Transition



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 ~~June~~September 30, 2005 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 the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve 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.

Yes X				No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

PG&E Corporation:

Yes X				No

Pacific Gas and Electric Company:

Yes			No X

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes			No X


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

Common Stock Outstanding, ~~July 28,~~October 27, 2005:
PG&E Corporation				~~373,054,553~~374,754,368 shares (excluding 24,665,500 shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company				Wholly owned by PG&E Corporation

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED ~~JUNE~~SEPTEMBER 30, 2005
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	13
	NOTE 2:		The Utility's Emergence from Chapter 11	2223
	NOTE 3:		Debt	2324
	NOTE 4:		Energy Recovery Bonds	2729
	NOTE 5:		Shareholders' Equity	2829
	NOTE 6:		Risk Management Activities	3031
	NOTE 7:		Commitments and Contingencies	3133

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			4042
	Results of Operations			4547
	Liquidity and Financial Resources			5357
	Contractual Commitments			5963
	Capital Expenditures			5963
	Off-Balance Sheet Arrangements			6064
	Contingencies			6065
	Risk Management Activities			6572
	Critical Accounting Policies			6976
	Accounting Pronouncements Issued But Not Yet Adopted			7178
	Additional Security Measures			7178
	Environmental and Legal Matters			7178

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			7178
ITEM 4.	CONTROLS AND PROCEDURES			7178

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			7279
ITEM 2.	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES			73
~~ITEM 4.~~	~~SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~			7481
ITEM 5.	OTHER INFORMATION			7481
ITEM 6.	EXHIBITS			7482

SIGNATURES				7683

PART I. FINANCIAL INFORMATION
ITEM 1:1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION	PG&E CORPORATION									PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		(Unaudited)									(Unaudited)

(in millions, except per share amounts)		Three Months Ended				Six Months Ended					Three Months Ended				Nine Months Ended
		June 30,				June 30,					September 30,				September 30,

		2005		2004		2005		2004			2005		2004		2005		2004

Operating Revenues
Electric		$	1,780	$	2,063	$	3,439	$	3,851		$	2,107	$	2,042	$	5,546	$	5,902
Natural gas		718		686		1,727		1,617			697		581		2,424		2,198

Total operating revenues		2,498		2,749		5,166		5,468			2,804		2,623		7,970		8,100

Operating Expenses
Cost of electricity		487		685		884		1,254			742		792		1,626		2,003
Cost of natural gas		347		278		967		857			326		239		1,293		1,096
Operating and maintenance		670		757		1,436		1,576			740		677		2,177		2,297
Recognition of regulatory assets		-		-		-		(4,900)			-		-		-		(4,900)
Depreciation, amortization and decommissioning		454		353		839		651			481		406		1,320		1,056
Reorganization professional fees and expenses		-		4		-		6			-		-		-		6

Total operating (gain) expenses		1,958		2,077		4,126		(556)
Total operating expenses											2,289		2,114		6,416		1,558

Operating Income		540		672		1,040		6,024			515		509		1,554		6,542
Reorganization interest income		-		-		-		8			-		-		-		8
Interest income		16		25		37		31			22		15		60		46
Interest expense		(131)		(176)		(292)		(406)			(145)		(159)		(438)		(565)
Other expense, net		(2)		(14)		(3)		(41)
Other income (expense), net											(14)		4		(16)		(46)

Income Before Income Taxes		423		507		782		5,616			378		369		1,160		5,985
Income tax provision		156		135		297		2,211			139		141		436		2,352

Income From Continuing Operations												239		228		724		3,633
Discontinued Operations (Note 7)												13		-		13		-

Net Income		$	267	$	372	$	485	$	3,405		$	252	$	228	$	737	$	3,633

Weighted Average Common Shares Outstanding, Basic		370		397		379		395			372		399		376		397

Earnings Per Common Share from Continuing Operations, Basic											$	0.63	$	0.55	$	1.88	$	8.73



Net Earnings Per Common Share, Basic		$	0.70	$	0.89	$	1.25	$	8.22		$	0.66	$	0.55	$	1.91	$	8.73



Earnings Per Common Share from Continuing Operations, Diluted											$	0.62	$	0.53	$	1.86	$	8.55

Net Earnings Per Common Share, Diluted		$	0.70	$	0.88	$	1.23	$	8.03		$	0.65	$	0.53	$	1.89	$	8.55

Dividends Declared Per Common Share		$	0.30	$	-	$	0.60	$	-		$	0.30	$	-	$	0.90	$	-

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
	Balance At

(in millions)	September 30,		December 31,
	2005 (Unaudited)		2004

ASSETS
Current Assets
Cash and cash equivalents	$	1,233	$	972
Restricted cash	1,527		1,980
Accounts receivable:
Customers (net of allowance for doubtful accounts of $105 million in 2005 and $93 million in 2004)	2,120		2,085
Regulatory balancing accounts	483		1,021
Inventories:
Gas stored underground and fuel oil	265		175
Materials and supplies	136		129
Prepaid expenses and other	243		46

Total current assets	6,007		6,408

Property, Plant and Equipment
Electric	22,073		21,519
Gas	8,688		8,526
Construction work in progress	679		449
Other	15		15

Total property, plant and equipment	31,455		30,509
Accumulated depreciation	(11,907)		(11,520)

Net property, plant and equipment	19,548		18,989

Other Noncurrent Assets
Regulatory assets	6,000		6,526
Nuclear decommissioning funds	1,693		1,629
Other	912		988

Total other noncurrent assets	8,605		9,143

TOTAL ASSETS	$	34,160	$	34,540




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

(in millions, except share amounts)	September 30,			December 31,
	2005 (Unaudited)			2004

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$		-	$	300
Long-term debt, classified as current			2		758
Rate reduction bonds, classified as current	290			290
Energy recovery bonds, classified as current	228			-
Accounts payable:
Trade creditors	568			762
Disputed claims and customer refunds	1,841			2,142
Regulatory balancing accounts	1,149			369
Other	414			352
Interest payable	401			461
Income taxes payable	199			185
Deferred income taxes	111			394
Other	1,212			905

Total current liabilities	6,415			6,918

Noncurrent Liabilities
Long-term debt	6,976			7,323
Rate reduction bonds	366			580
Energy recovery bonds	1,583			-
Regulatory liabilities	3,935			4,035
Asset retirement obligations	1,370			1,301
Deferred income taxes	3,165			3,531
Deferred tax credits	116			121
Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, no shares outstanding at September 30, 2005, 4,925,000 shares outstanding at December 31, 2004)	-			122
Other	1,747			1,690

Total noncurrent liabilities	19,258			18,703

Commitments and Contingencies (Notes 1, 2, 3, 4 and 7)
Preferred Stock of Subsidiaries	252			286
Preferred Stock
Preferred stock, no par value, 80,000,000 shares, $100 par value, 5,000,000 shares, none issued	-			-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 397,945,522 common and 1,391,028 restricted shares in 2005 and 414,985,014 common and 1,535,268 restricted shares in 2004	6,312			6,518
Common stock held by subsidiary, at cost, 24,665,500 shares	(718)			(718)
Unearned compensation	(26)			(26)
Accumulated earnings	2,672			2,863
Accumulated other comprehensive loss	(5)			(4)

Total common shareholders' equity	8,235			8,633

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,160		$	34,540




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance At
(in millions)
June 30,
December 31,
2005
(Unaudited)
2004
ASSETS
Current Assets
   Cash and cash equivalents
$
1,494
$
972
   Restricted cash
1,659
1,980
   Accounts receivable:
      Customers (net of allowance for doubtful accounts of $91
         million in 2005 and $93 million in 2004)
2,029
2,085
      Regulatory balancing accounts
859
1,021
   Inventories:
      Gas stored underground
175
175
      Materials and supplies
137
129
   Prepaid expenses and other
72
46
      Total current assets
6,425
6,408
Property, Plant and Equipment
   Electric
21,975
21,519
   Gas
8,663
8,526
   Construction work in progress
533
449
   Other
15
15
      Total property, plant and equipment
31,186
30,509
   Accumulated depreciation
(11,891)
(11,520)
      Net property, plant and equipment
19,295
18,989
Other Noncurrent Assets
   Regulatory assets
6,236
6,526
   Nuclear decommissioning funds
1,659
1,629
   Other
802
988
      Total other noncurrent assets
8,697
9,143
TOTAL ASSETS
$
34,417
$
34,540
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)

(in millions)	Nine Months Ended
	September 30,

	2005		2004

Cash Flows From Operating Activities
Net income	$	737	$	3,633
Discontinued operations	(13)		-

Net income from continuing operations	724		3,633
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction	1,295		1,056
Recognition of regulatory assets	-		(4,900)
Deferred income taxes and tax credits, net	(658)		2,360
Other deferred charges and noncurrent liabilities	(133)		(183)
Net effect of changes in operating assets and liabilities:
Short-term investments	(6)		-
Accounts receivable	58		42
Inventories	(97)		(61)
Accounts payable	(80)		78
Accrued taxes	14		4
Regulatory balancing accounts, net	940		(323)
Other working capital	(58)		572
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	-		(1,022)
Other, net	118		84

Net cash provided by operating activities	2,117		1,340


Cash Flows From Investing Activities
Capital expenditures	(1,318)		(1,110)
Net proceeds from sale of assets	19		28
Decrease (increase) in restricted cash	453		(1,601)
Other, net	3		(55)

Net cash used in investing activities	(843)		(2,738)

Cash Flows From Financing Activities
Repayments under credit facilities and short-term borrowings	(300)		-
Proceeds from issuance of long-term debt, net of issuance costs of $3 million in 2005 and $74 million in 2004	451		7,346
Proceeds from issuance of energy recovery bonds, net of issuance costs of $14 million in 2005	1,874		-
Long-term debt matured, redeemed or repurchased	(1,556)		(7,553)
Rate reduction bonds matured	(214)		(213)
Energy recovery bonds matured	(77)		-
Preferred stock with mandatory redemption provisions redeemed	(122)		(15)
Preferred stock without mandatory redemption provisions redeemed	(36)		-
Common stock issued	231		121
Common stock repurchased	(1,087)		-
Preferred dividends paid	(12)		(88)
Common stock dividends paid	(223)		-
Other	58		(2)

Net cash used in financing activities	(1,013)		(404)

Net change in cash and cash equivalents	261		(1,802)
Cash and cash equivalents at January 1	972		3,658

Cash and cash equivalents at September 30	$	1,233	$	1,856



Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	-	$	13
Cash paid for:
Interest (net of amounts capitalized)	373		522
Income taxes paid, net	1,051		96
Reorganization professional fees and expenses	-		21
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	111	$	-
Transfer of liabilities and other payables subject to compromise to operating assets and liabilities		-	(2,877)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	(Unaudited)

(in millions)	Three Months Ended				Nine Months Ended
	September 30,				September 30,

	2005		2004		2005		2004

Operating Revenues
Electric	$	2,107	$	2,042	$	5,546	$	5,902
Natural gas	697		581		2,424		2,198

Total operating revenues	2,804		2,623		7,970		8,100

Operating Expenses
Cost of electricity	742		792		1,626		2,003
Cost of natural gas	326		239		1,293		1,096
Operating and maintenance	738		671		2,179		2,271
Recognition of regulatory assets	-		-		-		(4,900)
Depreciation, amortization and decommissioning	481		405		1,320		1,054
Reorganization professional fees and expenses	-		-		-		6

Total operating expenses	2,287		2,107		6,418		1,530

Operating Income	517		516		1,552		6,570
Reorganization interest income	-		-		-		8
Interest income	20		11		59		36
Interest expense	(138)		(141)		(416)		(512)
Other income (expense), net	(3)		14		9		43

Income Before Income Taxes	396		400		1,204		6,145
Income tax provision	148		152		457		2,410

Net Income	248		248		747		3,735
Preferred dividend requirement	4		4		12		17

Income Available for Common Stock	$	244	$	244	$	735	$	3,718




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

(in millions)	September 30,		December 31,
	2005		2004
	(Unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	856	$	783
Restricted cash	1,527		1,980
Accounts receivable:
Customers (net of allowance for doubtful accounts of $105 million in 2005 and $93 million in 2004)	2,120		2,085
Related parties	2		2
Regulatory balancing accounts	483		1,021
Inventories:
Gas stored underground and fuel oil	265		175
Materials and supplies	136		129
Prepaid expenses and other	239		43

Total current assets	5,628		6,218

Property, Plant and Equipment
Electric	22,073		21,519
Gas	8,688		8,526
Construction work in progress	679		449

Total property, plant and equipment	31,440		30,494
Accumulated depreciation	(11,894)		(11,507)

Net property, plant and equipment	19,546		18,987

Other Noncurrent Assets
Regulatory assets	6,000		6,526
Nuclear decommissioning funds	1,693		1,629
Other	865		942

Total other noncurrent assets	8,558		9,097

TOTAL ASSETS	$	33,732	$	34,302




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
PACIFIC GAS AND ELECTRIC COMPANY							PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS	CONDENSED CONSOLIDATED BALANCE SHEETS						CONDENSED CONSOLIDATED BALANCE SHEETS
		Balance At						Balance At

(in millions, except share amounts)	(in millions, except share amounts)	June 30,			December 31,		(in millions, except share amounts)	September 30,		December 31,
		2005 (Unaudited)			2004			2005		2004
								(Unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY	LIABILITIES AND SHAREHOLDERS' EQUITY						LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities	Current Liabilities						Current Liabilities
Short-term borrowings		$		-	$	300
Short term borrowings							Short term borrowings	$	-	$	300
Long-term debt, classified as current	Long-term debt, classified as current			202		758	Long-term debt, classified as current		2		757
Rate reduction bonds, classified as current	Rate reduction bonds, classified as current	290			290		Rate reduction bonds, classified as current	290		290
Energy recovery bonds, classified as current	Energy recovery bonds, classified as current	232			-		Energy recovery bonds, classified as current	228		-
Accounts payable:	Accounts payable:						Accounts payable:
Trade creditors	Trade creditors	488			762		Trade creditors	568		762
Disputed claims and customer refunds	Disputed claims and customer refunds	1,810			2,142		Disputed claims and customer refunds	1,841		2,142
Related parties							Related parties	22		20
Regulatory balancing accounts	Regulatory balancing accounts	1,150			369		Regulatory balancing accounts	1,149		369
Other	Other	420			352		Other	401		337
Interest payable	Interest payable	427			461		Interest payable	395		461
Income taxes payable	Income taxes payable	339			185		Income taxes payable	179		102
Deferred income taxes	Deferred income taxes	357			394		Deferred income taxes	85		377
Other	Other	856			905		Other	1,068		869

Total current liabilities	Total current liabilities	6,571			6,918		Total current liabilities	6,228		6,786

Noncurrent Liabilities	Noncurrent Liabilities						Noncurrent Liabilities
Long-term debt	Long-term debt	6,977			7,323		Long-term debt	6,696		7,043
Rate reduction bonds	Rate reduction bonds	439			580		Rate reduction bonds	366		580
Energy recovery bonds	Energy recovery bonds	1,642			-		Energy recovery bonds	1,583		-
Regulatory liabilities	Regulatory liabilities	3,797			4,035		Regulatory liabilities	3,935		4,035
Asset retirement obligations	Asset retirement obligations	1,347			1,301		Asset retirement obligations	1,370		1,301
Deferred income taxes	Deferred income taxes	3,457			3,531		Deferred income taxes	3,288		3,629
Deferred tax credits	Deferred tax credits	117			121		Deferred tax credits	116		121
Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, no shares outstanding at June 30, 2005, 4,925,000 shares outstanding at December 31, 2004)		-			122
Preferred stock with mandatory redemption provisions (redeemable, 6.30% and 6.57%, no shares outstanding)							Preferred stock with mandatory redemption provisions (redeemable, 6.30% and 6.57%, no shares outstanding)	-		122
Other	Other	1,720			1,690		Other	1,615		1,555

Total noncurrent liabilities	Total noncurrent liabilities	19,496			18,703		Total noncurrent liabilities	18,969		18,386

Commitments and Contingencies (Notes 1, 2, 3, 4 and 7)	Commitments and Contingencies (Notes 1, 2, 3, 4 and 7)						Commitments and Contingencies (Notes 1, 2, 3, 4 and 7)
Preferred Stock of Subsidiaries		286			286
Preferred Stock
Preferred stock, no par value, 80,000,000 shares, $100 par value, 5,000,000 shares, none issued		-			-
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued 396,118,663 common and 1,390,388 restricted shares in 2005 and 417,014,431 common and 1,601,710 restricted shares in 2004		6,282			6,518
Common stock held by subsidiary, at cost, 24,665,500 shares		(718)			(718)
Unearned compensation		(28)			(26)
Accumulated earnings		2,533			2,863
Shareholders' Equity							Shareholders' Equity
Preferred stock without mandatory redemption provisions:							Preferred stock without mandatory redemption provisions:
Nonredeemable, 5% to 6%, outstanding 5,784,825 shares							Nonredeemable, 5% to 6%, outstanding 5,784,825 shares	145		145
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares in 2005 and 4.36% to 7.04%, outstanding 5,973,456 shares in 2004							Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares in 2005 and 4.36% to 7.04%, outstanding 5,973,456 shares in 2004	113		149
Common stock, $5 par value, authorized 800,000,000 shares, issued 299,291,477 shares							Common stock, $5 par value, authorized 800,000,000 shares, issued 299,291,477 shares	1,496		1,606
Common stock held by subsidiary, at cost, 19,481,213 shares							Common stock held by subsidiary, at cost, 19,481,213 shares	(475)		(475)
Additional paid-in capital							Additional paid-in capital	1,901		2,041
Reinvested earnings							Reinvested earnings	5,360		5,667
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(5)			(4)		Accumulated other comprehensive loss	(5)		(3)

Total common shareholders' equity		8,064			8,633
Total shareholders' equity							Total shareholders' equity	8,535		9,130

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,417		$	34,540	TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	33,732	$	34,302

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 STATEMENTS OF CASH FLOWS
	(Unaudited)

