarily consists of approximately $1.2 billion of cash held in escrow pending the resolution of the remaining Disputed Claims as well as deposits made under certain third-party agreements. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in money market funds.

As of ~~March 31,~~June 30, 2008, the Utility had ~~$220~~$281 million of letters of credit and no borrowings outstanding under its $2.0 billion working capital facility (“working capital facility”). As of ~~March 31,~~June 30, 2008, the Utility also had ~~$73~~$156 million of outstanding commercial paper. The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its working capital facility. As of ~~March 31,~~June 30, 2008, the Utility had ~~$1.7~~approximately $1.6 billion of short-term CPUC-authorized debt capacity available.

~~As of March 31, 2008, PG&E Corporation had no letters of credit and no borrowings outstanding~~ The Utility expects that the current total available capacity under its ~~$200 million~~commercial paper and working capital ~~facility.~~facilities will be sufficient to meet any additional short-term borrowing needs.

During March and April 2008, the Utility repurchased $454 million of ~~pollution control~~PC2005 bonds ~~series 2005 A-G (“PC2005 bonds”)~~ issued by the California Infrastructure and Economic Development Bank to minimize its interest rate risk arising from the credit downgrade of the bond ~~insurer and dislocation in the auction rate market.~~insurer. The repurchases were financed through a combination of long-term and short-term debt. The Utility ~~will hold~~holds the PC2005 bonds in treasury. The Utility expects that the PC2005 bonds will be resold during 2008, depending on conditions in the tax-exempt bond ~~market.~~market and liquidity needs at the Utility. The proceeds will be used to repay short-term debt.

On March 3, 2008, the Utility issued $200 million principal amount of 5.625% 10-year Senior Notes due on November 30, 2017, which increased the outstanding amount of ~~the~~its 5.625% Senior Notes ~~issued on December 4, 2007,~~ to $700 million. Also on March 3, 2008, the Utility issued $400 million principal amount of 6.35% 30-year Senior Notes due on February 15, 2038. The Utility expects it will ~~issue an~~incur additional ~~$250 million~~long-term debt ranging from $4.5 billion to ~~$450 million~~$5.1 billion during the remainder of ~~Senior Notes in~~ 2008 through 2011 primarily to finance capital ~~expenditures.~~expenditures and replace maturing debt.

The amount and timing of the Utility’s future financing needs will depend on various factors, including: (1) the timing and amount of forecasted capital expenditures and any incremental capital expenditures beyond those currently forecasted; (2) the amount of cash internally generated through normal business operations; (3) the timing of the resolution of the Disputed Claims (upon settlement or the conclusion of the FERC and judicial proceedings) and the amount of interest on these claims that the Utility will be required to ~~pay;~~pay (see Note 10 of the Notes to the Condensed Consolidated Financial Statements); and (4) the timing of the resale of the PC2005 bonds. ~~(See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)~~

On February 25, 2008, PG&E Corporation contributed equity of $50 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 ~~three~~six months ended ~~March 31,~~June 30, 2008, PG&E Corporation issued ~~1,086,926~~2,241,807 shares of common stock upon exercise of employee stock options, for the account of 401(k) participants, and under its Dividend Reinvestment and Stock Purchase Plan, generating approximately ~~$39~~$82 million of cash. In February 2008, PG&E Corporation contributed $50 million of cash to the Utility to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC. PG&E Corporation expects to issue additional common stock, debt, or other securities, depending on market conditions, to fund a portion of the Utility’s future equity needs.

Dividends

~~On February 15,~~During the six months ended June 30, 2008, the Utility paid cash dividends to holders of ~~various~~its outstanding series of preferred stock ~~in the aggregate amount of $3~~totaling $7 million. On ~~February 20,~~June 18, 2008, the Board of Directors of the Utility declared ~~dividends~~a cash dividend on ~~all~~its outstanding series of ~~its~~ preferred ~~stock. The dividends, totaling $4 million, are~~stock payable on ~~May~~August 15, 2008 to shareholders of record on ~~April 30,~~July 31, 2008.

Utility

Operating Activities

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

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

	Three Months Ended						Six Months Ended
	March 31,						June 30,
(in millions)	2008			2007			2008			2007
Net income	$	236		$	261		$	549		$	535
Adjustments to reconcile net income to net cash provided by operating activities		683			665
Net effect of changes in operating assets and liabilities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction								870			913
Deferred income taxes and tax credits, net								316			101
Other changes in noncurrent assets and liabilities								480			129
Gain on sale of assets								-			(1	)
Effect of changes in operating assets and liabilities:
Accounts receivable		88			237			(66	)		143
Inventories		107			75			(57	)		(22	)
Accounts payable		149			(99	)		123			(221	)
Income taxes receivable/payable		(20	)		41			57			(59	)
Regulatory balancing accounts, net		(356	)		(275	)		(351	)		(483	)
Other current assets		104			174			429			271
Other current liabilities		65			(98	)		(73	)		(48	)
Other		(2	)		(7	)		(3	)		(23	)
Net cash provided by operating activities	$	1,054		$	974		$	2,274		$	1,235

In the ~~three~~six months ended ~~March 31,~~June 30, 2008, net cash provided by operating activities increased by approximately ~~$80~~$1,039 million from the same period in ~~2007,~~2007. The following changes in financial condition positively impacted cash flows during the six months ended June 30, 2008:

·	Increase of approximately $936 million in collateral payable primarily related to price risk management activities between December 31, 2007 and June 30, 2008, compared with a decrease of approximately $138 million in collateral receivable related to price risk management activities over the same period in 2007 as a result of changes in the Utility’s exposure to counterparties’ credit risk. Collateral payable represents cash collected, and collateral receivable represents cash paid, to reduce the Utility’s net credit exposure to price risk management activities. The Utility’s collateral payables and receivables will fluctuate based on changes in the Utility’s net credit exposure, which is primarily dependent on electricity and gas price movement.

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

·	Increase in Regulatory balancing accounts, net under-collection of approximately $351 million between December 31, 2007 and June 30, 2008, compared with an approximately $483 million increase in the net under-collection over the same period in 2007. The increase resulted from receipt of a $230 million refund from the California Energy Commission (“CEC”), which more than offset the increase in the under-collection resulting from higher than forecasted electricity procurement costs during 2008 (see “Cost of Electricity” above). The funds from the CEC will be refunded to customers in 2009.