(in millions)	Nine Months Ended
	September 30,

	2005		2004

Cash Flows From Operating Activities
Net income	$	747	$	3,735
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, decommissioning and allowance for equity funds used during construction	1,294		1,054
Recognition of regulatory assets	-		(4,900)
Deferred income taxes and tax credits, net	(638)		2,395
Other deferred charges and noncurrent liabilities	(136)		(121)
Net effect of changes in operating assets and liabilities:
Accounts receivable	58		42
Inventories	(97)		(61)
Accounts payable	(83)		77
Accrued taxes	77		87
Regulatory balancing accounts, net	940		(323)
Other working capital	(55)		285
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	-		(1,022)
Other, net	20		10

Net cash provided by operating activities	2,127		1,258

Cash Flows From Investing Activities
Capital expenditures	(1,318)		(1,110)
Net proceeds from sale of assets	19		28
Decrease (increase) in restricted cash	453		(1,601)
Other, net	3		(50)

Net cash used in investing activities	(843)		(2,733)

Cash Flows From Financing Activities
Repayments under credit facilities and short-term borrowings	(300)		-
Proceeds from issuance of long-term debt, net of issuance costs of $3 million in 2005 and $74 million in 2004	451		7,346
Proceeds from issuance of energy recovery bonds, net of issuance costs of $14 million in 2005	1,874		-
Long-term debt matured, redeemed or repurchased	(1,554)		(7,552)
Rate reduction bonds matured	(214)		(213)
Energy recovery bonds matured	(77)		-
Common stock dividends paid	(330)		-
Preferred dividends paid	(12)		(88)
Preferred stock with mandatory redemption provisions redeemed	(122)		(15)
Preferred stock without mandatory redemption provisions redeemed	(36)		-
Common stock repurchased	(960)		-
Other, net	69		(2)

Net cash used in financing activities	(1,211)		(524)

Net change in cash and cash equivalents	73		(1,999)
Cash and cash equivalents at January 1	783		2,979


Cash and cash equivalents at September 30	$	856	$	980



Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	-	$	13
Cash paid for:
Interest (net of amounts capitalized)	360		466
Income taxes paid, net	1,047		94
Reorganization professional fees and expenses	-		21
Supplemental disclosures of noncash investing and financing activities
Equity contribution for settlement of POR payable	$	-	$	(128)
Transfer of liabilities and other payables subject to compromise to operating assets and liabilities		-		(2,877)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
(in millions)
Six Months Ended

June 30,

2005

2004
Cash Flows From Operating Activities
   Net income
$
485
$
3,405
   Adjustments to reconcile net income to
      net cash provided by operating activities:
         Depreciation, amortization and decommissioning
839
651
         Recognition of regulatory assets
-
(4,900)
         Deferred income taxes and tax credits, net
(115)
2,053
         Other deferred charges and noncurrent liabilities
(75)
12
         Tax benefit on employee stock option exercises
37
-
         Gain on sale of assets
-
(18)
   Net effect of changes in operating assets and liabilities:
         Short-term investments
(6)
-
         Accounts receivable
56
(8)
         Inventories
(8)
5
         Accounts payable
(221)
170
         Accrued taxes
153
284
         Regulatory balancing accounts, net
565
(440)
         Other working capital
(164)
560
   Payments authorized by the bankruptcy court on amounts classified as       liabilities subject to compromise
-
(1,022)
   Other, net
37
(134)
Net cash provided by operating activities
1,583
618
Cash Flows From Investing Activities
   Capital expenditures
(803)
(737)
   Net proceeds from sale of assets
17
25
   Decrease (increase) in restricted cash
321
(1,741)
   Other, net
12
(54)
Net cash used in investing activities
(453)
(2,507)
Cash Flows From Financing Activities
   Repayments under credit facilities and short-term
      borrowings
(300)
-
   Proceeds from issuance of long-term debt, net of issuance costs of $3       million in 2005 and $153 million in 2004
451
6,892
   Proceeds from issuance of energy recovery bonds, net of issuance
      costs of $14 million in 2005
1,874
-
   Long-term debt matured, redeemed or repurchased
(1,356)
(7,098)
   Rate reduction bonds matured
(141)
(141)
   Energy recovery bonds matured
(14)
-
   Preferred stock with mandatory redemption provisions redeemed
(122)
(11)
   Common stock issued
190
97
   Common stock repurchased
(1,065)
-
   Preferred dividends paid
(8)
(88)
   Common stock dividends paid
(111)
-
   Other
(6)
-
Net cash used in financing activities
(608)
(349)
Net change in cash and cash equivalents
522
(2,238)
Cash and cash equivalents at January 1
972
3,658
Cash and cash equivalents at June 30
$
1,494
$
1,420
Supplemental disclosures of cash flow information
   Cash received for:
      Reorganization interest income
$
-
$
11
   Cash paid for:
      Interest (net of amounts capitalized)
217
351
      Income taxes paid, net
241
48
      Reorganization professional fees and expenses
-
17
Supplemental disclosures of noncash investing and financing
   activities
   Common stock dividends declared but not yet paid
$
112
$
-
      Transfer of liabilities and other payables subject to compromise
         to operating assets and liabilities
-
(2,877)
      Transfer of disputed claims and customer refunds and interest payable          to accounts payable - regulatory balancing accounts
(378)
-
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in millions)
Three Months Ended
Six Months Ended
June 30,
June 30,
2005
2004
2005
2004
Operating Revenues
   Electric
$
1,780
$
2,063
$
3,439
$
3,851
   Natural gas
718
686
1,727
1,617
      Total operating revenues
2,498
2,749
5,166
5,468
Operating Expenses
   Cost of electricity
487
685
884
1,254
   Cost of natural gas
347
278
967
857
   Operating and maintenance
670
748
1,441
1,557
   Recognition of regulatory assets
-
-
-
(4,900)
   Depreciation, amortization and decommissioning
454
352
839
650
   Reorganization professional fees and expenses
-
4
-
6
      Total operating (gain) expenses
1,958
2,067
4,131
(576)
Operating Income
540
682
1,035
6,044
   Reorganization interest income
-
-
-
8
   Interest income
20
23
39
26
   Interest expense
(124)
(158)
(278)
(372)
   Other income, net
6
24
12
38
Income Before Income Taxes
442
571
808
5,744
   Income tax provision
166
159
309
2,258
Net Income
276
412
499
3,486
   Preferred dividend requirement
4
4
8
12
Income Available for Common Stock
$
272
$
408
$
491
$
3,474
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance At
(in millions)
June 30,
December 31,
2005
2004
(Unaudited)
ASSETS
Current Assets
   Cash and cash equivalents
$
1,140
$
783
   Restricted cash
1,659
1,980
   Accounts receivable:
      Customers (net of allowance for doubtful accounts of
         $91 million in 2005 and $93 million in 2004)
2,029
2,085
      Related parties
2
2
      Regulatory balancing accounts
859
1,021
   Inventories:
      Gas stored underground and fuel oil
175
175
      Materials and supplies
137
129
   Prepaid expenses and other
68
43
      Total current assets
6,069
6,218
Property, Plant and Equipment
   Electric
21,975
21,519
   Gas
8,663
8,526
   Construction work in progress
533
449
      Total property, plant and equipment
31,171
30,494
   Accumulated depreciation
(11,877)
(11,507)
      Net property, plant and equipment
19,294
18,987
Other Noncurrent Assets
   Regulatory assets
6,236
6,526
   Nuclear decommissioning funds
1,659
1,629
   Other
755
942
      Total other noncurrent assets
8,650
9,097
TOTAL ASSETS
$
34,013
$
34,302
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance At
(in millions, except share amounts)
June 30,
December 31,
2005
2004
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
   Short term borrowings
$
-
$
300
   Long-term debt, classified as current
202
757
   Rate reduction bonds, classified as current
290
290
   Energy recovery bonds, classified as current
232
-
   Accounts payable:
      Trade creditors
488
762
      Disputed claims and customer refunds
1,810
2,142
      Related parties
28
20
      Regulatory balancing accounts
1,150
369
      Other
408
337
   Interest payable
427
461
   Income taxes payable
290
102
   Deferred income taxes
334
377
   Other
714
869
      Total current liabilities
6,373
6,786
Noncurrent Liabilities
   Long-term debt
6,697
7,043
   Rate reduction bonds
439
580
   Energy recovery bonds
1,642
-
   Regulatory liabilities
3,797
4,035
   Asset retirement obligations
1,347
1,301
   Deferred income taxes
3,573
3,629
   Deferred tax credits
117
121
   Preferred stock with mandatory redemption provisions
      (redeemable, 6.30% and 6.57%, no shares outstanding)
-
122
   Other
1,589
1,555
      Total noncurrent liabilities
19,201
18,386
Commitments and Contingencies (Notes 1, 2, 3, 4 and 7)
Shareholders' Equity
   Preferred stock without mandatory redemption provisions:
      Nonredeemable, 5% to 6%, outstanding 5,784,825 shares
145
145
      Redeemable, 4.36% to 7.04%, outstanding 5,973,456 shares
149
149
   Common stock, $5 par value, authorized 800,000,000 shares,
      issued 299,291,477 shares
1,496
1,606
   Common stock held by subsidiary, at cost, 19,481,213 shares
(475)
(475)
   Additional paid-in capital
1,901
2,041
   Reinvested earnings
5,228
5,667
   Accumulated other comprehensive loss
(5)
(3)
      Total shareholders' equity
8,439
9,130
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
$
34,013
$
34,302
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in millions)
Six Months Ended
June 30,
2005
2004
Cash Flows From Operating Activities
   Net income
$
499
$
3,486
   Adjustments to reconcile net income to net cash provided by
      operating activities:
         Depreciation, amortization and decommissioning
839
650
         Recognition of regulatory assets
-
(4,900)
         Deferred income taxes and tax credits, net
(103)
2,105
         Other deferred charges and noncurrent liabilities
(83)
79
         Gain on sale of assets
(1)
(18)
   Net effect of changes in operating assets and liabilities:
         Accounts receivable
56
(35)
         Inventories
(8)
5
         Accounts payable
(222)
170
         Accrued taxes
188
288
         Regulatory balancing accounts, net
565
(440)
         Other working capital
(144)
287
   Payments authorized by the bankruptcy court on amounts
      classified as liabilities subject to compromise
-
(1,022)
   Other, net
18
(128)
Net cash provided by operating activities
1,604
527
Cash Flows From Investing Activities
   Capital expenditures
(803)
(737)
   Net proceeds from sale of assets
17
25
   Decrease (increase) in restricted cash
321
(1,741)
   Other, net
12
(54)
Net cash used in investing activities
(453)
(2,507)
Cash Flows From Financing Activities
   Repayments under credit facilities and short-term
      borrowings
(300)
-
   Proceeds from issuance of long-term debt, net of issuance costs of
      $3 million in 2005 and $153 million in 2004
451
6,892
   Proceeds from issuance of energy recovery bonds, net of issuance
      costs of $14 million in 2005
1,874
-
   Long-term debt matured, redeemed or repurchased
(1,354)
(7,098)
   Rate reduction bonds matured
(141)
(141)
   Energy recovery bonds matured
(14)
-
   Common stock dividends paid
(220)
-
   Preferred dividends paid
(8)
(88)
   Preferred stock with mandatory redemption provisions redeemed
(122)
(11)
   Common stock repurchased
(960)
-
Net cash used in financing activities
(794)
(446)
Net change in cash and cash equivalents
357
(2,426)
Cash and cash equivalents at January 1
783
2,979
Cash and cash equivalents at June 30
$
1,140
$
553
Supplemental disclosures of cash flow information
   Cash received for:
      Reorganization interest income
$
-
$
11
   Cash paid for:
      Interest (net of amounts capitalized)
204
315
      Income taxes paid, net
237
-
      Reorganization professional fees and expenses
-
17
Supplemental disclosures of noncash investing and financing activities
      Equity contribution for settlement of POR payable
$
-
$
(128)
      Transfer of liabilities and other payables subject to compromise
         to operating assets and liabilities
-
(2,877)
      Transfer of disputed claims and customer refunds and interest payable to          accounts payable - regulatory balancing accounts
(378)
-
See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

PG&E Corporation, incorporated in California in 1995, is ~~an energy-based~~a holding company ~~that~~whose primary purpose is to hold interests in energy based businesses. The company conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility, which was incorporated in California in 1905, engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity 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. ~~The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation.~~

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 itconsolidation is ~~subject to a majority of the risk of loss or gain.~~required by applicable accounting standards. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying interim unaudited Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation ~~S-X. Accordingly, they may~~S-X promulgated by the Securities and Exchange Commission, or SEC, and do not contain all of the information and footnotes required by GAAP and the SEC for ~~complete~~annual financial statements. Both PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets at December 31, 2004, were derived from the audited Consolidated Balance Sheets included in their ~~combined 2004 Annual~~joint Current Report on Form ~~10-K,~~8-K dated October 28, 2005, as amended on October 31, 2005, or ~~Annual Report, filed with~~ the ~~Securities~~2004 Financial Report.

The accounting policies used by PG&E Corporation and ~~Exchange~~the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission, or ~~SEC.~~CPUC, and the Federal Energy Regulatory Commission, or FERC.

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 (including delayed billings), disputed claims, asset retirement obligations, allowance for doubtful accounts receivable, environmental remediation liabilities, pension liabilities, mark-to-market accounting under Statement of Financial Accounting Standards, or SFAS, No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, or SFAS No. 133, income tax related liabilities, litigation, and the Utility's review fo r impairment of long-lived assets and certain identifiable intangibles to be held and used whenever events or changes in circumstances indicate that the carrying amount of its assets might not be recoverable. As these estimates and assumptions involve judgments based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict, actual results could differ materially from these estimates and assumptions. A change in management's estimates or assumptions could have a material impact on PG&E Corporation's and the Utility's financial condition and results of operations during the period in which such change occurred. PG&E Corporation's and the Utility's Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition and results of operations for the periods presented.

During the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, PG&E Corporation's and the Utility's Consolidated Financial Statements were presented in accordance with the American Institute of Certified Public Accountants' Statement of Position 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," or SOP 90-7. Under SOP 90-7, professional fees and expenses directly related to the Utility's Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings were reported separately as reorganization items. The Utility discontinued the application of SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004 when the Utility's plan of reorganization under Chapter 11 became effective, or the Effective Date. As discussed below, in Note 2, the U.S. Bankruptcy Court for the Northern District of California, which oversaw the Utility's Chapter 11 proceeding, retains jurisdiction, among other things, to resolve the remaining disputed claims made in the Utility's Chapter 11 proceeding.

This quarterly report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their ~~combined~~ 2004 ~~Annual~~Financial Report.

Earnings Per Common Share

Earnings per common share 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 ~~shareholders~~shares and participating securities. PG&E Corporation's $280 million of 9.50% Convertible Subordinated Notes due 2010, or Convertible Subordinated Notes, are entitled to receive (non-cumulative) dividend payments ~~without~~prior to exercising the conversion option and meet the criteria of a participating security. The Convertible Subordinated Notes are convertible at the option of the holders into 18,558,655 common shares. All PG&E Corporation's participating securities participate on a 1:1 basis in dividends with common shareholders.

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

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

	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended

(in millions, except per share amounts)	June 30,				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Net income	$	267	$	372	$	485	$	3,405
Net Income									$	252	$	228	$	737	$	3,633
Less: distributed earnings to common shareholders		112		-		223		-		111		-		334		-

Undistributed earnings		155		372		262		3,405		141		228		403		3,633
Less: Undistributed earnings from discontinued operations										13		-		13		-

Undistributed earnings from continuing operations									$	128	$	228	$	390	$	3,633



Common shareholders earnings
Basic
Distributed earnings to common shareholders	$	112	$	-	$	223	$	-	$	111	$	-	$	334	$	-
Undistributed earnings allocated to common shareholders		147		355		249		3,249
Undistributed earnings allocated to common shareholders - continuing operations										122		218		371		3,467
Undistributed earnings allocated to common shareholders - discontinued operations										12		-		12		-

Total common shareholders earnings, basic	$	259	$	355	$	472	$	3,249	$	245	$	218	$	717	$	3,467



Diluted
Distributed earnings to common shareholders	$	112	$	-	$	223	$	-	$	111	$	-	$	334	$	-
Undistributed earnings allocated to common shareholders		148		356		250		3,252
Undistributed earnings allocated to common shareholders - continuing operations										122		218		371		3,471
Undistributed earnings allocated to common shareholders - discontinued operations										12		-		12		-

Total common shareholders earnings, diluted	$	260	$	356	$	473	$	3,252	$	245	$	218	$	717	$	3,471



Weighted average common shares outstanding, basic		370		397	379		395			372		399	376		397
9.50% Convertible Subordinated Notes		19		19	19		19			19		19	19		19

Weighted average common shares outstanding and participating securities, basic		389		416	398		414			391		418	395		416

Weighted average common shares outstanding, basic		370		397	379		395			372		399	376		397
Employee stock compensation, restricted stock, accelerated share repurchase agreement and PG&E Corporation shares held by grantor trusts		5		7	5		7
Employee stock-based compensation										4		7	4		6
PG&E Corporation warrants		-		2	-		3			-		2	-		3

Rounding		(1)		-	(1)		-

Weighted average common shares outstanding, diluted		374		406	383		405			376		408	380		406
9.50% Convertible Subordinated Notes		19		19	19		19			19		19	19		19

Weighted average common shares outstanding and participating securities, diluted		393		425	402		424			395		427	399		425

Net earnings per common share, basic
Distributed earnings, basic	$	0.30	$	-	$	0.59	$	-	$	0.30	$	-	$	0.89	$	-
Undistributed earnings, basic		0.40		0.89		0.66		8.22
Undistributed earnings - continuing operations, basic										0.33		0.55		0.99		8.73
Undistributed earnings - discontinued operations, basic										0.03		-		0.03		-

Total	$	0.70	$	0.89	$	1.25	$	8.22	$	0.66	$	0.55	$	1.91	$	8.73

Net earnings per common share, diluted
Distributed earnings, diluted	$	0.30	$	-	$	0.58	$	-	$	0.30	$	-	$	0.88	$	-
Undistributed earnings, diluted		0.40		0.88		0.65		8.03
Undistributed earnings - continuing operations, diluted										0.32		0.53		0.98		8.55
Undistributed earnings - discontinued operations, diluted										0.03		-		0.03		-

Total	$	0.70	$	0.88	$	1.23	$	8.03	$	0.65	$	0.53	$	1.89	$	8.55

The following options to purchase PG&E Corporation common shares were outstanding, but not included in the computation of diluted ~~earnings per share~~EPS because the option exercise prices were greater than the average market price: ~~six~~nine months ended ~~June~~September 30, 2005 ~~-- 6,500, six~~- 23,000, nine months ended ~~June~~September 30, 2004 ~~-- 7,874,615,~~- 8,045,805, three months ended ~~June~~September 30, 2005 ~~-- 6,500,~~- 23,000, and three months ended ~~June~~September 30, 2004 ~~-- 8,235,055.~~- 7,705,881.