Among other factors, the Utility’s electricity procurement costs and the timing of rate adjustments authorized to recover these costs will drive changes in cash provided by or used in operating activities. The CPUC has established a balancing account mechanism to adjust the Utility’s electric rates whenever the forecasted aggregate over-collections or under-collections of the Utility’s procurement costs for the current year exceed 5% of the Utility's prior year generation revenues, excluding generation revenues for DWR contracts. In accordance with this mechanism, the Utility has requested approval to collect from customers $482 million during the 15-month period October 2008 through December 2009 to recover the forecast 2008 end-of-year under-collection of procurement costs, due mainly to ~~an approximately $230 million refund received from the California Energy Commission (“CEC”) that~~rapidly rising natural gas costs. The forecast will be ~~refunded~~updated in September 2008 for actual recorded under-collections through August 2008. On July 21, 2008, a proposed decision was issued that recommends the Utility’s request be approved. The CPUC is expected to ~~customers~~vote on this proposed decision on August 21, 2008. Independent of the balancing account mechanism, on June 10, 2008, the Utility filed its application for recovery of its forecasted electricity procurement and related costs for 2009. If this request is granted, the Utility will collect an additional approximately $339 million (to be updated in November 2008) over 12 months starting January 1, 2009. ~~The $230 million CEC refund was offset by a decrease of approximately $70 million in energy supplier settlements and a decrease of approximately $35 million due to lower pension contributions.~~

Investing Activities

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

The Utility's cash flows from investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and 2007 were as follows:

	Three Months Ended						Six Months Ended
	March 31,						June 30,
(in millions)	2008			2007			2008			2007
Capital expenditures	$	(853	)	$	(673	)	$	(1,712	)	$	(1,320	)
Net proceeds from sale of assets		6			4			12			8
Decrease (increase) in restricted cash		2			(11	)
Increase in restricted cash								(7	)		(13	)
Other investing activities		47			(18	)		(29	)		(58	)
Net cash used in investing activities	$	(798	)	$	(698	)	$	(1,736	)	$	(1,383	)

Net cash used in investing activities increased by approximately ~~$100~~$353 million in the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to the same period in 2007, primarily due to an increase of approximately ~~$180~~$392 million in capital expenditures for installation of the SmartMeter™ ~~installation~~advanced metering project, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Financing Activities

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

	Three Months Ended						Six Months Ended
	March 31,						June 30,
(in millions)	2008			2007			2008			2007
Repayments under accounts receivable facility and working capital facility	$	(250	)	$	(300	)	$	(250	)	$	(300	)
Net repayment of commercial paper, net discount of $4 million in 2007		(198	)		(425	)
(Repayment) issuance of commercial paper, net discount of $1 million in 2008 and $2 million in 2007								(114	)		109
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007		598			690			598			690
Long-term debt matured, redeemed, or repurchased		(300	)		-			(454	)		-
Rate reduction bonds matured		-			(75	)		-			(143	)
Energy recovery bonds matured		(83	)		(83	)		(165	)		(160	)
Equity infusion from PG&E Corporation		50			-
Equity infusion								50			200
Common stock dividends paid		(142	)		(127	)		(284	)		(254	)
Preferred stock dividends paid		(3	)		(3	)		(7	)		(7	)
Other		(7	)		14			16			21
Net cash used in financing activities	$	(335	)	$	(309	)
Net cash (used in) provided by financing activities							$	(610	)	$	156

In the ~~three~~six months ended ~~March 31,~~June 30, 2008, net cash used in financing activities increased by approximately ~~$26~~$766 million compared to the same period in ~~2007. This was mainly~~2007, representing a decreased reliance on cash provided by financing activities due to the ~~following factors:~~increase in cash provided by operating activities partially offset by the increase in cash used in investing activities. Components of the increase in net cash used in financing activities include the following:

·	In ~~March 2008,~~an effort to mitigate increasing interest rates as a result of downgrades to the bond issuer’s credit rating and credit issues which impacted the auction rate markets, the Utility repurchased ~~$300~~$454 million of PC2005 bonds ~~with~~in March and April 2008. There was no similar repurchase in 2007.

·	Proceeds from the issuance of Senior Notes were approximately $92 million less in the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the same period in 2007. Proceeds from the issuance of Senior Notes were used to repay outstanding commercial paper, for working capital purposes, and to fund capital expenditures.

·	The Utility’s net repayments of commercial paper were approximately ~~$227~~$223 million ~~less~~higher in the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the same period in ~~2007.~~

·	~~The RRBs were fully repaid~~2007 primarily due to the increases in ~~December 2007. As a result, there were no debt repayments~~cash from operations in 2008 as ~~compared to $75 million in payments for the three months ended March 31, 2007.~~described above.

·	The Utility received an equity infusion of $50 million from PG&E Corporation in February 2008, ~~with no similar~~as compared to $200 million equity infusion during the same period in 2007. Equity infusions are sized to maintain the common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

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

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

PG&E Corporation

Operating Activities

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

PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and 2007.

Investing Activities

Other than payment of dividends, PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with investing activities for the ~~three~~six months ended ~~March 31,~~June 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 ~~three~~six months ended ~~March 31,~~June 30, 2008 and 2007.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual obligations and commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of transportation capacity, natural gas and electricity to support customer demand, and the purchase of fuel and transportation to support the Utility's generation activities. In addition to those commitments disclosed in the 2007 Annual Report and those arising from normal business activities, PG&E Corporation and the Utility’s commitments at ~~March 31,~~June 30, 2008 include $200 million of 5.625% Senior Notes due November 30, 2017 and $400

million of 6.35% Senior Notes due February 15, 2038. (See Notes 4, 5, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements and the 2007 Annual Report for further discussion.)

CAPITAL EXPENDITURES

The Utility expects that capital expenditures will total approximately ~~$3.6~~$3.7 billion in 2008. During the ~~three~~six month period ended ~~March 31,~~June 30, 2008, the Utility incurred capital expenditures of approximately ~~$853 million.~~$1.7 billion. (See “Liquidity and Financial Resources – Investing ~~Activities"~~Activities” above.)

The Utility forecasts that it will make various capital investments in its electric and gas transmission and distribution infrastructure to maintain and enhance system reliability and customer service, to extend the life of or replace existing infrastructure, to add new infrastructure to meet already authorized growth, and to implement various initiatives designed to achieve operating and cost efficiencies. ~~The~~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 ~~also may request~~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.

On May 15, 2008, the Utility requested that the CPUC ~~to authorize additional capital expenditures, outside of~~approve the ~~next GRC, to make the~~ Utility’s proposed six-year electric distribution reliability ~~level more comparable~~improvement program and authorize the Utility to ~~that of other California investor-owned utilities~~collect revenues to recover forecasted capital expenditures totaling approximately $2.3 billion and ~~other utilities~~operating and maintenance expenses totaling approximately $43 million over the six-year period beginning on January 1, 2009. The amounts requested are incremental to the revenue requirement already authorized by the CPUC in the ~~United States.~~ Utility’s 2007 GRC. The CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”) have objected to the Utility’s request. PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility’s request. (See “Regulatory Matters” below for more information.)

The Utility has been exploring obtaining regulatory approval for a potential ~~investments~~investment in an electric transmission ~~projects including a proposed new 1,000-mile, 500-KV transmission line to run from British Columbia Canada to Northern California.~~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 ~~allow recovery~~collect transmission rates designed to provide an incentive to the Utility to continue leading the development of the proposed 1,000-mile, 500-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 ~~abandonment~~surveys, and all prudently incurred development and construction costs ~~related to~~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 ~~other~~many conditions and challenges to the development of ~~this~~these proposed electric transmission ~~line~~projects will be met.

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

Finally, PG&E Corporation also has been exploring potential investments in natural gas transmission pipeline projects, but it has decided not to pursue an investment in El Paso Corporation’s proposed Ruby Pipeline. On April 30, 2008, PG&E Corporation terminated the letter of intent it had entered into in December 2007 with El Paso Corporation to acquire an interest in the proposed Ruby Pipeline. The Utility will continue to seek CPUC approval of its natural gas transportation contract, entered into in December 2007, for firm service rights on the proposed Ruby Pipeline for a 15-year term commencing in 2011 when the pipeline is proposed to be placed into service. ~~PG&E Corporation continues~~

SmartMeter ™ Advanced Metering Project Upgrade

The CPUC has previously authorized the Utility to ~~pursue~~recover approximately $1.4 billion in capital costs in connection with its SmartMeterTM advanced metering project. Of this amount, the ~~development~~Utility has incurred capital expenditures of $421 million through June 30, 2008. The Utility’s request to recover additional expenditures of $572 million, including $463 million of additional capital expenditures, to upgrade certain elements of the ~~proposed 230-mile Pacific Connector Gas Pipeline, along~~Utility’s SmartMeterTM program is still pending at the CPUC. On June 30, 2008, the DRA and TURN recommended that the CPUC reject the Utility’s request. In the alternative, the DRA and TURN recommend that the CPUC authorize reduced amounts of $358 million and $324 million, respectively. Neither the DRA nor TURN specified the amount of capital expenditures included in their recommended amounts. On July 23, 2008, the Utility filed a response opposing these recommendations and reaffirming the Utility’s support for the requested amounts. A final CPUC decision is expected in December 2008. The Utility cannot predict whether the CPUC will approve its application for additional funds to upgrade its advance metering system. The Utility expects to incur approximately $19 million in capital costs for the upgrade before the CPUC decision is issued. If the CPUC does not approve the Utility’s request, the Utility may be unable to recover these costs.

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

Diablo Canyon Steam Generator Replacement Project

In November 2005, the CPUC authorized the Utility to replace the steam generators at the two nuclear operating units at Diablo Canyon (Units 1 and 2). The CPUC authorized the Utility to recover project costs ~~of this project~~ of up to $706 million from customers without further reasonableness ~~review; if~~review. If costs exceed this threshold, the CPUC authorized the Utility to recover costs of up to $815 million, subject to a reasonableness review of the full amount. As of ~~December 31, 2007,~~June 30, 2008, the Utility has spent approximately ~~$300~~$475 million, including progress payments, under contracts for the eight steam generators that the Utility has ordered. The Utility anticipates the future expenditures will be approximately ~~$373~~$224 million. The Utility installed four of the new steam generators in Unit 2 during the refueling outage that began in February 2008 and ended in April 2008. The remaining new generators infor Unit 1 are expected to be installed in 2009.

In March 2008, the Utility and the Coastal Law Enforcement Action Network (“CLEAN”) settled a complaint that CLEAN had filed in the Superior Court for the County of San Francisco challenging permits that the Utility had obtained from the California Coastal Commission and San Luis Obispo County related to the steam generator replacement project. CLEAN has agreed to dismiss its complaint, and the Utility has agreed to fund programs to benefit the coastal and marine environment.

New Generation Facilities

~~Colusa Power Plant~~

On ~~February 29,~~June 12, 2008, the CPUC ~~authorized~~gave its final approval for the Utility to ~~begin the construction of~~construct the Colusa Project, a 657-megawatt (“MW”) combined cycle generating facility to be located in Colusa County, California ~~contingent on its~~after reviewing the final environmental certification issued by the ~~CEC and the CPUC’s consideration of that certification. On April 23, 2008 the CEC issued a~~CEC. Construction will begin once final ~~decision granting an~~ environmental ~~certification of the project. The Utility has requested the CPUC to issue its final authorization for the Utility to begin construction of the project.~~permitting is complete.

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

Potential New Utility-Owned Generation

On ~~March 19,~~July 21, 2008, the Utility ~~filed a revised 2006 Long-Term Procurement Plan (“LTPP”) covering the period~~received bids from ~~2007 through 2016~~third parties in response to ~~conform to modifications required by the final CPUC decision issued in December 2007. The revised plan updates~~ the Utility’s ~~planning criteria and need determinations over the 10-year LTPP period. On~~ April 1, 2008 ~~the Utility issued a~~ request for offers (“RFO”) for 800 to 1,200 MW of dispatchable and operationally flexible generation resources to be on-line no later than May 2015. The Utility is evaluating these offers and currently expects to develop a shortlist of bidders by ~~2015 beyond the Utility's planned additions of renewable resources. Through this~~October 2008. The Utility’s RFO the Utility seeks to meet this electricity need through power purchase agreements or purchase and sale agreements (under which a new generating facility is constructed by a third party and sold to the Utility after the commercial operational performance standard is met).

~~On March 7, 2008, the Utility also issued an RFO for 800,000 to 1,600,000 MWh of renewable generation to become operational beginning in 2008 and beyond through~~requested both power purchase agreements and purchase and sale agreements. Under a purchase and sale agreement a new generating facility would be constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements.

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

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

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

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

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

PG&E Corporation and the Utility cannot predict the extent to which any of the RFOs described above will result in Utility-owned generation projects or if the ~~extent~~CPUC will approve the Utility’s application to ~~which future customer demand will be met through new utility-owned generation projects on which~~develop the ~~Utility would be authorized to earn an ROE.~~Tesla Generating Station.

OFF-BALANCE SHEET ARRANGEMENTS

For financing and other business purposes, PG&E Corporation and the Utility maintain certain arrangements that are not reflected in their Condensed Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E Corporation's 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

~~Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.~~ The Utility ~~is exposed to a concentration of credit risk associated~~conducts business with receivables from the sale of natural gas and electricity to residential and small commercial customers in northern and central California. This credit risk exposure is mitigated by requiring deposits from new customers and from those customers whose past payment practices are below standard. A material loss associated with the regional concentration of retail receivables is not considered likely.