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

Consolidation of Variable Interest Entities

An entity is a variable interest entity, or VIE, if it does not have sufficient equity investment at risk, or if the holders of the entity's equity instruments lack the essential characteristics of a controlling financial interest. The Financial Accounting Standards ~~Board,~~Board's, or ~~FASB,~~FASB's, Interpretation No. 46, ''Consolidation of Variable Interest Entities,'' or FIN 46R, requires that the company that is subject to a majority of the risk of loss from a VIE's activities, or is entitled to receive a majority of the entity's residual returns, or both, consolidate the VIE. A company that consolidates a VIE is called the primary beneficiary.

~~PG&E Corporation and the Utility adopted FIN 46R on January 1, 2004. The adoption of FIN 46R did not have an impact on net income.~~

Low-Income Housing Partnerships

The Utility invests in low-income housing partnerships, or LIHPs. The entities were formed to invest in low-income housing projects sponsored by non-profit organizations in the state of California. The Utility is the primary beneficiary of one LIHP, resulting in its consolidation and an increase in total assets and total liabilities of $10 million in PG&E Corporation's and the Utility's Consolidated Balance Sheets. The consolidated LIHP has issued debt in the amount of $4$2 million, which is secured by assets of the partnership, totaling $25 million, and the Utility's commitment to make capital infusions of approximately $9$8 million over the next ~~five~~three years.

The Utility is not considered to be the primary beneficiary of any other LIHPs. The maximum exposure to loss from its investment in unconsolidated LIHPs is the Utility's investment of $4 million at ~~June~~September 30, 2005.

Power Purchase Agreements

The nature of power purchase agreements is such that the Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a VIE owning one plant that sells substantially all of its output to the Utility, and the contract price for power is correlated with the plant's variable costs of production.counterparty. The Utility has determined that none of its current power purchase agreements represent significant variable interests. The FASB added a project to its agenda in March 2005 to review how companies determine whether an arrangement is a variable interest. Their findings could impact how the determination is applied to the Utility's power purchase agreements in the future.

~~Adoption of~~ New Accounting Policies

Accounting and ~~Summary~~Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of ~~Significant Accounting Policies~~

2003

In May 2004, FASB issued Staff Position SFAS No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," or FSP 106-2. FSP 106-2 provides guidance on the accounting, disclosure, effective date, and transition requirements related to the Medicare Prescription Drug Act. FSP 106-2 was effective and adopted for the third quarter of 2004. The ~~accounting policies used by PG&E Corporation~~Utility's postretirement medical plan, or the Plan, did not qualify for the federal subsidy under the preliminary regulations. Subsequently on January 21, 2005, the U.S. Department of Health and Human Services issued the ~~Utility include those necessary for rate-regulated enterprises, which reflect~~final regulations on prescription drug benefits. The final regulations did not have a material impact on the ~~ratemaking policies~~Condensed Consolidated Financial Statements. The receipt of the ~~California Public Utilities Commission, or CPUC, and the Federal Energy Regulatory Commission, or FERC.~~federal subsidy commences in January 2006.

Accounting Requirements Related to the Tax Deduction ~~provided~~Provided by the American Jobs Creation Act of 2004

In December 2004, FASB issued Staff Position FAS No. 109-1, "Application of FASB Statement No. 109, ~~' Accounting~~'Accounting for Income Taxes,' to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004," or FSP 109-1. FSP 109-1 indicates that the tax deduction on qualified production activities should be accounted for as a special deduction rather than as a rate reduction. Any benefit from the deduction on qualified production activities is to be reported during the year in which the deduction is claimed. FSP 109-1 was effective upon issuance. The adoption of FSP 109-1 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Accounting Pronouncements Issued But Not Yet Adopted

The following new accounting standards were issued, but have not yet been adopted by PG&E Corporation and the Utility as of September 30, 2005:

Share-Based Payment Transactions

In December 2004, the FASB issued Statement of Financial Accounting Standards, or SFAS, No. 123 (revised December 2004), "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R requires that the cost of all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such costs. In accordance with SFAS No. 123R, compensation expense for awards that vest should be measured over the requisite service period.

PG&E Corporation and the Utility are currently expensing share-based awards over the stated vesting period regardless of terms that accelerate vesting upon retirement. Compensation expense for awards granted subsequent to the adoption of SFAS 123R will be recognized over the shorter of 1) the stated vesting period, or 2) the period from the date of grant through the date the employee is no longer required to provide service to vest.

On April 14, 2005, the SEC amended the compliance date and allowed public companies with calendar year-ends to adopt SFAS No. 123R in the first quarter of 2006. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 123R on their Consolidated Financial Statements.

Conditional Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143," or FIN 47. FIN 47 clarifies that a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 will be effective for the fourth quarter of 2005. PG&E Corporation and the Utility are currently evaluating the impact of FIN 47 on their Consolidated Financial Statements.

Accounting Changes and Error Corrections

In May 2005, the FASB issued FASB Statement No. 154, "Accounting Changes and Error Corrections Disclosure," or SFAS No. 154. SFAS No. 154 replaces Accounting Principles Board, or APB, Opinion No. 20, "Accounting Changes, " or APB No. 20, and FASB Statement No. 3, "Reporting Accounting Changes in Interim Financial Statements," or SFAS No. 3. SFAS No. 154 requires retrospective application to prior periods' financial statements of changes in accounting principle unless it is impracticable. This Statement applies to all voluntary changes in accounting principle. SFAS No. 154 is effective for the first quarter of 2006.

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. ~~These services~~Services provided directly by the Utility to PG&E Corporation are priced either at the fully loaded cost (i.e., direct costs and allocations of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services. Services provided directly by PG&E Corporation to the Utility are priced either at the fully loaded cost or at the lower of fully loaded cost or fair market value, depending on the nature of the services. PG&E Corporation also allocates certain other corporate administrative and general costs, at cost, to the Utility and other subsidiaries using ~~agreed~~agre ed upon allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets, ~~and other cost allocation methodologies.~~etc. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or ~~GT NW,~~GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. GTNW is no longer a related party after the cancellation of PG&E Corporation's equity interest in National Energy & Gas Transmission, Inc., or NEGT, on the effective date of its plan of reorganization, October 29, 2004. Through July 7, 2003, all significant intercompany transactions with NEGT and its subsidiaries were eliminated in consolidation; therefore, no profit or loss resulted from these transactions. Beginning July 8, 2003, the Utility's transactions with NEGT are no longer eliminated in consolidation. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

																		Three Months Ended					Nine Months Ended				Receivable (Payable) Balance Outstanding at
			Three Months Ended					Six Months Ended					Receivable (Payable) Balance Outstanding at
(in millions)	(in millions)																September 30,					September 30,					September 30,		December 31,
		June 30,					June 30,					June 30,			December 31,

		2005			2004		2005			2004		2005			2004		2005			2004		2005			2004		2005		2004

Utility revenues from:
Administrative services provided to PG&E Corporation		$		1	$	2	$		2	$	4	$		1	$	1	$		1	$	2	$		4	$	6	$	1	$	1
Utility expenses from:
Administrative services received from PG&E Corporation		$		24	$	20	$		49	$	42	$		(28)	$	(20)	$		21	$	23	$		70	$	65	$	(22)	$	(20)
Interest accrued on pre-petition liabilities due to PG&E Corporation		-			-		-			2		-			-
Interest accrued on pre-petition liability due to PG&E Corporation																	-			-		-			2		-		-
Natural gas transportation services received from GTNW		-			14		-			29		-			-		-			14		-			43		-		-

Regulation and Statement of Financial Accounting Standards No. 71

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71,"Accounting for the Effects of Certain Types of Regulation," as amended, or SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, among others. SFAS No. 71 applies to all of the Utility's operations except for the operations of a natural gas pipeline.

SFAS No. 71 provides for recording regulatory assets and liabilities when certain conditions are met. Regulatory assets represent the capitalization of incurred costs that would otherwise be charged to expense when it is probable that the incurred costs will be included for ratemaking purposes in the future. Amortization of regulatory assets is charged to expense during the period that the costs are reflected in regulated revenues. Regulatory liabilities represent rate actions of a regulator that will result in amounts that are to be credited to customers through the ratemaking process.

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 the Utility's competitive position, the related regulatory assets and liabilities are written off.

Regulatory Assets

Regulatory assets ~~comprise~~are comprised of the following:

	Balance At				Balance At

(in millions)	June 30,		December 31,		September 30,		December 31,
	2005		2004		2005		2004

Settlement Regulatory Asset	$	1,239	$	3,188
Settlement regulatory asset					$	1,190	$	3,188
Energy recovery bond regulatory asset	1,806		-		1,734		-
Utility retained generation regulatory assets	1,140		1,181		1,120		1,181
Rate reduction bond assets	613		741		527		741
Regulatory assets for deferred income tax	510		490		525		490
Unamortized loss, net of gain, on reacquired debt	334		345		328		345
Environmental compliance costs	242		192		244		192
Regulatory assets associated with plan of reorganization	167		182		165		182
Post-transition period contract termination costs	137		142		134		142
Other, net	48		65		33		65

Total regulatory assets	$	6,236	$	6,526	$	6,000	$	6,526

In light of the satisfaction of various conditions to the implementation of the Utility's plan of reorganization, the accounting probability standard required to be met under SFAS No. 71 in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described in Note 2) was met as of March 31, 2004. Therefore, the Utility recorded the $3.7 billion, pre-tax ($2.2 billion, after-tax), regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $1.2 billion, pre-tax ($0.7 billion, after-tax), for the Utility retained generation regulatory assets in the first quarter of 2004 (see Note 2 for further discussion). As of December 31, 2004, the Utility had recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $309 million ($183 million, after-tax) for supplier settlements and approximately $233 million ($138 million, after-tax ) for amortization of the Settlement Regulatory Asset. For the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility recorded amortization of the Settlement Regulatory Asset of approximately ~~$76~~$125 million ($4575 million, after-tax).

On February 10, 2005, PG&E Energy Recovery Funding, LLC, or PERF, a limited liability company wholly owned and consolidated by the Utility (but legally separate from the Utility), issued the first series of energy recovery bonds, or ERBs, for approximately $1.9 billion to refinance the remaining after-tax balance of the Settlement Regulatory Asset. As a result of the issuance of ERBs, the pre-tax Settlement Regulatory Asset was reduced to approximately $1.3 billion (representing the deferred tax liability associated with the collection of the revenues for the ERBs) and the Utility has recorded a regulatory asset related to the ERBs of approximately $1.9 billion. For the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility recorded amortization of the energy recovery bond regulatory asset of approximately ~~$68~~$139 million.

The Utility's rate reduction bond asset represents electric industry restructuring costs that the Utility expects to collect over the life of the bonds. The regulatory assets for deferred income tax represent deferred income tax benefits that have already been 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 benefits to customers. The "flow through" method ignores the effect of deferred taxes on rates. The regulatory asset related to unamortized loss, net of gain, on reacquired debt represents costs on debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. Environmental compliance costs are costs incurred by the Utility for environmental remediation. Regulatory assets associated with the plan of reorganization include costs incurred in financing the Utility's exit from Chapter 11 and costs to oversee the environmental enhancement of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the ~~Utili ty's~~Utility's plan of reorganization. The post-transition period contract termination costs represent amounts the Utility incurred in terminating a 30-year power purchase agreement. These regulatory assets are recoverable from customers in future rates.

In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the only regulatory asset on which the Utility earns a return are the regulatory assets relating to the Utility's retained generation and unamortized loss, net of gain on reacquired debt.

The Settlement Agreement authorizes the Utility to earn an 11.22% rate of return on equity on its rate base, including the after-tax amount of the Settlement Regulatory Asset and the retained generation regulatory assets. Since the refinancing of the remaining unamortized after-tax balance of the Settlement Regulatory Asset on February 10, 2005 through the issuance of the first series of ERBs, the Utility no longer earns this 11.22% rate of return on the Settlement Regulatory Asset as it is no longer a part of rate base.

Regulatory Liabilities

Regulatory liabilities ~~comprise~~are comprised of the following:

	Balance At				Balance At

(in millions)	June 30,		December 31,		September 30,		December 31,
	2005		2004		2005		2004

Cost of removal obligation	$	2,059	$	1,990	$	2,100	$	1,990
Asset retirement costs	692		700		708		700
Employee benefit plans	592		687		547		687
Public purpose programs	192		191		194		191
Rate reduction bonds	175		182		167		182
Other	87		285		219		285

Total regulatory liabilities	$	3,797	$	4,035	$	3,935	$	4,035

The Utility's regulatory liabilities related to costs of removal represent revenues collected for asset removal costs that the Utility expects to incur in the future. The regulatory liability associated with asset retirement costs represents timing differences between the recognition of nuclear and fossil decommissioning obligations in accordance with GAAP applicable to non-regulated entities under SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143, and the amounts recognized for ratemaking purposes. The Utility's regulatory liabilities related to employee benefit plan expenses represent the cumulative differences between expenses recognized for financial accounting purposes and expenses recognized for ratemaking purposes. These balances will be charged against expense to the extent that future financial accounting expenses exceed amounts recoverable for regulatory purposes. The Utility' s regulatory liability related to public purpose programs represents revenues designated for public purpose program costs that are expected to be incurred in the future. The Utility's regulatory liability for rate reduction bonds represents the deferral of over-collected revenue associated with the rate reduction bonds that the Utility expects to return to customers in the future.

Regulatory Balancing Accounts

Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and revenues. 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 regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility's customers through authorized rate adjustments.

The Utility expects to collect from or refund to its customers the balances included in current balancing accounts receivable and payable within the next twelve months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next twelve months are included in non-current regulatory assets and liabilities.

As a result of settlements that the Utility has entered into with various power suppliers (see further discussion in Note 7 of the Notes to the Condensed Consolidated Financial Statements) and other activities related to the ERBs, the balance in the Energy Recovery Bond Balancing Account, or the ERBBA, which tracks recovery of customer costs and benefits related to the ERBs, is a liability of approximately ~~$365~~$364 million as of ~~June~~September 30, 2005.

Stock-Based Compensation

PG&E Corporation and the Utility apply the intrinsic-value method prescribed in ~~Accounting Principles Board~~APB Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for employee stock-based compensation, as allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," or SFAS No. 123, as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. 123," or SFAS No. 148. Under the intrinsic-value method, PG&E Corporation and the Utility do not recognize any compensation expense for stock options, as the exercise price is equal to the fair market value of a share of PG&E Corporation common stock at the time the options are granted.

The tables below show the effect on net income and earnings per common share for PG&E Corporation and the Utility had it elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three and ~~six~~nine months ended ~~June~~September 30, 2005 and 2004:

(in millions, except per share amounts)	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
	June 30,				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Net earnings:
As reported	$	267	$	372	$	485	$	3,405	$	252	$	228	$	737	$	3,633
Deduct: Total stock-based employee compensation
expense determined under the fair value based method
for all awards, net of related tax effects		3		4		6		9		3		3		10		10

Pro forma	$	264	$	368	$	479	$	3,396	$	249	$	225	$	727	$	3,623

Basic earnings per common share:
As reported	$	0.70	$	0.89	$	1.25	$	8.22	$	0.66	$	0.55	$	1.91	$	8.73
Pro forma		0.69		0.88		1.23		8.20		0.65		0.54		1.88		8.71

Diluted earnings per common share:
As reported		0.70		0.88		1.23		8.03		0.65		0.53		1.89		8.55
Pro forma		0.69		0.87		1.22		8.05		0.64		0.53		1.86		8.57

If compensation expense had been recognized using the fair value-based method under SFAS No. 123, the Utility's pro forma consolidated earnings would have been as follows:

(in millions)	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
	June 30,				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Net earnings:
As reported	$	272	$	408	$	491	$	3,474	$	244	$	244	$	735	$	3,718
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards, net of related tax effects		2	2		4		4
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects										2	2		6		6

Pro forma	$	270	$	406	$	487	$	3,470	$	242	$	242	$	729	$	3,712

Restricted Stock

At ~~June~~September 30, 2005, a total of ~~2,418,760~~2,424,270 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which ~~1,597,920~~1,603,430 shares were awarded to Utility employees. PG&E Corporation awarded ~~329,840~~335,350 shares of restricted common stock during the ~~six~~nine months ended ~~June~~September 30, 2005, of which ~~241,790~~247,300 shares were awarded to Utility employees.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. Dividends payable with respect to restricted shares are not paid until the restrictions lapse.

For restricted stock granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date. The compensation expense recognized for these shares is variable, and changes with the common stock's market price. As the performance criteria for 2004 were not met, 91,017 shares of restricted stock were forfeited.

Restricted stock awards after 2003 do not contain performance criteria. The restrictions lapse ratably over four years, from the date of award, subject to forfeiture if employment is terminated before the annual vesting date. All restricted shares are also subject to accelerated vesting in certain circumstances, including death, disability, and change in control.

Compensation expense associated with all the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the issuance of restricted shares, as reflected on PG&E Corporation's Condensed Consolidated Statements of Income, was approximately $3$2 million for the three months ended ~~June~~September 30, 2005 and approximately $3 million for the three months ended ~~June~~September 30, 2004, of which approximately $2$1 million for the three months ended ~~June~~September 30, 2005 and approximately $2 million for the three months ended ~~June~~September 30, 2004 was recognized by the Utility. The comparable amount for the ~~six~~nine months ended ~~June~~September 30, 2005 was approximately $6$8 million and approximately $6 million for the ~~six~~nine months ended ~~June~~September 30, 2004, of which approximately $4$6 million for the ~~six~~nine months ended ~~June~~September 30, 2005 and approximately $4 million for the ~~six~~nine months ended ~~June~~September 30, ~~200 4~~2004 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the issuance of restricted shares, as reflected as a reduction in common shareholders' equity on PG&E Corporation's Condensed Consolidated Balance Sheets was approximately ~~$28~~$26 million at ~~June~~September 30, 2005 and approximately $26 million at December 31, 2004.