~~Additionally, the Utility has a concentration of credit risk associated with its~~ wholesale customers and counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. This concentration of counterparties may impact the Utility's overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions. If a counterparty failed to perform on its contractual obligation to deliver electricity, then the Utility may find it necessary to procure electricity at current market prices, which may be higher than the contract prices. Credit-related losses attributable to receivables and electric and gas procurement activities from wholesale customers and counterparties are expected to be recoverable from customers through rates and are not expected to have a material impact on net income.

The Utility manages credit risk associated with its wholesale customers and counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically and a detailed credit analysis is performed at least annually. Further, the 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,~~June 30, 2008 and December 31, 2007:

(in millions)		Gross Credit Exposure Before Credit Collateral(1)			Credit Collateral	Net Credit Exposure(2)		Number of Wholesale Customer or Counterparties >10%	Net Exposure to Wholesale Customer or Counterparties >10%			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, 2008		$	847	$	153	$	694	1	$	87
June 30, 2008												$	1,462	$ 660	$	802	1	$	111
December 31, 2007		$	311	$	91	$	220	2	$	111		$	311	$ 91	$	220	2	$	111


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

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies that are discussed in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

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

2008 Cost of Capital Proceeding

On ~~April~~May 29, 2008, the CPUC adopted a ~~proposed decision was issued~~uniform three-year cost of capital mechanism in the second phase of the ~~CPUC’s~~ 2008 Cost of Capital proceeding ~~that recommends a uniform multi-year cost of capital mechanism~~ for the Utility and the other two California investor-owned electric utilities that ~~would~~will replace the annual cost of capital proceeding. ~~The~~Under the adopted mechanism, the utilities ~~would be~~are required to file full cost of capital applications by April 20 of every third ~~year. The first application would be due~~year, beginning on April 20, 2010. (Under the current regulatory schedule, the annual cost of capital application is due May 8 of each year, to become effective on January 1 of the following year. In December 2007 the CPUC waived the requirement for the utilities to file their 2009 Cost of Capital applications by May 8, 2008.) The proposed decision would permit the utilities to file a cost of capital application earlier in extraordinary circumstances.

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

The ~~proposed~~ cost of capital mechanism ~~would use~~uses an interest rate index ~~the~~(the 12-month October through September average of the Moody's Investors Service ~~("Moody's") Aa~~ utility bond ~~index (for A credit-rated utilities) or the Moody’s Baa utility bond index (for B credit-rated utilities),~~index) to trigger changes in the authorized cost of debt, preferred stock, and equity. ~~The proposed decision states that in~~

In any year in which the ~~current~~12-month October through September average for the index increases or decreases by more than 100 basis points (the “deadband”) from the ~~applicable Moody’s~~ benchmark, the cost of equity ~~would~~will be adjusted by one-half of the difference between the ~~benchmark~~12-month average and the current index. It is unclear in the proposed decision whether such adjustment would be based on one-half of the full difference between the current index and the benchmark, or one-half of the amount that the current

~~index exceeds the 100 basis point deadband.~~benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock ~~would~~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 ~~scheduled~~forecasted to be ~~issued.~~

~~Comments on~~issued in the ~~proposed decision are due on May 19, 2008. PG&E Corporation and~~coming year. Finally, the ~~Utility are unable to predict whether~~12-month October through September average of the ~~CPUC~~index, which triggered the adjustment, will ~~adopt~~become the ~~proposed decision.~~new benchmark.

Spent Nuclear Fuel Storage Proceeding

~~Because~~As a consequence of the U.S. Department of ~~Energy has failed~~Energy’s failure 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 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~~In addition, 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.~~fuel.

~~Although the Utility expected to begin loading spent nuclear fuel in 2008, the Utility currently expects that the~~The construction of this dry cask storage facility, ~~and~~along with modifications to the power plant to support dry cask storage processing, ~~will~~is not expected to be completed inuntil late 2008 ~~and that~~with the initial movement of spent nuclear fuel to dry cask storage ~~will begin~~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.

~~Also, on April 30,~~On July 1, 2008, ~~in connection with the pending appeal of the 2004 decision by~~ the Nuclear Regulatory Commission ("NRC") ~~to grant the Utility a permit to construct the dry cask storage facility, the NRC set~~held a hearing ~~date of July 1, 2008 for oral argument on~~to consider whether the NRC staff sufficiently addressed the latent health impacts and damage to property of a potential radiological release in its supplemental environmental assessment report ~~that~~when it decided to issue a permit for the dry cask storage facility. The NRC’s supplemental assessment had concluded there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon dry cask storage facility. ItThe NRC is expected ~~that the NRC will~~to issue a ~~final~~ decision on this matter in the ~~fourth~~third quarter of 2008.

Energy Efficiency Programs and Incentive Ratemaking

In January 2008, the CPUC ~~issued a final decision modifying~~directed its Energy Division to update certain assumptions to be used to measure and verify the ~~incentive ratemaking mechanism it had previously adopted with respect to~~energy savings achieved by the California investor-owned ~~utilities’~~utilities through implementation of their 2006-2008 and 2009-2011 energy efficiency ~~program cycles.~~programs. The ~~January 2008~~original schedule set by the CPUC ~~decision required~~called for the ~~CPUC's~~ Energy Division to ~~update~~complete its verification report by August 2008 so that the new assumptions could be used to ~~estimate~~assess the ~~amount of~~utilities’ interim claims, to be submitted in September 2008, for incentives (or reimbursement obligations) based on energy savings per efficiency measure over the 3-year program period and the amount of the estimated savings that can be attributed to the utilities' programs, for purposes of assessing, on an interim basis, whether the utilities are entitled to incentives or are required to reimburse customers.achieved in 2006-2007. (Under the interim claim process, 35% of the incentives or reimbursement obligations calculated for each interim claim will be “held back” until completion of measurement studies verifying the actual energy savings for the entire three-year program cycle.) ~~It is~~Due to an expected ~~that~~delay in the completion of the Energy Division’s verification report and following a party’s request for the CPUC ~~will adopt revised assumptions by June 30, 2008 and that~~to initiate an alternative dispute process, the CPUC ~~will complete its verification~~has scheduled a preliminary meeting on August 8, 2008 to explore the possibility of conducting a facilitated or mediated settlement conference to resolve the utilities’ installed energy efficiency measures by July 15, 2008. The revised assumptions and verification results will be used to evaluate and measure the savings resulting from the Utility's 2006-2008 and 2009-2011 energy efficiency programs. It is expected that this evaluation and measurement processinterim claims for 2006-2007 ~~programs will be completed by September 30, 2008 and that~~before the ~~Utility would submit its interim claim shortly thereafter. The Utility’s application seeking CPUC approval~~end of ~~the Utility’s energy efficiency programs and funding for the next cycle of energy efficiency programs (2009-2011) is due June 23,~~ 2008. ~~A final CPUC decision regarding the 2009-2011 programs is expected to be issued in late 2008.~~

The amount of any shareholder incentives the Utility may receive or the amount of any reimbursement obligations the Utility may incur for 2006-2008, will depend on the form of revised assumptions the CPUC adopts, the level of energy efficiency savings actually achieved over the three-year program cycle, and the amount of the savings attributable to the Utility’s energy efficiency programs based on the revised assumptions and verification results. If the parties are able to reach a settlement, the terms of the settlement, including the amount of any shareholder incentive or reimbursement obligation, would be subject to CPUC approval. It is uncertain whether this alternative dispute process will be successful or whether the CPUC will issue a decision by the end of 2008.

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. On July 31, 2008, the CPUC issued a decision that clarified that the 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. It is expected that that the CPUC will issue a decision regarding authorization of the Utility’s 2009-2011 programs in late 2008 or early 2009.

The amount of any shareholder incentives the Utility may receive or the amount of any reimbursement obligations the Utility may incur for implementation of the 2009-2011 programs will depend on how the CPUC changes the incentive

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

Application to Recover Hydroelectric Generation Facility Divestiture Costs

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

Proposed Electric Distribution Reliability Program (Cornerstone Improvement Program)

On May 15, 2008, the Utility filed an application requesting that the CPUC (1) approve the Utility’s proposed six-year electric distribution reliability improvement program and (2) authorize the Utility to collect revenues to recover forecasted capital expenditures totaling approximately $2.3 billion and operating and maintenance expenses totaling approximately $43 million over the six-year period beginning January 1, 2009. The amounts requested are incremental to the revenue requirement already authorized by the CPUC in the Utility’s 2007 GRC. The program includes initiatives that are designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities. The Utility expects that the work performed in the six-year program also would provide additional reliability benefits. The Utility proposes to record program costs and related revenue requirements in a separate balancing account so that the revenue requirement increase would be used only to recover costs associated with the proposed initiatives, and to allow the return of unused amounts to customers. The Utility would seek CPUC review and approval to recover any costs that exceed the CPUC’s authorized amount. For the next GRC in 2011, the Utility would provide forecasts that exclude costs related to the proposed reliability improvements. The Utility would continue to record the program costs and related revenue requirements in the balancing account until the GRC following the completion of this program in 2014.

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

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

RISK MANAGEMENT ACTIVITIES

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

On June 26, 2008, the CPUC approved the Utility’s conformed 2006 Long-Term Procurement Plan and its revised Electricity and Gas Hedging Plan. The ~~following disclosures omit certain information that has not changed since~~revised plan updates the ~~2007 Annual Report was filed with~~Utility’s planning criteria and need determination over the ~~SEC.~~10-year period 2007-2016.

Price Risk

~~Electricity Procurement~~

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

The Utility expects to satisfy at least some of the forecasted short position through the CPUC-approved contracts it has entered into in accordance with its CPUC-approved long-term procurement plan. As discussed above, the Utility filed a revised 2006 LTPP in March 2008 and issued a new RFO on April 1, 2008 for 800 to 1,200 MW of dispatchable and operationally flexible resources by 2015. The Utility recovers the costs incurred under these contracts and other electricity procurement costs through retail electricity rates that are adjusted whenever the forecasted aggregate over-collections or under-collections of the Utility’s procurement costs for the current year exceed 5% of the Utility's prior year generation revenues, excluding generation revenues for DWR contracts. As long as these cost recovery mechanisms remain in place, adverse market price changes are not expected to impact the Utility's net income. The Utility is at risk to the extent that the CPUC may in the future disallow portions or the full costs of procurement transactions.

Under California’s greenhouse gas emissions law, the State is considering a “cap and trade” program that if adopted, could require entities regulated under the law, including power generators and the Utility, to procure greenhouse gas emissions allowances beginning in 2012. Costs of such allowances could increase the Utility’s electricity procurement costs, but the reasonable costs of these allowances would be expected to be recovered through retail electricity rates.

Electric Transmission Congestion Rights

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

The Utility has been allocated and has acquired via auction certain CRRs as of ~~March 31,~~June 30, 2008 and anticipates acquiring additional CRRs through the allocation and auction phases prior to the MRTU effective date. The anticipated MRTU effective date has been delayed and a revised date has not yet been disclosed by the CAISO. During the first quarter of 2008, the Utility participated in an auction to acquire additional firm electricity transmission rights (“FTRs”) to hedge its financial risk until the MRTU becomes effective.

The CRRs are accounted for as derivative instruments and are recorded in PG&E Corporation’s and the Utility’s

Condensed Consolidated Balance Sheets at fair value. ~~The fair~~On January 1, 2008, the value ofrecorded for CRRs increased ~~significantly~~by $48 million compared to December 31, 2007 due to the adoption of ~~Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“~~SFAS No. ~~157”) on January 1, 2008.~~157. (See Note 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion.) Changes in the fair value of the CRRs are deferred and recorded in regulatory accounts as they are recoverable through rates.

Natural Gas Procurement (Core Customers)

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

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

Natural Gas Transportation and Storage

The Utility uses value-at-risk to measure the ~~shareholders'~~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 ~~99%~~95% confidence level, which means that there is a 1%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~~Utility’s value-at-risk calculated under the methodology described above was approximately ~~$22 million and $31~~$27 million at ~~March 31, 2008 and December 31, 2007, respectively.~~June 30, 2008. The Utility's high, low, and average ~~value-at-risk~~values-at-risk during the ~~years~~six-months ended ~~March 31,~~June 30, 2008 ~~and December 31, 2007~~ were approximately $30 million, ~~$22~~$17 million, and ~~$26 million; and $39 million, $21 million, and $29~~$23 million, respectively.

On April 29, 2008 the Utility began using a 95% confidence level to calculate value-at-risk for its natural gas and transportation services consistent with the CPUC's use of a 95% confidence level in calculating value-at-risk for the Utility's electricity portfolio.