Comprehensive Income (Loss)

PG&E Corporation's and the Utility's comprehensive income (loss) consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133, and the effects of the remeasurement of the Utility's defined benefit pension plan.

(in millions)	PG&E Corporation				Utility				PG&E Corporation				Utility

	2005		2004		2005		2004		2005		2004		2005		2004

Three months ended June 30
Three months ended September 30
Comprehensive income	$	267	$	372	$	272	$	408	$	252	$	228	$	244	$	244

Six months ended June 30
Nine months ended September 30
Net income available for common stock	$	485	$	3,405	$	491	$	3,474	$	737	$	3,633	$	735	$	3,718
Net gain in other comprehensive income from current period hedging transactions and price changes in accordance with SFAS No. 133 (net of income tax expense of $2 million in 2004)		-		3		-		3		-		3		-		3
Minimum pension liability adjustment (net of income tax benefit of $2 million in 2005)		(1)		-		(2)		-
Minimum pension liability adjustment (net of income tax benefit of $1 million in 2005)										(1)		-		(2)		-
Other		-		1		-		-		-		1		-		-

Comprehensive income (loss)	$	484	$	3,409	$	489	$	3,477
Comprehensive income									$	736	$	3,637	$	733	$	3,721

PG&E Corporation and the Utility did not have any other comprehensive income activity for the three months ended ~~June~~September 30, 2005 and ~~June~~September 30, 2004.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that results from transactions and other economic events, other than transactions with shareholders. The following table sets forth the changes in each component of accumulated other comprehensive income (loss):

(in millions)	Hedging Transactions in Accordance with SFAS No. 133			Foreign Currency Translation Adjustment			Minimum Pension Liability Adjustment		Other		Accumulated Other Comprehensive Income (Loss)			Hedging Transactions in Accordance with SFAS No. 133			Foreign Currency Translation Adjustment			Minimum Pension Liability Adjustment		Other		Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2003	$		(81)	$		-	$	(4)	$	-	$		(85)	$		(81)	$		-	$	(4)	$	-	$		(85)
Period change in:
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133	3			-			-		-		3			3			-			-		-		3
Other	-			-			-		1		1			-			-			-		1		1

Balance at June 30, 2004			(78)		-			(4)	1				(81)
Balance at September 30, 2004																(78)		-			(4)	1				(81)

Balance at December 31, 2004	(1)						(4)		1		(4)			(1)			-			(4)		1		(4)
Period change in:
Minimum pension liability adjustment			-		-			(1)	-				(1)			-		-			(1)	-				(1)
Other			1		-			-	(1)				-			1		-			-	(1)				-

Balance at June 30, 2005		$	-	$	-		$	(5)	$	-		$	(5)
Balance at September 30, 2005															$	-	$	-		$	(5)	$	-		$	(5)

Accumulated other comprehensive income (loss) included losses related to discontinued operations of approximately $77 million at December 31, 2003. During the fourth quarter of 2004, the remaining losses of approximately $77 million included in accumulated other comprehensive income (loss) were recognized in connection with PG&E Corporation's elimination of its equity interest in NEGT. Excluding the activity related to NEGT, there was no material difference between PG&E Corporation's and the Utility's accumulated other comprehensive income (loss).

There were no changes in PG&E Corporation's or the Utility's accumulated other comprehensive income (loss) components for the three months ended ~~June~~September 30, 2005 and ~~June~~September 30, 2004.

Pension and Other Postretirement Benefits

PG&E Corporation and ~~its subsidiaries~~the Utility provide a non-contributory defined benefit pension ~~plans~~plan for certain of their employees and retirees (referred to collectively as pension benefits), contributory postretirement medical plans for certain of their employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for certain of their employees and retirees (referred to collectively as other benefits). PG&E Corporation and ~~its subsidiaries~~the Utility use a December 31 measurement date for all of ~~its~~their plans and use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee, to determine the fair value of the plan assets.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three and ~~six month~~nine-month periods ended ~~June~~September 30, 2005 and 2004 are as follows:

PG&E Corporation

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

	2005		2004		2005			2004		2005		2004		2005			2004

Service cost for benefits earned	$	56	$	47	$	9	$		9	$	53	$	49	$	8	$		8
Interest cost	125		118		20		23			125		120		18		21
Expected return on plan assets	(151)		(142)		(21)		(19)			(151)		(140)		(21)		(19)
Amortization of transition obligation	-		2		6		6			-		1		6		6
Amortization of prior service cost	14		13		3		3			14		14		3		3
Amortization of unrecognized loss	6		-		-		-			7		2		-		-

Net periodic benefit cost	$	50	$	38	$	17	$		22	$	48	$	46	$	14	$		19

(in millions)	Pension Benefits Six Months Ended June 30,				Other Benefits Six Months Ended June 30,					Pension Benefits Nine Months Ended September 30,				Other Benefits Nine Months Ended September 30,

	2005		2004		2005			2004		2005		2004		2005			2004

Service cost for benefits earned	$	112	$	93	$	17	$		18	$	161	$	146	$	23	$		24
Interest cost	249		236		40		44			374		361		55		63
Expected return on plan assets	(301)		(282)		(43)		(38)			(451)		(422)		(64)		(57)
Amortization of transition obligation	-		3		13		13			-		4		19		19
Amortization of prior service cost	27		26		6		7			41		41		9		9
Amortization of unrecognized loss	13		-		-		-			21		6		(1)		-
Settlement loss										-		1		-		-

Net periodic benefit cost	$	100	$	76	$	33	$		44	$	146	$	137	$	41	$		58

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

Under SFAS No. 71, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach.

PG&E Corporation and the Utility ~~expect to contribute~~contributed approximately $20 million for Pension Benefits to fund voluntary retirement program obligations during the third quarter 2005 and expect to contribute approximately ~~$68~~$57 million for Other Benefits induring the fourth quarter 2005. These anticipated contributions are consistent with PG&E Corporation's and the Utility's funding policy, which is to contribute amounts that are tax deductible, consistent with applicable regulatory decisions and sufficient to meet minimum funding requirements. None of these benefit plans are subject to a minimum funding requirement in 2005. The Utility's pension benefit plans met all the funding requirements under the Employee Retirement Income Security Act of 1974, as amended.

~~Accounting Pronouncements Issued But Not Yet Adopted~~

~~Share-Based Payment Transactions~~

In December 2004, the FASB issued Statement No. 123 (revised December 2004), "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such a cost. On April 14, 2005, the SEC amended the compliance date and allowed public companies with calendar year-ends to adopt SFAS No. 123R in the first quarter of 2006. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 123R on their Consolidated Financial Statements.

~~Conditional Asset Retirement Obligations~~

In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," or FIN 47. FIN 47 clarifies that a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 will be effective for the fourth quarter of 2005. PG&E Corporation and the Utility are currently evaluating the impact of FIN 47 on their Consolidated Financial Statements.

~~Accounting Changes and Error Corrections~~

In May 2005, the FASB issued FASB Statement No. 154, "Accounting Changes and Error Corrections Disclosure," or SFAS No. 154. SFAS No. 154 replaces APB Opinion No. 20, "Accounting Changes, " or APB No. 20, and FASB Statement No. 3, "Reporting Accounting Changes in Interim Financial Statements," or SFAS No. 3. SFAS No. 154 requires retrospective application to prior periods' financial statements of changes in accounting principle unless it is impracticable. This Statement applies to all voluntary changes in accounting principle. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS No. 154 is effective for the first quarter of 2006. PG&E Corporation and the Utility are currently evaluating the impacts of SFAS No. 154 on their Consolida ted Financial Statements.

Restricted Cash Classification on Statement of Cash Flows

PG&E Corporation and the Utility have changed the classification of changes in certain restricted cash balances in their Condensed Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2005, to present such changes as an investing activity. These changes in restricted cash balances were previously presented as an operating activity. In the accompanying Condensed Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2004, PG&E Corporation and the Utility have reclassified changes in restricted cash balances to be consistent with the 2005 presentation, which resulted in a ~~$93~~$150 million increase in investing cash flows and a corresponding decrease in operating cash flows from the amounts previously reported by both PG&E Corporation and the Utility.

NOTE 2: THE UTILITY'S EMERGENCE FROM CHAPTER 11

As a result of the California energy crisis, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 on April 6, 2001. The Utility retained control of its assets and was authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding. PG&E Corporation and the subsidiaries of the Utility, including PG&E Funding LLC, ~~(which~~which issued rate reduction ~~bonds)~~bonds and PG&E Holdings LLC, ~~(which~~which holds stock of the ~~Utility),~~Utility, were not included in the Utility's Chapter 11 proceeding.

On April 12, 2004, the Utility emerged from Chapter 11 when its plan of reorganization became effective, or the Effective Date. The plan of reorganization incorporated the terms of the Settlement Agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the plan of reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

In light of the satisfaction of various conditions to the implementation of the plan of reorganization, the accounting probability standard required to be met under SFAS No. 71, in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement was met as of March 31, 2004. Therefore, the Utility recorded the $2.2 billion, after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility retained generation regulatory assets. Refer to the 2004 ~~Annual~~Financial Report for further discussion of the Settlement Agreement. On February 10, 2005, the Utility refinanced the remaining unamortized after-tax portion of the Settlement Regulatory Asset as discussed in Note 4.

As of ~~June~~September 30, 2005, the Utility had accrued approximately $1.3 billion for remaining net disputed claims, consisting of approximately $1.8 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator, or ISO, and the Power Exchange, or the PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion. At December 31, 2004, the Utility had accrued approximately $2.1 billion for remaining ~~net~~ disputed claims. Since December 31, 2004, the Utility has made payments to creditors of approximately $6 million in settlement of disputed claims and, as a result of settlements reached with creditors, has reduced the disputed claims balance by approximately ~~$325~~$295 million. The Utility held ~~$1.4~~$1.3 billion in escrow for the payment of the remaining disputed claims as of ~~June~~September 30, 2005. Upon resolution of these claims and under the terms of the Settlement ~~A greement,~~Agreement, any refunds, claims offsets or other credits that the Utility receives from energy suppliers will be returned to customers. With the approval of the bankruptcy court, the Utility has withdrawn certain amounts from the escrow in connection with settlements with certain ISO and PX sellers.

On June 13, 2005, the California Court of Appeal summarily denied the petitions for review of the CPUC's order approving the Settlement Agreement and order denying rehearing of its approval order that had been filed by the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet. CCSF and Aglet have not appealed the appellate court's denial of their petitions and the time period within which an appeal could be filed has elapsed.

~~In addition, two~~Two former CPUC commissioners who did not vote to approve the Settlement Agreement filed an appeal of the bankruptcy court's confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed their appeal. The former commissioners have appealed the District Court's order ~~with~~to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Briefing is complete, and the Ninth Circuit is likely to schedule oral arguments on the appeal by the end of the year. On April 12, 2005, the District Court entered an order dismissing a second appeal of the confirmation order that had been filed by the City of Palo Alto, but which the City of Palo Alto subsequently had agreed to dismiss voluntarily.

~~PG&E Corporation and the Utility believe the former commissioners' appeal of the confirmation order is without merit and will be rejected.~~ If the bankruptcy court's confirmation order ~~or the Settlement Agreement~~ is overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected. PG&E Corporation and the Utility believe the former commis sioners' appeal of the confirmation order is without merit and will be rejected.

NOTE 3: DEBT

Long-Term Debt

The following table summarizes PG&E Corporation's and the Utility's long-term ~~debt that matures in one year or more from the date of issuance:~~debt:

	Balance At					Balance At

(in millions)	June 30, 2005		December 31, 2004			September 30, 2005		December 31, 2004

PG&E Corporation
Convertible subordinated notes, 9.50%, due 2010	$	280	$		280	$	280	$		280
Other long-term debt	-		1			-		1
Less: current portion	-		(1)			-		(1)

		280			280		280			280

Utility
First mortgage bonds/senior notes
Floating rate and 3.60% to 6.05% bonds, due 2006-2034	5,300		6,200
3.60% to 6.05% bonds, due 2009-2034						5,100		6,200
Unamortized discount, net of premium		(17)			(17)		(17)			(17)

Total first mortgage bonds/senior notes		5,283			6,183		5,083			6,183
Pollution control bond loan agreements, variable rates, due 2026	614		614			614		614
Pollution control bond loan agreement, 5.35%, due 2016	200		200			200		200
Pollution control bond loan agreements, 3.50%, due 2007	345		345
Pollution control bond loan agreements, 3.50%, due 2023						345		345
Pollution control bond loan agreements, variable rates, due 2016-2026	454		-			454		-
Pollution control bond reimbursement obligations, variable rates, due 2005	-		454			-		454
Other	3		4			2		4
Less: current portion	(202)		(757)			(2)		(757)

	6,697		7,043
Long-term debt, net of current portion						6,696		7,043

Total consolidated long-term debt, net of current portion	$	6,977		$	7,323	$	6,976		$	7,323

Other Long Term Debt Guarantees⁽¹⁾
(in millions)
Utility
At June 30, 2005
Facility
Series
Termination Date
Commitment
Outstanding
Pollution control bond bank reimbursement agreements
96 C, E, F,
97 B
April 2010
$
620
$
620
Pollution control bond -- bond insurance reimbursement agreements
96A
December 2016
(2)
200
200
Pollution control bond -- bond insurance reimbursement agreements
2004 A -- D
December 2023
(2)
345
345
Pollution control bond -- bond insurance reimbursement agreements
2005 A -- G
2016 -- 2026
(2)
454
454
$
1,619
$
1,619
(1) Off-balance sheet commitments
(2) Principal and debt service insured by the bond insurance company
Under the pollution control bond loan agreements, the Utility is obligated to pay on the due dates to the trustee for the account of the conduit state agencies, an amount equal to the principal of, premium, if any, and interest on the bonds, which were issued for the benefit of the Utility. In order to enhance the credit ratings of these bonds, the Utility has obtained credit support from banks and insurance companies. These third parties have reimbursement agreements covering the terms of the Utility's debt service repayment amounts. This additional layer of credit support gives bondholders comfort that, in the event that the Utility does not pay debt servicing costs, the banks or insurance companies will step in and pay the debt servicing costs, which is represented in the following table:

Other Long-Term Debt Guarantees⁽¹⁾

(in millions)

Utility				At September 30, 2005

Facility	Series	Termination Date		Commitment			Outstanding

Pollution control bond bank reimbursement agreements	96 C, E, F, 97 B	April 2010		$	620	$	620
Pollution control bond -- bond insurance reimbursement agreements	96A	December 2016	(2)		200		200
Pollution control bond -- bond insurance reimbursement agreements	2004 A -- D	December 2023	(2)		345		345
Pollution control bond -- bond insurance reimbursement agreements	2005 A -- G	2016 -- 2026	(2)		454		454

				$	1,619	$	1,619






(1) Off-balance sheet commitments
(2) Principal and debt service insured by the bond insurance company

PG&E Corporation

Convertible Subordinated Notes

PG&E Corporation currently has outstanding $280 million of ~~9.50%~~ Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,655 shares of common stock of PG&E Corporation, at a conversion price of approximately $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's outstanding common shares. To date, the conversion price has not required adjustment. In addition, holders of the Convertible Subordinated Notes are entitled to receive "pass-through dividends" at the same payout as common stockholders with the number of shares determined by dividing the principal amount of the Convertible Subordinated Notes by the conversion price. OnIn connection with each common stock dividend that was payab le to holders of PG&E Corporation common stock on April 15, July 15 and ~~July~~October 15, 2005, PG&E ~~Corpor ation~~Corporation paid approximately $6 million of ~~"pass-through~~"pass through dividends" to the holders of ~~the~~ Convertible Subordinated Notes. The holders have a one-time right to require PG&E Corporation to repurchase the Convertible Subordinated Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including liquidated damages and unpaid "pass-through dividends," if any).

In accordance with SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and ~~marked-to-market on~~recorded at fair value in PG&E Corporation's Consolidated Financial Statements. Changes in the fair value are recognized in PG&E Corporation's Consolidated Statements of Income as a non-operating expense ~~(in~~or income (included in Other ~~expense,~~income (expense), net)~~, and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets at June 30, 2005.~~. At ~~June~~September 30, 2005 and 2004, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately ~~$91~~$93 million and $70 million, respectively, of which ~~$20~~$21 million and $9 million, respectively, is classified as a current liability (in Current liabilities-Other) and ~~$71~~$72 million and $61 million, respectively, is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in value of the liability was immaterial for the ~~quarter~~quarters ended ~~June~~September 30, 2005 ~~was immaterial. The mark-to-market change was approximately $33 million, pre-tax, for the quart er ended June 30,~~and 2004.

Utility

First Mortgage Bonds/Senior Notes

On March 23, 2004, the Utility closed a public offering of $6.7 billion of first mortgage bonds, or First Mortgage Bonds. The First Mortgage Bonds were offered in multiple tranches consisting of 3.60% First Mortgage Bonds due March 1, 2009 in the principal amount of $600 million, 4.20% First Mortgage Bonds due March 1, 2011 in the principal amount of $500 million, 4.80% First Mortgage Bonds due March 1, 2014 in the principal amount of $1 billion, 6.05% First Mortgage Bonds due March 1, 2034 in the principal amount of $3 billion, and Floating Rate First Mortgage Bonds due April 3, 2006 in the principal amount of $1.6 billion. The Utility received proceeds of $6.7 billion from the offering, net of a discount of $18 million. The interest rate for the Floating Rate First Mortgage Bonds is based on the three-month London Interbank Offered Rate, or LIBOR, plus 0.70%, which resets quarterly. ~~At June 30, 2005, the intere st rate on the~~The Floating Rate Senior ~~Notes (as redesignated below) was 3.82%.~~Not es were subsequently redeemed on July 3, 2005. First Mortgage Bonds in the aggregate amount of $2.5 billion also were used to secure the Utility's obligations under various other debt agreements.