Convertible Subordinated Notes

In accordance with Statement SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), the dividend participation rights ~~component~~ of the Convertible Subordinated Notes isare considered to be an embedded derivative ~~instrument~~instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E ~~Corporation's~~Corporation’s Condensed Consolidated Financial Statements. Dividend participation rights are recognized as operating cash flows in PG&E Corporation’s Condensed Consolidated Statements of Cash Flows. Changes in the fair value are recognized (in Other Income, Net) in PG&E ~~Corporation's~~Corporation’s Condensed Consolidated Statements of Income as a non-operating expense or ~~income (in Other Income, Net).~~income. At ~~March 31,~~June 30, 2008, the total estimated fair value of the dividend participation rights, ~~component,~~ on a pre-tax basis, was approximately ~~$63~~$55 million, of which $27 million was classified ~~as a current liability (in~~in Current Liabilities - ~~Other)~~Other and ~~$36~~$28 million was classified ~~as a noncurrent liability (in~~in Noncurrent Liabilities - ~~Other)~~Other in the accompanying Condensed Consolidated Balance Sheets. At December 31, 2007, the total estimated fair value of the dividend participation rights, ~~component,~~ on a pre-tax basis, was approximately $62 million, of which $25 million was classified as a current liability ~~(in~~in Current Liabilities ~~- - Other)~~– Other and $37 million was classified as a noncurrent liability ~~(in~~in Noncurrent Liabilities ~~- Other)~~– 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 value, of which approximately $1 million was classified as a current liability (in Current Liabilities - Other) and $5 million was classified as a noncurrent liability (in Noncurrent Liabilities - Other) in the accompanying Condensed Consolidated Balance Sheets.fair value. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion of the implementation of SFAS No. 157.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At ~~March 31,~~June 30, 2008, if interest rates changed by 1% for all current variable rate debt issued by PG&E Corporation and the Utility, the change would affect net income by approximately $4$5 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 2007 Annual Report. They include:

·	regulatory assets and liabilities;

·	unbilled revenues;

·	environmental remediation liabilities;

·	asset retirement obligations;

·	income taxes; and

·	pension and other postretirement benefits.

On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157, ~~“Fair Value Measurements” (See New~~(see “New Accounting ~~Pronouncements in the Management Discussion~~Policies” below and ~~Analysis,~~ 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 Condensed Consolidated Financial Statements for further discussion).

For the period ended ~~March 31,~~June 30, 2008, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and there were no material changes to the important assumptions underlying the critical accounting estimates.

NEW ACCOUNTING POLICIES

Fair Value Measurements

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

Level 3 Instruments at Fair Value

(in millions)
Value as of March 31, 2008

Nuclear Decommissioning Funds $ 7
Long Term Disability Trust 103
Price Risk Management Instruments 299
Dividend Participation Rights (63 )
Other (2 )
Total Level 3 $ 344

(in millions)	Value as of June 30, 2008
Nuclear Decommissioning Funds	$	7
Price Risk Management Instruments		382
Long Term Disability Trust		95
Dividend Participation Rights		(55	)
Other		(6	)
Total Level 3 Instruments	$	423

Level 3 fair value measurements represent ~~13%~~15% of the total net value of all fair value measurements of PG&E Corporation. During the three ~~month period~~and six months ended ~~March 31,~~June 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 onin the ~~balance sheet~~accompanying Condensed Consolidated Balance Sheets with the exception of the dividend participation rights which are held by PG&E Corporation. The changes in the dividend participation rights are reflected in Other Income, 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 ~~March 31,~~June 30, 2008.

Nuclear Decommissioning Funds and Long Term Disability Trust

The nuclear decommissioning funds and the long-term disability trust primarily hold equities, debt securities, mutual funds, and life insurance policies. These instruments are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. Commingled funds within these trusts represent the Utility’s shares of certain money market funds held. Due to liquidity restrictions and lack of an active market for individual shares of these money market funds, commingled funds are classified as Level 3. The Level 3 nuclear decommissioning fund assets did not change significantly ~~from January 1, 2008 to March 31,~~for the three and six months ended June 30, 2008. The Level 3 long-term disability trust assets increased from approximately $69 million at January 1, 2008 to approximately $95 million at June 30, 2008. This increase of approximately $26 million was primarily due to purchases of commingled fund investments. Additionally, the Level 3 long-term disability trust assets decreased from approximately $103 million at March 31, 2008 to

approximately $95 million at June 30, 2008. ~~The $34~~This decrease of approximately $8 million ~~increase~~ was primarily due to ~~purchases~~sale of commingled fund investments.

Price Risk Management Instruments

The price risk management instrument category is comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. When necessary, PG&E Corporation and the Utility generally use similar models to value similar instruments. Since the Utility’s contracts are used within the regulatory framework, regulatory accounts are recorded to offset the associated gains and losses of these derivatives, which will be reflected in future rates. The Level 3 price risk management instruments increased from approximately $115 million as of January 1, 2008 to ~~$299~~approximately $382 million as of ~~March 31,~~June 30, 2008. This ~~$184~~increase of approximately $267 million ~~increase~~ was primarily due to an increase in commodity prices on ~~March 31,~~June 30, 2008 as compared to January 1, 2008. Additionally, the Level 3 price risk management instruments increased from approximately $299 million as of March 31, 2008 to approximately $382 million at June 30, 2008. This increase of approximately $83 million was primarily due to an increase in commodity prices on June 30, 2008 as compared to March 31, 2008.

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.

CRRs, FTRs, and ~~DR Contracts~~demand response contracts are new and/or complex instruments that have immature or limited markets. CRRs allow market participants, including LSEs, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. FTRs allow market participants, including LSEs, to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market prior to the operation of the MRTU day-ahead market. ~~DRs~~Demand response contracts allow market participants, including LSEs, 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 or dealer quotations. Such instruments are generally classified within Level 3 of the fair value hierarchy.

Dividend Participation Rights

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

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

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

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

ENVIRONMENTAL MATTERS

·	Approximately ~~$228~~$221 million for remediation at the Hinkley and Topock natural gas compressor sites;

·	Approximately ~~$90~~$83 million related to remediation at divested generation facilities;

·	Approximately ~~$185~~$182 million related to remediation costs for the Utility’s generation and other facilities, third-party disposal sites, and manufactured gas plant sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites); and

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

The Utility's undiscounted future costs could increase to as much as ~~$912~~$895 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than ~~anticipated.~~anticipated, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The amount of approximately ~~$912~~$895 million does not include any estimate for any potential costs of remediation at former manufactured gas plant sites owned by others, unless the Utility has assumed liability for the site, the current owner has asserted a claim against the Utility, or the Utility has otherwise determined it is probable that a claim will be asserted.

Various parties separately challenged the EPA's regulations and in ~~court and the EPA regulations were suspended. The cases were consolidated in~~January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”)~~. In January 2007, the~~ 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 ~~held that a cost-benefit test could not be used to comply with performance standards or to obtain a variance from~~in July 2007 the ~~standards. The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard.~~EPA suspended its regulations. In April 2008, the U.S. Supreme Court ~~indicated it will~~agreed to review the Second Circuit decision regarding the cost-benefit ~~test. It~~test and a decision is ~~uncertain when the Supreme Court will issue a decision.~~expected by mid-2009. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo ~~Canyon.~~Canyon and may incur a material charge.

TAX MATTERS

In the first quarter of 2008, PG&E Corporation ~~finalized~~reached a settlement with the ~~IRS~~Internal Revenue Service (“IRS”) appellate division for tax years 1997-2000. On July 9, 2008, PG&E Corporation was notified that the U.S. Congress’ Joint Committee on Taxation (“Joint Committee”) had approved the settlement. This settlement did not result in material changes to the amount of unrecognized tax benefits ~~at December 31, 2007~~ that PG&E Corporation ~~recognized~~recorded under FASB Interpretation No. 48, “Accounting for Uncertainty in Income ~~Taxes” (“FIN 48”).~~Taxes.”

~~In addition, during the first quarter of~~On June 20, 2008, PG&E Corporation reached ~~a tentative settlement~~an agreement with the IRS regarding a change in accounting method related to the capitalization of indirect service costs for tax years ~~2001-2002 that would resolve issues raised~~2001-2004. This agreement resulted in a $29 million benefit from a reduction in interest expense accrued on unrecognized tax benefits partially offset by a $15 million liability associated with unrecognized state tax benefits, for a net tax benefit of approximately $14 million. On June 27, 2008, PG&E Corporation agreed to a revenue agent report (“RAR”) from the IRS ~~with respect~~that reflected this agreement and resolved all 2001-2002 audit issues, except a dispute relating to several significant deductions taken by PG&E Corporation related to losses sustained at National Energy & Gas Transmission, Inc. The IRS has indicated that it intends to allow deductions in its audits of PG&E Corporation’s tax returns for tax years 2003-2004 that it disallowed in tax years 2001–2002. The tentative settlement also would resolve certain issues related to the Utility. Remaining issues that are not part of the tentative settlement, including whether PG&E Corporation is entitledentitlement to $104 million inof synthetic fuel tax credits, ~~will be~~which was referred to the IRS appellate ~~division.~~

from the federal capital loss carry forwards.

LEGAL MATTERS

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

PG&E Corporation and the Utility's primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management ~~(“PRM”)~~ activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these ~~PRM~~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” ~~section included~~ above under Item 2: 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 and the Utility's disclosure controls and procedures as of ~~March 31,~~June 30, 2008, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 (“the Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal controls over financial reporting that occurred during the quarter ended ~~March 31,~~June 30, 2008 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Solano County District Attorney’s Office

~~In a letter dated July 11, 2007,~~For more information regarding the ~~Solano County District Attorney's Office stated its intention to file a civil complaint against~~resolution of this matter, see “Part II, Item 1. Legal Proceedings” in PG&E Corporation's and the ~~Utility~~Utility's combined Quarterly Report on Form 10-Q for ~~record-keeping violations related to an underground storage tank at~~ the Utility’s service center in Vallejo, California. The letter attached a copy of the draft complaint, which detailed a series of alleged California Health and Safety Code record-keeping violations, some of which date back to 2004. Alleged violations include failing to complete inspections, testing, and certifications, and to make records available to the County. Under the California Health and Safety Code, penalties of up to $5,000 per day for each violation may be assessed. The draft complaint also seeks penalties for unfair and unlawful business practices under California Business and Professions Code Section 17200, under which penalties of up to $2,500 per violation may be assessed. There are no allegations related to the discharge of any hazardous substances. The Utility has investigated the allegations and has reached agreement with the District Attorney. Pursuant to that agreement, a stipulation for entry of final judgment and a complaint were filed simultaneously on April 8,quarter ended March 31, 2008. The terms of the judgment provide that the Utility will pay a total of $75,320 and will comply with injunctive provisions requiring compliance with applicable regulations and certifications for underground storage tanks owned and operated in Solano County for three years.

ITEM 1A. RISK FACTORS

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

Because the U.S. Department of Energy has failed to develop a permanent national repository for the nation's spent nuclear fuel and high-level radioactive waste produced by the nation's nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon 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.

~~Also, on April 30, 2008, in~~In connection with the pending appeal of the 2004 decision by the Nuclear Regulatory Commission ("NRC") to grant the Utility a permit to construct the dry cask storage facility, the NRC ~~set~~held a hearing ~~date of~~on July 1, 2008 ~~for oral argument on~~to consider whether the NRC staff sufficiently addressed the latent health impacts and damage to property of a potential radiological release in its supplemental environmental assessment report ~~that~~when it decided to issue the permit. The NRC’s supplemental assessment had concluded there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon dry cask storage facility. ItThe NRC is expected ~~that the NRC will~~to issue a ~~final~~ decision on this matter in the ~~fourth~~third quarter of 2008.

The discussion of the potential adverse impact of municipalization and other forms of bypass on the Utility are discussed in the 2007 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors” under following caption “The Utility faces the risk of unrecoverable costs if its customers obtain distribution and transportation services from other providers as a result of municipalization, technological change, or other forms of bypass.” is updated as follows to describe a voter initiative that will appear on the City and County of San Francisco’s November 2008 ballot:

On July 22, 2008, the Board of Supervisors of the City and County of San Francisco voted to place an initiative on the November 2008 ballot seeking approval to amend the city’s charter to require a study of the costs and benefits of taking over the electric system in San Francisco. The charter amendment would allow the Board of Supervisors to issue revenue bonds to finance a takeover of the Utility’s facilities in San Francisco without further voter approval, as is currently required. If the ballot measure were approved and the Board of Supervisors were to move forward with municipalization proceedings, the Utility would be entitled to receive the fair market value of its facilities subject to the takeover, but the valuation issues in any municipalization proceeding would most likely be highly contentious.

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

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

During the second quarter ~~ended March 31,~~of 2008, PG&E Corporation ~~made an equity contribution~~did not redeem or repurchase any shares of ~~$50 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.~~

~~Issuer Purchases of Equity Securities~~

~~PG&E Corporation common stock:~~

Period Total Number of Shares Purchased Average Price Paid 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, 2008
2,777(1)
$ $43.25 - $ -
February 1 through February 28, 2008 - $ - - $ -
March 1 through March 31, 2008 - $ - - $ -
Total 2,777 $ $43.25 - $ -

(1) On January 2, 2008, Mary S. Metz, a director of PG&E Corporation and the Utility, delivered 2,777 of her shares of PG&E Corporation common stock to PG&E Corporation to pay the exercise price in connection with an exercise of options to purchase PG&E Corporation common stock. This transaction was reported on a Form 4 filed with the SEC on January 4, 2008.

stock outstanding. During the ~~first~~second quarter of 2008, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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

PG&E Corporation:

On May 14, 2008, PG&E Corporation held its annual meeting of shareholders. At the meeting, the shareholders voted as indicated below on the following matters:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Pacific Gas and Electric Company:

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

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

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

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

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

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

ITEM 5. OTHER INFORMATION

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

The Utility's earnings to fixed charges ratio for the three and six months ended ~~March 31,~~June 30, 2008 was ~~2.62.~~3.01 and 2.82, respectively. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three and six months ended ~~March 31,~~June 30, 2008 was ~~2.57.~~2.96 and 2.77, respectively. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility's Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility's first preferred stock and its senior notes, respectively.