On October 3, 2004, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $500 million. On January 3, 2005, in anticipation of the receipt of ERB proceeds, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $300 million. On February 24, 2005, the Utility used a portion of the ERB proceeds to defease $600 million of Floating Rate First Mortgage Bonds due in 2006. The defeased bonds were redeemed on April 3, 2005. On July 3, 2005, the remaining $200 million of Floating Rate Senior Notes (as redesignated below) were redeemed.

The First Mortgage Bonds were secured by a first lien, subject to permitted exceptions, on substantially all of the Utility's real property and certain tangible personal property related to the Utility's facilities. The lien was released on April 22, 2005, upon satisfaction of various conditions specified in the indenture, including confirmation from Moody's Investors Service, or Moody's, and Standard & Poor's Ratings Service, or S&P, that the Utility's unsecured debt ratings following the release would be at least Baa2 from Moody's and BBB from S&P. On March 3, 2005, Moody's upgraded the rating on the First Mortgage Bonds from Baa2 to Baa1. On April 22, 2005, the Utility and the trustee entered into an amended and restated indenture to eliminate the provisions related to the lien of the mortgage. The First Mortgage Bonds have been redesignated as follows:

First Mortgage Bonds	Redesignated As	Amount	Amount outstanding as of 9/30/2005

3.6% First Mortgage Bonds due 2009	3.6% Senior Notes due 2009	$600 million	$600 million
4.2% First Mortgage Bonds due 2011	4.2% Senior Notes due 2011	$500 million	$500 million
4.8% First Mortgage Bonds due 2014	4.8% Senior Notes due 2014	$1 billion	$1 billion
6.05% First Mortgage Bonds due 2034	6.05% Senior Notes due 2034	$3 billion	$3 billion
Floating Rate First Mortgage Bonds due 2006	Floating Rate Senior Notes due 2006	$200 million

Since the lien has been released there is no collateral securing the First Mortgage Bonds and the bonds, now designated as the Senior Notes as set forth in the table above, have become the Utility's unsecured general obligations rankingpari passu with the Utility's other senior unsecured debt. Under the indenture for the Senior Notes, the Utility has agreed that it will not incur secured debt (except for (1) debt secured by specified liens, and (2) secured debt in an amount not exceeding 10% of the Utility's net tangible assets, as defined in the indenture) unless the Utility provides that the Senior Notes will be equally and ratably secured with the new secured debt.

Pollution Control Bonds

On April 22, 2005, the Utility entered into an amendment to four reimbursement agreements totaling $620 million related to letters of credit that had been issued to support certain pollution control bonds aggregating $614 million issued by the California Pollution Control Financing Authority, or CPCFA, on behalf of the Utility. Interest rates on the $614 million pollution control bonds are variable. At September 30, 2005, interest rates on these loans ranged from 2.77% to 2.88%. In addition to reducing pricing and generally conforming the covenants and events of default to those in the $1 billion working capital facility (described below), the term of the amended agreements has been extended toby five years until April 22, 2010.

On May 24, 2005, the Utility entered into seven loan agreements with the California Infrastructure and Economic Development Bank to issue seven series of tax-exempt pollution control bonds, or PC Bonds Series A-G, totaling $454 million. These series are in auction modes ~~with~~where interest rates are set among investors who submit bids to buy, sell, or hold securities at desired rates. The initial interest rates ~~ranging~~ranged from 2.54% to 3.00%. Four series of the bonds (Series A-D) have auctions every 35 days and three series (Series E-G) have auctions every 7 days. Maturities on the bonds range from 2016 to 2026. At ~~June~~September 30, 2005, interest rates on these loans ranged from ~~1.94%~~2.30% to ~~3.00%~~2.70%. ~~The bonds are insured by Ambac Assurance Corporation.~~

Repayment Schedule

At ~~June~~September 30, 2005, PG&E Corporation's and the Utility's combined aggregate amounts of scheduled repayments of long-term debt, rate reduction bonds, and ERBs as scheduled are reflected in the table below:

(in millions)	2005		2006		2007		2008			2009		Thereafter		Total			2005		2006		2007		2008		2009		Thereafter		Total

Long-term debt:
PG&E Corporation
Average fixed interest rate		-		-		-			-		-		9.50%			9.50%		-		-		-		-		-		9.50%		9.50%
Fixed rate obligations	$	-	$	-	$	-	$		-	$	-	$	280	$		280	$	-	$	-	$	-	$	-	$	-	$	280	$	280
Utility
Average fixed interest rate	-			-	3.50%		-			3.60%		5.56%		5.22%			-			-	-		-		3.60%		5.42%		5.22%
Fixed rate obligations	$	-	$	-	$	345	$		-	$	600	$	4,683	$	5,628		$	-	$	-	$	-	$	-	$	600	$	5,028	$	5,628
Variable interest rate as of June 30, 2005		3.82%		-		-		-			-		2.33%		2.57%
Variable interest rate as of September 30, 2005																		-		-		-		-		-		2.68%		2.68%
Variable rate obligations	$	200	$	-	$	-	$	-		$	-	$	1,068	$	1,268		$	-	$	-	$	-	$	-	$	-	$	1,068	$	1,068
Other		2		1		-		-			-		-		3			2		-		-		-		-		-		2

Total consolidated long-term debt	$	202	$	1	$	345	$		-	$	600	$	6,031	$	7,179		$	2	$	-	$	-	$	-	$	600	$	6,376	$	6,978

Energy Recovery Bonds & Rate Reduction Bonds:	Energy Recovery Bonds & Rate Reduction Bonds:																Energy Recovery Bonds & Rate Reduction Bonds:
Utility
Average fixed interest rate		6.42%		6.44%	6.48%				-		-		-		6.45%			6.42%		6.44%	6.48%			-		-		-		6.46%
Rate reduction bonds	$	149	$	290	$	290	$		-	$	-	$	-	$	729		$	76	$	290	$	290	$	-	$	-	$	-	$	656

Average fixed interest rate		3.32%		3.55%	3.87%				3.87%		4.05%		4.35%		4.03%			3.32%		3.55%	3.87%			3.87%		4.05%		4.35%		4.05%
Energy recovery bonds	$	126	$	221	$	230	$		239	$	248	$	810	$	1,874		$	63	$	221	$	230	$	239	$	248	$	810	$	1,811

Credit Facilities and Short-Term Borrowings

The following table summarizes PG&E Corporation's and the Utility's short-term borrowings and outstanding credit facilities at ~~June~~September 30, 2005:

(in millions)	(in millions)												(in millions)
					At June 30, 2005													At September 30, 2005

Authorized Borrower		Facility	Termination Date		Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Availability		Facility	Termination Date			Facility Limit			Letters of Credit Out-standing		Cash Borrowings		Availability

PG&E Corporation	PG&E Corporation	Senior Credit Facility	December 2009	$	200	(1)	$	-	$	-	$	200	PG&E Corporation	Senior credit facility		December 2009	$	200	(1)	$	-	$	-	$	200
Utility	Utility	Accounts receivable financing	March 2007		650			-		-		650	Utility	Accounts receivable financing		March 2007		650			-		-		650
Utility	Utility	Working capital facility	April 2010		1,000	(2)		139		-		861	Utility	Working capital facility		April 2010		1,000	(2)		52		-		948

Total Credit Facilities	Total Credit Facilities			$	1,850		$	139	$	-	$	1,711	Total Credit Facilities				$	1,850		$	52	$	-	$	1,798

(1) Includes $50M sublimit for Letters of Credit and $100M sublimit for swingline loans.
(2) Includes a $600M sublimit for Letters of Credit and $100M sublimit for swingline loans.
(1) Includes $50 million sublimit for Letters of Credit and $100 million sublimit for swingline loans, which are made available on a same day basis and repayable in full within thirty days.													(1) Includes $50 million sublimit for Letters of Credit and $100 million sublimit for swingline loans, which are made available on a same day basis and repayable in full within thirty days.
(2) Includes a $600 million sublimit for Letters of Credit and $100 million sublimit for swingline loans, which are made available on a same day basis and repayable in full within thirty days.													(2) Includes a $600 million sublimit for Letters of Credit and $100 million sublimit for swingline loans, which are made available on a same day basis and repayable in full within thirty days.

PG&E Corporation

Senior Credit Facility

On April 8, 2005, PG&E Corporation entered into an amendment,, which became effective on April 12, 2005, to the $200 million revolving senior unsecured credit facility, or the senior credit facility, to extend its term from three years to five years, with all amounts due and payable on December 10, 2009. In addition, the amendment made other changes to the senior credit facility to conform the covenants, representations and events of default to those in the Utility's working capital facility, discussed below. At ~~June~~September 30, 2005, PG&E Corporation had not made any borrowings or issued any letters of credit under the senior credit facility.

The fees and interest rates PG&E Corporation pays under the senior credit facility vary depending on the Utility's unsecured debt ratings issued by S&P and Moody's. A facility fee is based on the total amount of the senior credit facility (regardless of the usage) and a utilization fee is based on the average daily amount outstanding under the senior credit ~~facility are payable quarterly in arrears.~~facility. The utilization fee is payable during any quarter in which the average daily amount outstanding under the senior credit facility is in excess of 50% of the aggregateamount of the facility. At PG&E Corporation's option, any loan under the senior credit facility (other than swingline loans which are made available on a same day basis and repayable in full within thirty days) bears interest at a rate equal to the "applicable margin" plus one of the following indexes: (i) LIBOR or (ii) ~~th e~~the base rate (the higher of (a) the administrative ~~agent's~~agent 's base rate and (b) the Federal Funds rate plus 0.50%). Each swingline loan bears interest at the applicable margin plus the base rate. The applicable margin ranges between 0.50% and 1.35% for Eurodollar loans, and 0% and 0.5% for base rate loans. The facility fee ranges between 0.15% and 0.40%, and the utilization fee ranges between 0.125% and 0.25%.Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.

If the Utility's debt ratings from S&P and Moody's are at different levels, the lower rating applies. In addition, PG&E Corporation pays a fee for each letter of credit outstanding under the senior credit facility equal to the applicable margin for LIBOR loans to be shared by the lenders. PG&E Corporation also pays a fronting fee of 0.125% to the issuer of a letter of credit.

The senior credit facility includesusual and customary covenants for credit facilities of this type, including covenants limiting liens, mergers, sales of all or substantially all of PG&E Corporation's assets and other fundamental changes. Refer to the ~~combined~~ 2004 ~~Annual~~Financial Report for further details.

Utility

Working Capital Facility

On April 8, 2005, the Utility entered into a $1 billion revolving credit facility, or the working capital facility. This credit facility replaced the $850 million credit facility that the Utility entered into on March 5, 2004. The working capital facility includes a $600 million sublimit for the issuance of letters of credit and a $100 million sublimit for swingline loans. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash flows and were used for bridge financing in connection with the reissuance of the tax-exempt pollution control bonds discussed below. Letters of credit under the working capital facility will be used primarily to provide credit enhancements to counterparties for natural gas and electricity procurement transactions.

Subject to obtaining any required regulatory approvals and commitments from existing or new lenders and satisfaction of other specified conditions, the Utility may increase, in one or more requests given not more frequently than once a year, the aggregate lenders' commitments under the working capital facility by up to $500 million or, in the event that the Utility's $650 million accounts receivable facility is terminated or expires, by up to $850 million, in the aggregate for all such increases.

The working capital facility has a term of five years and all amounts will be due and payable on April 8, 2010. At the Utility's request and at the sole discretion of each lender, the facility may be extended for additional periods. The Utility has the right to replace any lender who does not agree to an extension.

The working capital facility includes usual and customary covenants for credit facilities of this type, including covenants limiting liens to those permitted under the Senior Notes indenture, mergers, sales of all or substantially all of the Utility's assets and other fundamental changes. In addition, the working capital facility also requires that the Utility maintain a debt to capitalization ratio of at most 65% as of the end of each fiscal quarter.

The fees and interest rates the Utility pays under the working capital facility vary depending on the Utility's unsecured debt rating by S&P and Moody's. A facility fee is based on the total amount of the working capital facility (regardless of the usage) and a utilization fee is based on the average daily amount outstanding under the working capital ~~facility are payable quarterly in arrears.~~facility. The utilization fee is payable during any quarter in which the average daily amount outstanding under the working capital facility is in excess of 50% of the aggregate amount of the facility. At the Utility's option, any loan under the working capital facility (other than swingline loans) bears interest at a rate equal to the "applicable margin" plus one of the following indexes: (i) LIBOR or (ii) the base rate (the higher of (a) the administrative agent's base rate and (b) the Federal Funds rate plus 0.50%). Each swingline loan bears interest at ~~the~~t he applicable margin plus the base rate. The applicable margin is set at 0% for base rate loans and ranges between 0.22% and 0.675% for LIBOR loans. The facility fee ranges between 0.08% and 0.20%, and the utilization fee ranges between 0.10% and 0.25%. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.

If the Utility's debt ratings from S&P and Moody's are at different levels, the higher rating applies. In addition, the Utility pays a fee for each letter of credit outstanding under the working capital facility equal to the applicable margin for LIBOR loans to be shared by the lenders. The Utility also pays a fronting fee of 0.125% to the issuer of a letter of credit.

At ~~June~~September 30, 2005, there were no loans outstanding under the $1 billion working capital facility. At ~~June~~September 30, 2005, there were approximately ~~$139~~$52 million of letters of credit outstanding under the $1 billion working capital facility.

On April 20, 2005, the Utility borrowed $454 million under the working capital facility. The proceeds were used to repay $454 million under certain reimbursement obligations the Utility entered into in April 2004 when its plan of reorganization under Chapter 11 became effective. These reimbursement obligations replaced the Utility's obligation to certain issuers of letters of credit that were drawn upon during the Chapter 11 proceeding in connection with the redemption of certain pollution control bonds that had been issued for the benefit of the Utility. The draw under the Utility's working capital facility was repaid with the proceeds of the tax-exempt PC Bonds Series A-G issued for the benefit of the Utility by the California Infrastructure and Economic Development Bank.

NOTE 4: ENERGY RECOVERY BONDS

The aggregate principal amount of the first series of ERBs issued was approximately $1.9 billion. They were issued in five classes, with scheduled maturities ranging from September 25, 2006 to December 25, 2012, and final legal maturities ranging from September 25, 2008 to December 25, 2014. Interest rates on the five classes range from 3.32% for the earliest maturing class to 4.47% for the latest maturing class. The proceeds of the first series of ERBs were paid by PERF to the Utility and were used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset. The proceeds of the second series of ERBs, anticipated to be issued in November 2005 in an aggregate amount of up to ~~$800~~$850 million (reflecting recent energy supplier settlements), will be paid by PERF to the Utility to pre-fund the Utility's tax liability that will be due as the Utility collects the DRC over the term of the first series of ERBs.

The total principal amount of ERBs outstanding was ~~$1.87~~$1.811 billion at ~~June~~September 30, 2005. The scheduled principal payments on the ERBs for the years 2005 through 2009 are ~~$126~~$63 million, $221 million, $230 million, $239 million, and $248 million, respectively. The remaining payments thereafter total $810 million. While PERF is a wholly owned consolidated subsidiary of the Utility, PERF is legally separate from the Utility. The assets of PERF (including the recovery property) are not available to creditors of PG&E Corporation or the Utility 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 ~~six~~nine months ended ~~June~~September 30, 2005 were as follows:

	PG&E Corporation		Utility		PG&E Corporation		Utility

(in millions)	Total Common Shareholders' Equity		Total Shareholders' Equity		Total Common Shareholders' Equity		Total Shareholders' Equity

Balance at December 31, 2004	$	8,633	$	9,130	$	8,633	$	9,130
Net income	485		499		737		747
Common stock issued	190		-		231		-
PG&E Corporation common stock repurchased:
Settlement of accelerated share repurchase obligation - February 2005	(14)		-		(14)		-
Accelerated share repurchase - March 2005	(1,051)		-		(1,051)		-
Settlement of accelerated share repurchase obligation - September 2005					(22)		-
Utility common stock repurchased			(960)		-		(960)
Common restricted stock amortization	7		-		8		-
Common stock dividends paid	(111)		(220)		(223)		(330)
Common stock dividends declared but not yet paid	(112)		-		(111)		-
Preferred stock redeemed					-		(36)
Preferred stock dividends	-		(8)		-		(12)
Tax benefit from employee stock options	37		-
Minimum pension liability adjustment	(1)		(2)		(1)		(2)
Other	1		-		48		(2)

Balance at June 30, 2005	$	8,064	$	8,439
Balance at September 30, 2005					$	8,235	$	8,535

Stock Repurchases

~~On February 22,~~March 2005 under an accelerated share repurchase arrangement entered into on December 15, 2004, PG&E Corporation paid Goldman Sachs & Co., or GS&Co., approximately $14 million as a price adjustment based on the daily volume weighted average price, or VWAP, of PG&E Corporation common stock over the term of the arrangement. PG&E Corporation charged the payment to Common Stock within Common Shareholders' Equity.Accelerated Share Repurchase Arrangement

On March 4, 2005, PG&E Corporation entered into an accelerated share repurchase arrangement, or the March 2005 arrangement, with Goldman Sachs & Co., or GS&Co., under which PG&E Corporation repurchased 29,489,400 shares of its common stock at an initial price of $35.60 per share (for an aggregate amount including commissions of approximately $1.05 billion). The repurchase was funded from available cash on hand and the repurchased shares were retired. PG&E Corporation ~~charged~~recorded approximately $460 million to Common Stock and approximately $591 million to Accumulated Earnings within Common Shareholders' Equity in respect of ~~these transactions.~~this transaction. Under the share forward component of the ~~arrangement, or~~ March 4, 2005 arrangement certain payments were required by both PG&E Corporation and GS&Co. upon termination. Most significantly, PG&E Corporation was to receive from, or be required to pay to, GS&Co. a ~~price~~pr ice adjustment on the repurchased shares based on the difference between the amount it paid and the daily volume weighted average price, or VWAP, over the approximately six month intended arrangement period. Upon an early termination of the March 4, 2005 arrangement, PG&E Corporation was required to compensate GS&Co. for its losses in connection with the arrangement unless the termination event resulted from the declaration of a dividend and a new share forward was executed to complete the March 4, 2005 arrangement. As discussed below, on June 15, 2005, the Board of Directors of PG&E Corporation declared a cash dividend on PG&E Corporation common stock for the second quarter of ~~2005.~~

~~Thus, on June 16,~~ 2005 ~~PG&E Corporation entered into a new share forward with GS&Co., or June 16,~~and terminated the March 2005 arrangement ~~based on 11,430,000 shares to complete the balance of the March 4, 2005 arrangement.~~early. The net of the amounts payable between the parties under the March 4, 2005 arrangement, including the amount of the price adjustment based on the VWAP, was approximately $78,000 and was paid to GS&Co., at PG&E Corporation's option in cash, on June 30, 2005.

June 2005 Accelerated Share Repurchase Arrangement

On June 16, 2005, PG&E Corporation entered into a new share forward with GS&Co., or the June 2005 arrangement, based on 11,430,000 shares to complete the balance of the March 2005 arrangement. The June ~~16,~~ 2005 arrangement is substantially identical to the March 4, 2005 arrangement, requiring certain payments by both PG&E Corporation and GS&Co. As with the March 4, 2005 arrangement, the most significant of these payments is the price adjustment with respect to the 11,430,000 shares based on the difference between the $35.60 purchase price per share and the VWAP over a period expected to extend to early September 2005. The ~~price adjustment and any additional payments that PG&E Corporation may make~~net of the amounts payable between the parties under the June ~~16,~~ 2005 arrangement, ~~can be settled,~~including the amount of the price adjustment based on the VWAP, was approximately $22 million, and was paid to GS&Co., at PG&E Corporation's option in cash, ~~or in shares of its common stock, or a combination of~~on September 12, 2005 to settle the ~~two. Therefore,~~arrangemen t.

December 2004 Accelerated Share Repurchase Arrangement

On February 22, 2005, under an accelerated share repurchase arrangement entered into on December 15, 2004, PG&E Corporation ~~accounts for its payment obligations~~paid GS&Co. approximately $14 million as ~~equity.~~

~~Until the June 16, 2005 arrangement is completed or terminated, GAAP requires PG&E Corporation to assume that it will issue shares~~a price adjustment to settle ~~its obligations (up to a maximum of 22,860,000 shares). PG&E Corporation must calculate~~ the ~~number of shares that would be required to satisfy its obligations upon completion of the June 16, 2005 arrangement~~arrangement. The settlement was based on the market price of PG&E Corporation's common stock at the end of a reporting period. The number of shares that would be required to satisfy the obligations must be treated as outstanding for purposes of calculating diluted earnings per share. Based on the market price of PG&E Corporation stock at June 30, 2005, PG&E Corporation would have an obligation to GS&Co. of approximately $25.3 million upon completion of the June 16 arrangement. Accordingly, approximately 674,000 additional sharesVWAP of PG&E Corporation common stock ~~attributable~~over the term of the arrangement. PG&E Corporation recorded the payment to ~~the accelerated repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings per share.~~Common Stock within Common Shareholders' Equity.

Utility Common Stock Repurchase

On March 8, 2005, the Utility used proceeds from the issuance of ERBs (discussed in Note 4) to repay debt and to repurchase 22,023,283 shares of its common stock from PG&E Corporation for an aggregate purchase price of approximately $960 million. The Utility had repurchased $960 million of its common stock as of ~~June~~September 30, 2005. ~~The~~As a result of this transaction, the Utility ~~recognized charges~~recorded reductions of approximately $141 million to Additional Paid-in Capital, approximately $110 million to Common Stock, and approximately $709 million to Reinvested Earnings within Shareholders' ~~Equity in respect of this transaction.~~Equity.

Dividends

On ~~June 15,~~September 21, 2005, the Board of Directors of the Utility declared a dividend of approximately ~~$118~~$117 million that was paid on ~~June 16,~~September 22, 2005 to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that holds approximately 7% of the Utility's common stock.

Also, on ~~June 15,~~September 21, 2005 the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.30 per share, payable on October 15, 2005, to shareholders of record on ~~June 30,~~October 3, 2005. ~~On July 15, 2005~~ PG&E Corporation paid this dividend ~~totaling~~which totaled approximately $119 ~~million, of which~~million. Of this amount, approximately $7 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. In addition, PG&E Corporation paid approximately $6 million in dividend equivalent payments to Convertible Subordinated Note holders of record on ~~June 30,~~October 3, 2005.

PG&E Corporation ~~charged~~recorded dividends declared to Accumulated Earnings and the Utility ~~charged~~recorded dividends declared to Reinvested Earnings.

Redemption of Preferred Stock with Mandatory Redemption Provisions

On April 20, 2005, the Utility's Board of Directors authorized the redemption of all of the outstanding shares of the Utility's 6.57% Redeemable First Preferred Stock and 6.30% Redeemable First Preferred Stock totaling $120 million aggregate par value. Both issues were redeemed on May 31, 2005. In addition to the $25 per share redemption price, holders of the 6.57% Redeemable First Preferred Stock and the 6.30% Redeemable First Preferred Stock received an amount equal to all accumulated and unpaid dividends through May 31, 2005 on such shares totaling approximately $644,000.

Redemption of Preferred Stock without Mandatory Redemption Provisions

On June 15, 2005, the Utility's Board of Directors authorized the redemption of all of the outstanding shares of the Utility's 7.04% Redeemable First Preferred Stock totaling approximately $36 million aggregate par value plus approximately $1 million related to a $0.70 redemption premium. This issue was fully redeemed on August 31, 2005. In addition to the $25 per share redemption price, holders of the 7.04% Redeemable First Preferred Stock received an amount equal to all accumulated and unpaid dividends through August 31, 2005 on such shares totaling approximately $211,000.

NOTE 6: RISK MANAGEMENT ACTIVITIES

~~Non-Trading~~Commodity Procurement Activities

The Utility enters into ~~non-trading activities related~~contracts to ~~procurement of~~procure electricity, ~~and contracts associated with the~~ natural gas and nuclear ~~fuel portfolio.~~fuel. Additionally, the Utility hedges natural gas in the electric and natural gas portfolios on behalf of its customers to reduce commodity price risk. On PG&E Corporation and the Utility's Consolidated Balance Sheets, price risk management activities are presented at fair value of ~~$24million~~$205million in Current Assets - Prepaid expenses and other, ~~current assets and $8~~$138 million in ~~other current liabilities~~Other Non-Current Assets - Other, and $1 million in Current Liabilities - Other for ~~June~~September 30, 2005, and $5 million in Current Assets - Prepaid expenses and other ~~current assets~~ and $11 million in ~~other current liabilities~~Current Liabilities - Other for December 31, 2004. The costs and proceeds of these derivatives are recovered in regulated rates charged to customers and ~~the Utility records the offset to~~are recorded in the regulatory accounts.

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.

PG&E Corporation had gross accounts receivable of approximately ~~$2.1~~$2.2 billion at ~~June~~September 30, 2005 and ~~$2.2 billion at~~ December 31, 2004. The majority of the accounts receivable are associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately ~~$91~~$105 million at ~~June~~September 30, 2005 and $93 million at December 31, 2004 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered ~~likely.~~likel y.

The Utility manages credit risk for its largest customers or counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility's largest customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes ~~immediate~~ action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies on 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 Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At June 30, 2005, there were two counterparties that represented greater than 10% of the Utility's net credit exposure. Both of these counterparties were investment grade representing a total of approximately 44% of the Utility's net wholesale credit exposure.

The Utility conducts business with wholesale 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. Credit losses experienced as a result of electrical and gas procurement activities are expected to be recoverable from customers and are, therefore, not expected to have a material impact on earnings.

The schedule below summarizes the Utility's net credit risk exposure, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at ~~June~~September 30, 2005 and December 31, 2004:

(in millions)	(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%		(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%

June 30, 2005		$	165	$	11	$	154	2	$	68
September 30, 2005											September 30, 2005	$	433	$	95	$	338	2	$	156
December 31, 2004	December 31, 2004	105		7		98		3	62		December 31, 2004	105		7		98		3	62

(1)	Gross credit exposure equals mark-to-market value, 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, liquidity or credit reserves. The Utility's gross credit exposure includes wholesale activity only. Retail activity and payables are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.										Gross credit exposure equals mark-to-market value, 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, liquidity or credit reserves. The Utility's gross credit exposure includes wholesale activity only. Retail activity and payables are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.
(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.										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.

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to the Utility's wholesale customers and counterparties at ~~June~~September 30, 2005 and December 31, 2004:

(in millions)	(in millions)	Net Credit Exposure⁽²⁾			Percentage of Net Credit Exposure	(in millions)	Net Credit Exposure⁽²⁾			Percentage of Net Credit Exposure

Credit Quality⁽¹⁾	Credit Quality⁽¹⁾					Credit Quality⁽¹⁾
June 30, 2005
September 30, 2005						September 30, 2005
Investment grade⁽³⁾	Investment grade⁽³⁾	$	145	94%		Investment grade⁽³⁾	$	335	99%
Non-investment grade	Non-investment grade		9	6%		Non-investment grade		3	1%

Total	Total	$	154	100%		Total	$	338	100%

December 31, 2004	December 31, 2004					December 31, 2004
Investment grade⁽³⁾	Investment grade⁽³⁾	$	79	81%		Investment grade⁽³⁾	$	79	81%
Non-investment grade	Non-investment grade		19	19%		Non-investment grade		19	19%

Total	Total	$	98	100%		Total	$	98	100%

(1)	Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.					Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.
(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.					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.
(3)	Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit worthiness.					Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit-worthiness.

NOTE 7: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility's operating activities.

Commitments

PG&E Corporation

For the ~~six~~nine months ended ~~June~~September 30, 2005, PG&E Corporation did not have any material new commitments or changes to its material commitments, other than those related to the Utility discussed below. The Canadian natural gas pipeline firm transportation contracts effective November 1, 2007 through October 31, 2023, are anticipated to be reassigned to the Utility during the ~~third~~fourth quarter of 2005. See PG&E Corporation's and the Utility's ~~combined~~ 2004 ~~Annual~~Financial Report for further discussion.

Utility

Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase energy and makes payments on existing power purchase agreements. As the Utility acts as only an agent for the Department of Water Resources, or DWR, any agreements entered into by the DWR are not disclosed in the Utility's purchase power agreements. At ~~June~~September 30, 2005, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)
2005	$	1,805	$	544
2006		2,006		2,301
2007		2,140		2,447
2008		1,986		2,215
2009		1,779		1,927
Thereafter		12,761		13,648

Total	$	22,477	$	23,082

Payments made by the Utility under power purchase agreements amounted to approximately ~~$905~~$1,535 million for the ~~six~~nine months ended ~~June~~September 30, 2005, and ~~$1,084~~$1,752 million for the same period in 2004.

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 have fluctuated, generally based on market conditions.

At ~~June~~September 30, 2005, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2005	$	717	$	681
2006		417		1,086
2007		25		25
2008		13		13
2009		9		9
Thereafter		4		4

Total	$	1,185	$	1,818

Payments made by the Utility for natural gas purchases and gas transportation services amounted to approximately ~~$1,108~~$1,583 million for the ~~six~~nine months ended ~~June~~September 30, 2005, and ~~$972~~$1,328 million for the same period in 2004.

Reliability Must Run Agreements

The ISO has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units, known as RMR units, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. At ~~June~~September 30, 2005, as a party to a Transmission Control Agreement, or TCA, the Utility estimated that it could be obligated to pay the ISO approximately ~~$138~~$329 million for costs incurred under these RMR agreements during the period ~~July~~October 1, 2005 to ~~June 30,~~December 31, 2006. Of this amount, the Utility estimates it would receive approximately ~~$15~~$49 million under these RMR agreements during the same period. These payments and receipts are subject to applicable ratemaking ~~mechanisms.~~mechanisms and will be recognized in future periods as incurred.

In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision in a rate case involving subsidiaries of Mirant Corporation. The ALJ approved rates and a ratemaking methodology that, if affirmed by the FERC, would have required the Mirant Corporation subsidiaries that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $363 million, including interest, for the availability of RMR plants under these agreements. On July 14, 2003, Mirant Corporation and certain of its subsidiaries filed a petition for reorganization under Chapter 11 and, on December 15, 2003, the Utility filed claims in the Chapter 11 proceeding including a claim for an RMR refund. On January 14, 2005, the Utility entered into a settlement with Mirant Corporation and its subsidiaries that own RMR units that, among other matters, will resolve th e Utility's claim through September 30, 2004 (see "Mirant Settlement" below). On April 13, 2005, the FERC approved the settlement agreement and also terminated the RMR rate case involving the Mirant Corporation subsidiaries without ruling on the ALJ's ratemaking methodology.

~~If the FERC adopted the ALJ's ratemaking methodology, the Utility believes it would be entitled to a refund of RMR payments made to other RMR plant owners. Therefore, on May 13, 2005,~~November 2001 the Utility and other interested California parties ~~as well as the Mirant Corporation subsidiaries, sought rehearing of the part of the FERC's April 13 order terminating the RMR case and urged~~filed a complaint at the FERC ~~to issue~~against RMR owners other than the Utility, alleging that certain rates under those owners' RMR agreements with the ISO were unlawfully high and proposing that the FERC apply a ~~final decision approving the~~ ratemaking methodology ~~adopted in the ALJ's initial decision. On~~to these other RMR agreements that would significantly reduce those rates. In an order issued on June 3, 2005, the FERC ~~issued an order denying rehearing. In~~dismissed this complaint without a ~~separate order issued~~decision on June 3, the FERC also dismissed a complaint that had been filed in November 2001 at the FERC against other RMR owners alleging that the ratemaking methodology approved by the ALJ should apply to other RMR agreements.

its merits. On July 5, 2005, the Utility, along with other interested California parties, filed a request for rehearing of the FERC's June 3 ~~order dismissing the complaint and urged~~order. On August 3, 2005, the FERC ~~to find~~denied the request for rehearing. On September 23, 2005, the Utility and other ~~owners' RMR rates unlawfully high based on~~interested California parties filed a petition for review of this decision with the ~~ratemaking methodology approved by~~United States Court of Appeals for the ~~ALJ in the Mirant RMR rate case.~~District of Columbia Circuit. Any refunds the Utility may obtain will be credited to the Utility's ~~retail~~ electricity customers. PG&E Corporation and the Utility are unable to predict the outcome of this matter.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, ~~the~~energy efficiency program incentives, self-generation incentive program exchange agreements, telecommunication contracts and the electric generating interconnection project contracts. At ~~June~~September 30, 2005, the future minimum payments related to other commitments were as follows:

(in millions)
2005	$	92	$	83
2006	114		98
2007	18		18
2008	14		13
2009	6		6
Thereafter	14		14

Total	$	258	$	232

Payments made by the Utility for other commitments amounted to approximately ~~$48~~$100 million for the ~~six~~nine months ended ~~June~~September 30, 2005, and ~~$63~~$102 million for the same period in 2004.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain NEGT indemnity obligations issued to the purchaser of an NEGT subsidiary company during 2000, up to $150 million. The underlying indemnity obligations of NEGT have expired and PG&E Corporation's sole remaining exposure relates to the potential of environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser. PG&E Corporation has never received any claims nor does it consider it probable any claims will occur under the guarantee. Accordingly, PG&E Corporation has made no provision for this guarantee at ~~June~~September 30, 2005.

PG&E Corporation also retains a guarantee of the Utility's underlying obligation to pay workers' compensation claims. As of ~~June~~September 30, 2005, the actuarially determined workers' compensation liability was approximately ~~$227.2~~$227.8 million.

Utility

PX Block-Forward Contracts

The Utility had PX block-forward contracts, which were seized by California's then-Governor Gray Davis in February 2001 for the benefit of the state, acting under California's Emergency Services Act. At the time the state of California seized them, the block-forward contracts had an estimated unrealized gain of up to $243 million, an amount which ~~amount~~ was reflected in account receivables in the Utility balance sheet. The Utility, the PX, and some of the PX market participants have filed claims in state court against the state of California to recover the value of the seized contracts. The state of California disputes the plaintiffs' rights to recover any valuations. The Utility has ~~accrued a reserve for~~fully reserved the estimated value of the seized contracts. This state court litigation is pending. The Utility is unable to predict the outcome of this litigation or the impact on its financial condition or results of operations.

California Energy Crisis Proceedings

FERC Proceedings

Various entities, including the Utility and the state of California are seeking ~~up to $8.9 billion in~~ refunds for electricity overcharges on behalf of California electricity purchasers for the period May 2000 to June 2001 through aregulatory and judicial proceedings. A proceeding ~~pending~~began at the FERC, ~~and in the appellate courts reviewing FERC decisions. This proceeding,~~ the Refund Proceeding, ~~commenced~~ on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. ~~On July 25, 2001, the~~A FERC held that refunds would be available for certain overcharges, and established a process to determine the refunds but asserted that it could not order market-wide refunds for periods before October 2, 2000. In December 2002, a FERCadministrative law judge, or ALJ, issued an initial decision in ~~the Refund Proceeding~~December 2002, finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe ~~the power suppliers approximately~~ $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

In March 2003, the FERC ~~confirmed most of~~accepted the ALJ's ~~findings in the Refund Proceeding,~~decision but ~~partially~~ modified the refund methodology to include use of a new natural gas price methodology ~~as the basis for mitigated prices. The FERC~~and indicated that ~~it would consider later allowances claimed~~the refunds could be reduced by ~~sellers for~~the amount of the seller's actual natural gas costs ~~above~~that are higher than the prices assumed in the ALJ's refund methodology. The sellers were directed to submit proof of their actual natural gas ~~prices in the refund methodology. In March 2005, FERC extended the time for review of gas allowance claims and~~costs to the ISO ~~expects~~which is responsible for recalculating the refunds according to ~~receive~~ the ~~required~~new methodology. It is expected that the sellers' audited fuel cost information will be submitted to the ISO by November 1, 2005. In subsequent rulings, the FERC also ruled that if any sellers could demonstrate that refunds would result in sales revenue below their costs, their refund obligation would be reduced. Various sellers submitted information to the FERC trying to make such a showing and the FERC is expected to issue a decision on these fili ngs by November 15, 2005.

The FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to ~~make compliance filings~~submit new calculations establishing refund ~~amounts.~~amounts based on the new methodology and audited natural gas cost reductions. The ISO has recently indicated that it plans to ~~make~~file its ~~compliance filing~~recalculation in the first quarter of 2006, with the PX to follow. ~~In October 2003,~~

Parties have appealed the ~~FERC affirmed its March 2003 decision~~applicability and ~~various parties appealed to~~scope of the Ninth Circuit. Briefs have been submitted concerning which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters were argued beforeFERC's refund methodology. On September 6, 2005, the Ninth Circuit ~~on April 12 and 13, 2005, and~~issued a partial decision ~~is expected by the end of 2005.~~

~~The final refunds will not be determined until~~finding that the FERC ~~issues a final decision in~~did not have the ~~Refund Proceeding, following the ISO~~authority to order governmental and ~~PX compliance filings~~municipal utilities to provide refunds. This finding could substantially reduce refunds and the ~~resolution of~~Utility is reviewing this decision and considering whether to seek rehearing or further appellate review. A further Ninth Circuit decision on the ~~appeals~~extent of the FERC's ~~orders. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities.~~

~~In the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the~~ power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In September 2004, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The FERC has not yet acted on this finding and itfrom other sellers is ~~uncertain how it will be applied by the FERC.~~still pending.

The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as disputed claims. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of unpaid PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The revised methodology adopted by the FERC's March 2003 decision could further reduce the amount by several hundred million ~~dollars, offset~~dollars. In addition, refunds could be further reduced by the amount of any ~~additional~~FERC-approved fuel cost ~~allowance~~allowances or cost recovery offsets for ~~suppliers.~~suppliers and any refunds not received from m unicipal entities.

The Utility has entered into settlements with various power suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. As of ~~June~~September 30, 2005, the Utility has recorded total offsets to the Settlement Regulatory Asset and credits to customers of approximately ~~$765~~$728 million in connection with these settlements. (The settlement agreements make provision for several contingencies that may affect the final amounts actually received by the Utility). Approximately $310 million of these credits were recorded as an offset to the Settlement Regulatory Asset that was refinanced through the issuance of the first series of ERBs in February 2005. The remaining ~~$455~~$418 million has been credited to the ERBBA, offset by net interest costs of approximately ~~$70~~$83 million related to net disputed claims. As indicated previously, the resolution of a number of pending FERC and appellate proce edings could affect the net settlement amounts. Amounts received by the Utility under future settlements for electric market overcharges with energy suppliers will be ~~credi ted~~credited to customers, except for those related to certain wholesale power purchases, either as a reduction to the amount of the second series of ERBs, anticipated to be issued in November 2005, or if refunds are received after the second series of ERBs is issued, as a credit to the ERBBA.

Enron Settlement

On ~~July 15,~~August 24, 2005, the Utility along with the Attorney General of the State of California, the California Department of Water Resources, Southern California Edison, San Diego Gas & Electric Company, the California Electric Oversight Board and the CPUC, along with the Attorney Generals of the States of ~~California,~~ Oregon and Washington, ~~the California Department of Water Resources, or DWR,~~and the FERC's Office of Market Oversight and Investigations ~~Southern California Edison, and San Diego Gas & Electric Company,~~ entered into a ~~memorandum of understanding, or MOU,~~definitive agreement with Enron Corporation and various of its subsidiaries, or Enron, to satisfy Enron's liabilities in the Refund Proceeding. The ~~MOU is subject to negotiation and execution of a definitive~~ agreement ~~to be~~was also filed with the FERC on August 24, 2005, with a decision requested by ~~August 19,~~year end 2005. ~~The definitive~~On October 20, 2005, the agreement was approved by Enron's bankruptcy court, however, the agreement will not become effective until approved by the ~~FERC, the CPUC and the bankruptcy court where Enron's bankruptcy cases are pending.~~FERC.

The ~~MOU~~settlement provides that Enron would pay $47 million in cash ~~to the California parties~~ and allow an unsecured claim of $875 million in the bankruptcy proceeding of Enron Power Marketing, ~~I nc.~~Inc., a subsidiary through which Enron conducted its power marketing operations in ~~California.~~California, to settle electric and gas market overcharges. The actual value of the bankruptcy claim is uncertain and the final amount would not be realized until the conclusion of the bankruptcy ~~case. Further, the~~case unless liquidated earlier in a secondary market. The allocation of the amount of the cash payment and the ~~amount realized upon payment of the~~ allowed claim among the California ~~utilities~~parties remains subject to final negotiation and agreement. The Utility has not yet recorded the amount of refunds to be provided under the settlement agreement as several conditions, including FERC approval, have not yet been met.

Reliant Settlement

On August 12, 2005, the Utility along with the Attorney Generals of the States of Oregon and Washington, the DWR, the FERC's Office of Market Oversight and Investigations, Southern California Edison and San Diego Gas & Electric Company, entered into a memorandum of understanding with Reliant Energy, Inc. and various of its subsidiaries, or Reliant, to resolve claims against Reliant for gas and electric market manipulation and overcharges during the California energy crisis in 2000 and 2001. The definitive agreement was executed and submitted to the FERC for approval on October 14, 2005. The FERC was requested to issue a decision by the end of 2005. The agreement will not become effective until it is approved by the FERC.

The agreement provides that Reliant will assign to the California parties approximately $300 million of its receivables from the California ISO or PX and related interest of approximately $10 million. In addition, Reliant will provide the California parties approximately $131 million in cash. The allocation of these considerations among the California parties remains subject to final negotiation and agreement. The Utility has not yet recorded the amount of the refunds to be provided under the settlement agreement as several conditions, including FERC approval have not yet been met.

Mirant Settlement

In January 2005, the Utility and other parties entered into a settlement agreement with Mirant Corporation and certain of its subsidiaries, or Mirant, related to claims outstanding in Mirant's Chapter 11 proceeding.

The first part of the two-part settlement is between Mirant, ~~and several California parties, including~~ the California Attorney General's Office, the DWR, the CPUC, Southern California Edison, San Diego Gas & Electric Company, and the Utility, ~~or the California Parties,~~among others, resolving market manipulation claims ~~including~~against Mirant and Mirant's liability for FERC refunds, penalties and civil liabilities arising out of the California energy crisis in 2000 to 2001. Under this portion of the agreement, Mirant will provide ~~the California Parties~~ approximately $320 million in cash equivalents and $175 million of allowed claims in the bankruptcy proceeding of Mirant America's Energy Marketing, LP. Of these amounts, the Utility will receive approximately $130 million in cash ~~equivalents~~ and as a reduction in the Utility's payable to the PX, and will receive $40 million in allowed claims. Most of the ~~$130 million~~ consideration has been ~~included in~~credited to the ~~$45 5 million credited to~~Utility's customers through the ERBBA ~~during~~or reflected as a regulatory liability dur ing the quarter as described above. The final cash value of the allowed claims will not be known until the completion of ~~Mirant's~~the bankruptcy ~~proceedings.~~proceedings unless liquidated earlier in a secondary market for such claims.

The second part of the settlement is between the Utility and Mirant and is designed to settle claims that Mirant overcharged the Utility under Mirant's RMR contracts and other disputes. Under the settlement agreement, Mirant has agreed to transfer to the Utility the equipment, permits and contracts for the construction of Contra Costa Unit 8, a modern 530-megawatt electric generating facility Mirant started to build, but never completed. On June 10, 2005, the Utility and Mirant completed negotiations onof an Asset Transfer Agreement, which provides the terms and conditions under which the Contra Costa 8 equipment, permits, and contracts would be transferred to the Utility and development and construction of the plant would be completed. On June 17, 2005, the Utility filed an application with the CPUC requesting approval of the Asset Transfer Agreement and cost-of-service funding to complete the $310 million construc tion of the facility, and funding to operate it for up to three years. The ~~Utility requested~~CPUC hearings ~~in October~~are scheduled to begin December 5, 2005 and a final decision ~~in January~~is expected by March 15, 2006. If the Utility and Mirant do not receive the necessary approvals, including CPUC authorization, the Utility will be paid at least $70 million in lieu of transferring the assets. The settlement agreement also includes a contract that ~~would give~~gives the Utility the right from 2006 through 2012 to dispatch power from certain RMR units owned by Mirant subsidiaries, subject to continued RMR status, when the facilities are not needed by the ISO to meet local reliability needs. In addition, Mirant has withdrawn the claim it filed in the Utility's bankruptcy proceeding of approximately $20 million and the Utility will receive approximately $60 million of allowed claims, credits, offsets, and/or cash from Mirant and Mirant will withdraw its outstanding claim in the Utility's bankruptcy proceeding of approximately $20 million. The settlement may also include separate options under which the Utility, under certain circumstances, would have the right to acquire Mirant's existing Contr a Costa and Pittsburg power plants.Mirant.

The settlement agreement became effective on April 15, 2005, after all regulatory and other approvals required by the settlement agreement were obtained. ~~In June~~As of September 30, 2005, the Utility has recorded a receivable and a corresponding regulatory liability of approximately ~~$140~~$171 million, which includes the $70 million discussed above relating to the transfer of the Contra Costa 8 assets, representing the expected value to be received in connection with the Mirant settlement agreement.

Nuclear Insurance

The Utility has several types of nuclear insurance for the Diablo Canyon Power Plant, or Diablo Canyon, and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or 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. 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 ~~$42.5~~$43.6 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, there isare no policy coverage limitations for an act caused by foreign terrorists because NEIL would be entitled to receive substantial reimbursement by the federal government. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

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, or 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 ~~$10~~$15 million per incident until the Utility has fully paid its share of the liab ility. 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 ~~$20~~$30 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including Diablo Canyon, which had coverage before December 31, 2003. Congress may address renewal of the Price-Anderson Act in future energy legislation.

In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at Humboldt Bay power plant and has a $500 million indemnification from the NRC, for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

California Department of Water Resources Contracts

Electricity from the DWR allocated contracts provided approximately 26% of the electricity delivered to the Utility's customers for the ~~six-month~~nine-month period ended ~~June~~September 30, 2005. The DWR purchased the electricity under contracts with various generators. The Utility is responsible for administration and dispatch of the DWR's electricity procurement contracts allocated to the Utility for purposes of meeting a portion of the Utility's net open position, which is the portion of the demand of a utility's customers, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts. The DWR remains legally and financially responsible for its electricity procurement contracts. The Utility acts as a billing agent for the collection of the DWR's revenue requirements from the Utility's customers.

The ~~current~~ DWR contracts currently allocated to the Utility terminate at various times through 2012, and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facilities regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered. In the Utility's ~~proposed~~CPUC-approved long-term integrated energy resource plan, ~~filed with the CPUC in July 2004 and approved in December 2004,~~ the Utility has not assumed that the DWR contracts will be renewed beyond their current expiration dates.

The DWR has stated publicly that it intends to transfer full legal title to, 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 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 will be no less than A2 and the Utility's long-term issuer credit rating by S&P will be no less than A;
·	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.

Defined Benefit Pension Plan Additional Minimum Liability

If current market conditions continue through the remainder of 2005, the Utility anticipates that its defined benefit retirement plan assets at December 31, 2005 will be less than the accumulated benefit obligations due to changes in certain market yields used to estimate benefit ~~obligations and low stock market returns.~~obligations. The ultimate amount, if any, that the Utility would be required to recognize as an additional minimum pension liability is dependent upon certain market yields at December 31, 2005 and investment returns through the remainder of 2005 and as such, cannot be estimated at this time.

The Utility has recently filed a petition requesting the CPUC to authorize it to resume contributions to its employee pension trust beginning in 2006 based upon the funded status of the pension plan. The petition estimates the annual revenue requirement associated with the pension contributions for its generation and distribution businesses to be approximately $185 million, and it requests that the amount be recovered in rates beginning January 1, 2006, subject to refund to customers if the CPUC later disapproves the contributions. The Utility is unable to predict the outcome of the petition to the CPUC, the amount of minimum pension liability to be recognized, if any, or the impact on its financial condition or results of operations.

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 the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, as amended, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occ ur 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 estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately ~~$410~~$414 million at ~~June~~September 30, 2005, and approximately $327 million at December 31, 2004. During the ~~six~~nine months ended ~~June~~September 30, 2005, the liability increased by approximately ~~$83~~$87 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately ~~$410~~$414 million accrued at ~~June~~September 30, 2005, includes approximately $101 million related to the pre-closing remediation liability associated with divested generation facilities and approximately ~~$309~~$313 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the ~~former manufactur ed~~f ormer manufactured gas plant sites. Of the approximately ~~$410~~$414 million environmental remediation liability, approximately $143 million has been included in prior rate setting proceedings and the Utility expects that approximately ~~$202~~$205 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

The Utility's undiscounted future costs could increase to as much as ~~$578~~$584 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately ~~$578~~$584 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.

Taxation Matters

The Internal Revenue Service, or IRS, has completed its audit of PG&E Corporation's 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of approximately $81 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the ~~IRS'~~IRS Appeals Office.

The IRS also has completed its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns and refunded $14 million to PG&E Corporation. As a result of the resolution of this audit, in the second quarter of 2005 PG&E Corporation paid the Utility $18 million relating to the Utility matters that had been included in the audit, the Utility reduced its reserve for outstanding tax audits by $11 million and PG&E Corporation recognized tax benefits of $32 million for ~~NEGT related~~NEGT-related matters included in the audit.

The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. The IRS has indicated that it plans to ~~complete~~continue the audit ~~and issue a Revenue Agent Report in~~into 2006. At the ~~third or fourth quarter~~beginning of ~~2005. During~~ its examination the IRS ~~has proposed to~~indicated it would disallow synthetic fuel credits claimed by PG&E Corporation. ~~The~~In addition, the IRS ~~also~~ has proposed to disallow a number of deductions, the largest of which is a deduction for abandoned or worthless assets owned by NEGT. PG&E Corporation believes that it properly reported these transactions in its tax returns and will contest any IRS assessment. If the IRS includes all of its proposed disallowances in the final Revenue Agent Report, the alleged tax deficiency would approximate $452 million. Of this deficiency, approximately $104 million relates to the synthetic fuel credits and approximately $316 million is of a timing nature, which would be ~~ref unded~~refunded to PG&E Corporation in the ~~future.~~f uture. In the second quarter of 2005, PG&E Corporation ~~has~~ increased its reserve with respect to NEGT tax issues included in the 2001 and 2002 consolidated federal income tax returns by $32 ~~million to a total of $84 million for all open tax audits.~~million.

PG&E Corporation has filed its 2003 federal income tax return and expects to file its 2004 return by September 15, 2005. PG&E Corporation has paid estimated federal income taxes with respect to the 2004 tax year, which amount includes the estimated 2004 tax liability of $94 million related to NEGT through October 29, 2004, the effective date of NEGT's plan of reorganization. PG&E Corporation has previously recognized this estimated tax liability in discontinued operations. PG&E Corporation expects theThe IRS ~~to begin~~began its audit of PG&E Corporation's 2003 and 2004 tax returns byin the ~~end~~third quarter of ~~the year.~~2005.

During ~~second~~the third quarter of 2005, ~~NEGT-related activities had no impact on~~PG&E Corporation received additional information from NEGT regarding income to be included in PG&E Corporation's 2004 federal income tax return. This information was incorporated in the 2004 tax return, which was filed with the IRS in September 2005. As a result, the 2004 federal income tax liability was reduced by approximately $19 million. In addition, NEGT provided additional information with respect to amounts previously included in PG&E Corporation's 2003 federal income tax return. This change resulted in PG&E Corporation's 2003 federal income tax liability increasing by approximately $6 million. These two adjustments, netting to $13 million, were recognized in income from discontinued operations ~~and consisted~~in the third quarter of ~~the net loss benefit related to the 1999-2000 audit, offset by the provision for additional tax assessments for the 2001-2002 audit.~~2005.

As of ~~June~~September 30, 2005, PG&E Corporation has accrued approximately ~~$133~~$138 million to cover potential tax obligations and interest related to outstanding audits, including the ~~$84~~$89 million related to NEGT issues discussed above, and $49 million to cover potential tax obligations related to non-NEGT issues. The increase in PG&E Corporation's accrual at ~~June~~September 30, 2005, compared to December 31, 2004, of approximately ~~$40~~$37 million is primarily related to the ~~current~~second quarter increase of $32 million in the accrual for NEGT tax issues included in the 2001-2002 audit discussed above. ~~In addition, as~~

As of ~~June~~September 30, 2005, the Utility has accrued approximately $52 million to cover potential tax obligations discussed above, including interest, related to outstanding audits. This represents an $11 million reduction from the accrual at December 31, 2004, and reflects the resolution in the ~~current~~second quarter of the 1999-2000 audit ~~disc ussed~~discussed above.

Considering these reserves, PG&E Corporation ~~does~~and the Utility do not expect the resolution of the outstanding audits to have a material impact on ~~its~~their financial condition or results of operations.

Legal Matters

In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. The most significant of these are discussed below.

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 case. 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 other noncurrent liabilities in the Condensed Consolidated Balance Sheets, and totaled approximately ~~$209~~$222 million at ~~June~~September 30, 2005 and $220 million at December 31, 2004. As to the chromium litigation described below, PG&E Corporation and the Utility are unable to predict whether the ultimate outcome of this matter will have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

PG&E Corporation and the Utility do not believe it is probable that losses associated with legal matters other than the chromium litigation, that exceed amounts already recognized will be incurred in amounts that would be material to PG&E Corporation's or the Utility's financial condition or results of operations.