ITEM 6. EXHIBITS

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

3.2	Bylaws of Pacific Gas and Electric Company, as amended as of May 14, 2008

~~4.1~~	~~Third Supplemental Indenture dated as of March 3, 2008 relating to the issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038~~ (incorporated by reference to Pacific Gas and Electric Company’s ~~Current~~Quarterly Report on Form ~~8-K dated~~10-Q for the quarter ended March 3,31, 2008 (File No. 1-2348), Exhibit ~~4.1)~~3.2)

10.1*	~~Resolution of the~~Amendment to January 3, 2007 Restricted Stock Agreement between PG&E Corporation ~~Board of Directors dated February 20,~~and Peter A. Darbee, effective May 9, 2008 ~~adopting director compensation arrangement effective January 1, 2008 (incorporated by reference~~(January 3, 2007 Restricted Stock Agreement filed as Exhibit 10.3 to PG&E Corporation’s and Pacific Gas and Electric Company’s Quarterly Report on Form ~~10-K~~10-Q for the ~~year~~quarter ended ~~December~~March 31, ~~2007 (File No. 1-12609), Exhibit 10.28)~~2007)

10.2*	Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2007 (File No. 1-2348), Exhibit 10.29)

10.3*	~~Letter regarding Compensation~~Restricted Stock Unit Agreement between ~~Pacific Gas~~Peter A. Darbee and ~~Electric Company and Barbara Barcon dated March 3, 2008~~

10.4*	~~Separation Agreement between~~ PG&E Corporation ~~and G. Robert Powell~~ dated ~~March 6,~~May 9, 2008

10.5*	~~Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan~~


10.6*	~~Form of Performance Share Agreement for 2008 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

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.

6064

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~~
CHRISTOPHER P. ~~Johns~~JOHNS

Christopher P. Johns Senior Vice President, Chief Financial Officer, and Treasurer (duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

~~Barbara~~
BARBARA L. ~~Barcon~~BARCON

Barbara L. Barcon Vice President, Finance and Chief Financial Officer (duly authorized officer and principal financial officer)

Dated: ~~May~~August 6, 2008

6165

EXHIBIT INDEX

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

3.2	Bylaws of Pacific Gas and Electric Company, as amended as of May 14, 2008

~~4.1~~	~~Third Supplemental Indenture dated as of March 3, 2008 relating to the issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038~~ (incorporated by reference to Pacific Gas and Electric Company’s ~~Current~~Quarterly Report on Form ~~8-K dated~~10-Q for the quarter ended March 3,31, 2008 (File No. 1-2348), Exhibit ~~4.1)~~3.2)

10.1*	~~Resolution of the~~Amendment to January 3, 2007 Restricted Stock Agreement between PG&E Corporation ~~Board of Directors dated February 20,~~and Peter A. Darbee, effective May 9, 2008 ~~adopting director compensation arrangement effective January 1, 2008 (incorporated by reference~~(January 3, 2007 Restricted Stock Agreement filed as Exhibit 10.3 to PG&E Corporation’s and Pacific Gas and Electric Company’s Quarterly Report on Form ~~10-K~~10-Q for the ~~year~~quarter ended ~~December~~March 31, ~~2007 (File No. 1-12609), Exhibit 10.28)~~2007)

10.2*	Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1, 2008 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2007 (File No. 1-2348), Exhibit 10.29)

10.3*	~~Letter regarding Compensation~~Restricted Stock Unit Agreement between ~~Pacific Gas~~Peter A. Darbee and ~~Electric Company and Barbara Barcon dated March 3, 2008~~

10.4*	~~Separation Agreement between~~ PG&E Corporation ~~and G. Robert Powell~~ dated ~~March 6,~~May 9, 2008

10.5*	~~Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan~~

10.6*	~~Form of Performance Share Agreement for 2008 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

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.

6266

Current Liabilities – Other	16	67
Noncurrent Liabilities – Other	21	20


(1) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $100 million decrease to Current Assets-Prepaid expenses and other, a $54 million decrease to Other Noncurrent Assets–Other, and a $1 million increase to Noncurrent Liabilities–Other.
(2) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $3 million increase to Current Assets-Prepaid expenses and other, a $46 million increase to Other Noncurrent Assets–Other, and a $16 million decrease to Current Liabilities–Other. These collateral amounts have been reclassified from Current Assets–Prepaid expenses as was presented in the 2007 Annual Report.

	Cash Flow Hedges
(in millions)	March 31, 2008(1)			December 31, 2007(2)
Current Assets – Prepaid expenses and other	$	57		$	(2	) (3)
Other Noncurrent Assets – Other		50			42
Current Liabilities – Other		(2	) (4)		12
Noncurrent Liabilities – Other		-			3


(1) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $14 million decrease to Current Assets-Prepaid expenses and other and a $9 million decrease to Other Noncurrent Assets-Other.
(2) Balances include the impact of cash collateral in accordance with the requirements of FIN 39-1 of a $9 million increase to Other Noncurrent Assets-Other and a $7 million decrease to Current Liabilities-Other. These collateral amounts have been reclassified from Current Assets–Prepaid expenses as was presented in the 2007 Annual Report.
(3) $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.
(4) $2 million of the cash flow hedges in an asset position at March 31, 2008 relate to counterparties for which the total net derivatives position is a current liability.

Utility expenses from:
Administrative services received from PG&E Corporation	$	24	$	24	$	(27	)	$	(28	)
Utility employee benefit asset contributions provided to PG&E Corporation		-		1		-			-

(in millions)
2008	$	1,247
2009		599
2010		93
2011		80
2012		49
Thereafter		199
Total	$	2,267

(in millions)	Value as of March 31, 2008
Nuclear Decommissioning Funds	$	7
Long Term Disability Trust		103
Price Risk Management Instruments		299
Dividend Participation Rights		(63	)
Other		(2	)
Total Level 3	$	344

Period	Total Number of Shares Purchased	Average Price Paid 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, 2008	2,777(1)	$	$43.25	-	$	-
February 1 through February 28, 2008	-	$	-	-	$	-
March 1 through March 31, 2008	-	$	-	-	$	-
Total	2,777	$	$43.25	-	$	-


(1) On January 2, 2008, Mary S. Metz, a director of PG&E Corporation and the Utility, delivered 2,777 of her shares of PG&E Corporation common stock to PG&E Corporation to pay the exercise price in connection with an exercise of options to purchase PG&E Corporation common stock. This transaction was reported on a Form 4 filed with the SEC on January 4, 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 in accordance with the requirements of FIN 39-1 of $6 million.

~~(2)~~ The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions SFAS No. 157, resulting in a $6 million expense to increase the value of the liability.

~~(3)~~Excludes taxes on appreciation of investment value and cash and cash equivalents.