Chromium Litigation

There are 14 civil suits pending against the Utility in several California state courts in which plaintiffs allege that exposure to chromium at or near the Utility's compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful deaths, or other injury, ~~and seek related damages.~~referred to as the Chromium Litigation. One of these suits also names PG&E Corporation as a defendant. ~~Currently, there~~There are ~~approximately~~currently about 1,200 plaintiffs in the ~~chromium litigation cases. Approximately 1,260 individuals~~Chromium Litigation who seek compensatory damages, more than 1,000 of whom are also seeking punitive damages. Although the plaintiffs' complaints in the Chromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000 of the current plaintiffs filed ~~proofs of~~ claims in the Utility's Chapter 11 case ~~most of whom also are plaintiffs~~requesting compensatory damages in ~~the chromium litigation cases. Approximately 1,035 of these claimants filed claims requesting~~ an approximate aggregate amount of ~~$580~~$500 million and ~~another approximately 225 claimants~~others filed ~~claims~~cla ims for an "unknown amount." ~~Pursuant to the~~(The Utility's ~~plan of reorganization, these claims have p assed through the Utility's~~exit from Chapter 11 ~~proceeding unimpaired.~~in April 2004 did not affect the plaintiffs' claims for compensatory and punitive damages.) To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select 18 plaintiffs for the first trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the initial trial plaintiffs, and one plaintiff and two alternates were selected at random.

The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. The Utility ~~will pursue~~is pursuing appropriate legal defenses, including statute of limitations, exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from three of the cases for a test trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the initial trial plaintiffs, and one plaintiff and two alternates were selected at random.

The Utility has filed 14 motions in the Superior Court for the County of Los Angeles, or Superior Court, challenging the ~~test~~first trial plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries. ~~In February 2005, the~~The Superior Court has denied ~~two~~four of these ~~motions. The Utility filed~~motions and also has denied the Utility's motions for reconsideration of these ~~orders with~~orders. The Utility has sought appellate court review of the Superior ~~Court and also filed a request with~~Court's denials of the ~~appellate court seeking to overturn or modify~~Utility's pre-trial motions based on the ~~orders because~~argument that they are inconsistent with recent California appellate decisions (one of which is now under review by the California Supreme Court) concerning the admissibility of expert testimony and the requirements for proving medical causation. ~~After these motions for reconsideration and~~The Utility also requested the ~~request were filed,~~appellate court to order the Superior Court to stay the upcoming trial until after the California Supreme Court ~~granted review~~issues its decision. The appellate court ordered the plaintiffs to file a brief addressing the issues raised by the Utility. Plaintiffs' brief was filed on September 23, 2005 and the Utility's responses were filed on September 30 and October 3, 2005. The appellate court's decision as to whether to consider the merits of the Utility's appeal is still pending.

On October 3, 2005, the Utility received a ruling issued by the Superior Court granting one of ~~these recent appellate decisions. In April~~the Utility's pre-trial motions. As a result of the ruling, the Superior Court dismissed one plaintiff who was scheduled to participate in the first trial who claimed that chromium caused her Crohn's disease. The ruling also applies to seven other plaintiffs who are claiming that exposure to chromium caused them to contract Crohn's disease. Also, on September 20, 2005, in response to another pre-trial motion that had been filed by the Utility, three plaintiffs who were scheduled to participate in the first trial voluntarily dismissed their claims. On October 19, 2005, the Superior Court ~~heard arguments on both motions for reconsideration and denied the motions in July 2005.~~

~~On June 9, 2005, the Superior Court denied another of~~took under submission the Utility's ~~motions~~motion for summary judgment that plaintiffs have failed to ~~exclude evidence,~~prove that exposure to chromium caused leukemia.

The trial for the 14 remaining plaintiffs who were selected to participate in the first trial was scheduled to begin on January 9, 2006, but has been moved to February 7, 2006. Counsel for the Utility and counsel for the plaintiffs are engaged in settlement discussions. PG&E Corporation and the Utility ~~filed a motion for reconsideration. On July 18, 2005,~~cannot predict the ~~Superior Court denied this motion for reconsideration. The Superior Court denied another~~outcome of ~~the Utility's motions to exclude evidence on June 29, 2005~~these discussions.

As previously disclosed, the Utility has recorded a $160 million reserve in its financial statements with respect to the ~~chromium litigation.~~Chromium Litigation. Given ~~recent rulings and appellate writs regarding~~the Superior Court's denials of the Utility's pre-trial motions and the ~~California Supreme Court's current review~~uncertainty of ~~similar issues in unrelated litigation,~~the outcome of the Utility's request to the appellate court, PG&E Corporation and the Utility are ~~no longer able~~unable to predict whether the ultimate outcome of this matter, after taking into account the amount already reserved at ~~June~~September 30, 2005, would have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations.

The dismissals entered on September 20 and the October 3 ruling have not altered this assessment of the ultimate outcome of the Chromium Litigation.

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

OVERVIEW

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 and a variable interest entity for which it is subject to a majority of the risk of loss or entitled to receive a majority of the entity's residual returns. This combined Management's Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, of PG&E Corporation and the Utility should be read in conjunction with these Condensed Consolidated Financial Statements and Notes to the Condensed Consolidat ed Financial Statements, as well as the MD&A, Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their ~~combined 2004 Annual~~joint Current Report on Form ~~10-K,~~8-K dated October 28, 2005, as amended on October 31, 2005, or the 2004 ~~Annual Report, filed with the Securities and Exchange Commission, or SEC.~~Financial Report..

The Utility served approximately 5.0 million electricity distribution customers and approximately ~~4.1~~4.2 million natural gas distribution customers at ~~June~~September 30, 2005. The Utility had approximately ~~$34.0~~$34 billion in assets at ~~June~~September 30, 2005 and generated revenues of approximately ~~$5.2~~$8 billion in the ~~six~~nine months ended ~~June~~September 30, 2005.

The Utility is regulated primarily by the California Public Utilities Commission, or ~~the~~ CPUC, and the Federal Energy Regulatory Commission, or ~~the~~ FERC. The Utility's revenues are generated mainly through the sale and delivery of electricity and natural gas at rates set by the CPUC and the FERC. Rates are set to permit the Utility to recover its authorized "revenue requirements" from customers. Revenue requirements are designed to allow the Utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or 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~~ 2004 ~~Annual~~Financial Report and ~~below~~be low under "Regulatory Matters."

Factors Affecting Financial Condition and Results of Operations

Several factors have had, and are expected to continue to have, a significant impact on PG&E Corporation's and the Utility's financial condition and results of operations, including:

·	~~The issuance of approximately $1.9 billion~~In February 2005, after the first series of Energy Recovery Bonds, or ERBs, ~~on February 10, 2005 by PG&E Energy Recovery Funding LLC, or PERF, a limited liability company that is wholly owned and consolidated by~~were issued (as discussed below under "Regulatory Matters"), the Utility ~~(but legally separate from~~refinanced the ~~Utility). The Utility used the ERB proceeds to repay debt and repurchase stock resulting in the elimination~~after-tax portion of the Settlement Regulatory Asset ~~on which~~established by the ~~Utility was entitled to earn an 11.22% rate of return on equity, or ROE, as provided in the~~December 2003 settlement agreement entered into among the Utility, PG&E Corporation and the CPUC to resolve the Utility's Chapter 11 case, or the Settlement Agreement. ~~The elimination~~While the after-tax portion of the Settlement Regulatory Asset existed, the Utility earned its authorized rate of return on equity, or ROE, of 11.22% on the Settlement Regulatory Asset. After the elimination of the after-tax portion of the Settlement Regulatory Asset, ~~reduced~~the Utility no longer was entitled to collect the revenue requirements, including the revenue requirement to recover the 11.22 % ROE, associated with this asset. As a result, the Utility's net income for the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 were reduced by approximately ~~$28~~$27 million and ~~$46~~$73 million, ~~compared~~compar ed to the same periods in 2004, when the Utility earned the 11.22% ROE on the Settlement Regulatory Asset. Total net income for 2005 ~~i s~~is estimated to be reduced by approximately $100 million, compared to 2004, due to the elimination of the 11.22% ROE on the Settlement Regulatory Asset. The ~~Utility's net income also will be reduced by approximately $55 million in 2006 representing the equity portion~~issuance of ~~the carrying cost credit associated with~~ the second series of ERBs, anticipated to ~~be issued~~occur in November 2005, is expected to result in ~~an aggregate amount of up to $800 million and the after-tax balance of energy supplier refunds received before the second series of ERBs is issued. See "Regulatory Matters" below.~~
·	As a ~~result of the increase~~reduction in the Utility's ~~equity ratio from 49% in 2004 to 52% in 2005, the Utility's equity earnings in the three and six-month periods ended June 30, 2005, increased by~~2006 net income of approximately $7 million and $21 million compared to the same periods in 2004. Based on the 52% equity ratio, it is expected that the Utility's equity earnings for the second half of 2005 will increase by approximately $20 million compared to the same period in 2004.$56 million. Net income for 2006 also will be affected by the amount of ROE authorized by the CPUC ~~for 2006. The Utility's currently authorized ROE of 11.22% will be~~ in ~~effect until~~ the Utility's 2006 cost of capital application is approved by the CPUC. On May 9, 2005, the Utility filed its 2006 cost of capital application with the CPUC for its electric utility generation and distribution operations and gas distribution operations requesting an authorized ROE of 11.50% and that the equity component of its authorized capital structure for 2006 remain at 52.0 %. The Utility has proposed that any changes to its electric and gas revenue requirements resulting from adjustments to its authorized 2006 test year cost of capital be effective January 1, 2006.proceeding. (See "Regulatory Matters" below).;
·	~~With the achievement of a 52% equity ratio, during the six months ended June 30,~~During 2005, the Utility used cash (including the ERB proceeds) in excess of amounts needed for operations, debt service and repayment, base capital expenditures, and the reinstated quarterly dividend, to repurchase common stock. In turn, PG&E Corporation ~~used the cash received from the Utility to recommence~~reinstated the payment of a regular ~~$0.30~~quarterly dividend at an annual rate of $1.20 per ~~share quarterly common stock~~share. As discussed below under "Liquidity", the Board of Directors of PG&E Corporation has increased the annual dividend ~~and~~level target, consistent with its dividend policy, to ~~repurchase common stock from shareholders.~~ $1.32 per share;
·	PG&E ~~Corporation's repurchase of~~Corporation has repurchased common stock under accelerated share repurchase arrangements that have increased both basic and diluted earnings per share by approximately ~~$0.06~~$0.15 and ~~$0.05,~~$0.14, respectively, for the ~~six~~nine months ended ~~June~~September 30, 2005. ~~The calculation of~~ PG&E Corporation's earnings per share for future periods will be affected by the accelerated share repurchase arrangements that PG&E Corporation has entered into with Goldman Sachs & Co., or GS&Co. In addition, PG&E Corporation anticipates repurchasing additional shares subject to authorization by the Board of ~~Directors. Any~~Directors has authorized additional repurchases ~~would be made toward the end~~ of up to $1.6 billion of common stock in 2005 and ~~would not significantly affect earnings per share in 2005. (See~~2006, as discussed below under "Liquidity ~~and Financial Resources" below).~~- Stock Repurchases;"
·	~~During the three months ended June 30, 2004,~~By December 2, 2005, the Utility ~~recorded additional revenues authorized in the CPUC's May 2004 decision in the Utility's 2003~~intends to file its 2007 General Rate Case, or ~~GRC. Because~~GRC, application with the additional revenues covered 2003 and the six-month period ended June 30, 2004, the total GRC revenues for the three-month period ended June 30, 2005 are approximately $100 million lower than in the same period in 2004. On August 1, 2005, the Utility notified the CPUC ~~that it intended to file its 2007 GRC application~~ to determine the amount of authorized base revenues to be collected from customers to recover the Utility's basic business and operational costs for its gas and electric distribution and electric generation operations for the period 2007 through 2009. ~~The Utility~~As compared to the projected authorized 2006 revenue requirements, the Utility's Notice of Intent filed with the CPUC on August 1, 2005 indicated that the Utility's GRC application ~~will~~would request ~~an increase~~increases in electric and gas distribution revenue requirements of $393 million and $61 million, respectively, ~~over the projected authorized 2006 revenue requirements.~~and an increase of $48 million related to generation expenses and administrative costs associated with electric procurement activities. The ~~Utility has~~Utility's GRC application will include a proposed a mechanism to share savings with customers that may be achieved through implementation of specific initiatives the Utility has identified to ~~provide~~provid e better faster and more cost-effective service to its ~~customers.~~customers (See "Regulatory Matters" below).;
·	The Utility has requested that the CPUC approve various capital expenditures for electric and gas distribution infrastructure improvements, including the funding for installation of advanced meters, for potential investment in new generation resources, and for ongoing investments in its electric and gas transmission operations. As discussed below under "Capital Expenditures," it is estimated that the Utility's capital expenditures will approximate $1.9 billion in 2005 and $2.4 billion in 2006 (excluding the capitalized portion of a 2006 pension contribution), resulting in a projected rate base of $15.2 billion in 2005 and $16.2 billion in 2006;
·	In response to rising natural gas prices during the quarter, the CPUC permitted the Utility to implement additional hedging strategies to reduce the impact of higher prices on the Utility's residential and small commercial retail natural gas customers (referred to as core customers) and to reduce the impact of higher natural gas prices on the Utility's electric generation portfolio. For a further discussion see "Risk Management" below. Although there are ratemaking mechanisms in place to recover the Utility's natural gas costs, the Utility's implementation of the CPUC-approved hedging strategies is subject to reasonableness review. In addition, as customer rates rise in response to increasing gas and electricity prices, there may be greater pressure on the CPUC to disallow costs as unreasonable or to defer the Utility's recovery of costs; and
·	PG&E Corporation's and the Utility's future results of operation and financial condition ~~and results of operations will~~may also be affected by the ~~amount~~extent to which forecasted or estimated amounts or accrued liabilities differ from the amounts actually incurred for operations, including legal liabilities such as the Chromium Litigation discussed in "Part II, Item 1. Legal Proceedings" below and in Note 7 of ~~future capital expenditures~~ the Utility may make in long-term generation resource and infrastructure improvements. The Utility is evaluating initial bids that it has received from third parties to provide long-term generation resources (which may take the form of conventional or renewable resources to be provided under utility-owned projects or turnkey developments, or buyouts, or third party power purchase agreements) for approximately 1,200 megawatts, or MW, of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010. The Utility anticipates that contracts for the winning bidders will be submittedNotes to the ~~CPUC~~Consolidated Financial Statements, or for approval in the second half of 2005. (See "Regulatory Matters.") In addition, on June 17, 2005, the Utility filed an application with the CPUC to complete and operate, under a cost-of-service ratemaking structure, the Contra Costa Unit 8 facility, a proposed modern 530 MW power plant currently owned by Mirant Corporation. Also, on June 16, 2005, the Utility also requested the CPUC to approve an application for deployment of the Utility's full advanced metering infrastructure, or AMI, project at an estimated cost of $1.46 billion, which includes an estimated capital ~~cost of $1.26 billion, based on a five year installation schedule for virtually all of the Utility's electric and gas customers starting in 2006. (See "Capital Expenditures" below).~~expenditures.

In addition to the factors discussed above, PG&E Corporation's and the Utility's future financial condition and results of operations are subject to the uncertainties and risk factors discussed ~~below, as well as to the risk factors discussed in their 2004 Annual Report.~~below.

Forward-Looking Statements

This combined Quarterly Report on Form 10-Q, including the MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties the realization or resolution of which are outside of management's control. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts at the time the statements were made. These forward-looking statements are identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "might," ~~"will,"~~ "should," "would," "could," "goal," "potential" and similar expressions. Although 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:

Operating Environment

·	Unanticipated changes in operating expenses or capital expenditures, which may result in material differences between forecasted costs used to determine rates and actual costs incurred that in turn may affect the Utility's ability to earn its authorized rate of return;
·	The ~~level and volatility~~adequacy of ~~wholesale electricity and~~ natural gas supplies and the effect of increasing prices ~~and supplies,~~for natural gas on the Utility's electric generation portfolio and its natural gas distribution operations, the ability of the Utility to manage and respond to ~~the levels and volatility~~increasing natural gas costs successfully and ~~the extent to which the Utility is able~~ to timely ~~recover~~recovery of its natural gas costs and increased ~~costs related to such volatility;~~electricity procurement costs;
·	Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility's assets or operations or those of third parties on which the Utility relies, and the extent to which the Utility is able to timely recover costs related to such events;
·	Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;
·	The operation of the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure ~~outlays and, to the extent~~outlays;
·	Whether the Utility is ~~unable~~able to increase its spent nuclear fuel storage capacity at Diablo Canyon by 2007 by completing its dry cask storage project (the timing of which may be affected by the pending federal appeal of the license issued by the Nuclear Regulatory Commission, or ~~find~~NRC), by timely completing the construction of other on-site spent nuclear fuel storage alternatives, or by finding an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources, and the extent to which the Utility is able to timely recover related costs and expenses;
·	Actions of credit rating agencies;
·	Significant changes in the Utility's relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and
·	Acts of terrorism.

Legislative Actions and Regulatory ~~Environment~~Proceedings

·	The outcome of the regulatory proceedings pending at the CPUC and the FERC discussed in "Regulatory Matters" below, including the Utility's 2007 GRC, the Utility's request for a revenue requirement to fund pension contributions that may be required in the future, the outcome of the Utility's application for approval of capital expenditures, and the impact of ~~current and~~ future ratemaking actions ofby the CPUC ~~including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;~~
·	~~Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the FERC,~~ and the Nuclear Regulatory Commission, or the NRC, with regard to the Utility's allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;FERC;
·	The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons, resulting in write-offs of regulatory balancing accounts;
·	How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's decisions permitting the establishment of holding companies for the California investor-owned electric utilities;
·	The terms and conditions under which the CPUC authorizes the Utility to issue debt and equity in the future, and the extent to which the terms and conditions limit the Utility's ability to issue debt in the future;
·	Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses; and
·	Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies.

~~Pending Regulatory Proceedings and Litigation~~

·	Whether the assumptions and forecasts underlying the Utility's CPUC-approved long-term electricity procurement plan prove to be accurate, the terms and conditions of the generation or procurement commitments the Utility enters into in connection with its plan, the extent to which the Utility is able to recover the costs it incurs in connection with these commitments, and the extent to which a failure to perform by any of the counterparties to the Utility's electricity purchase contracts or the California Department of Water Resources, or the DWR, contracts allocated to the Utility's customers affects the Utility's ability to meet its obligations or to recover its costs;
·	The impact of the recently enacted Energy Policy Act of 2005 which, among other provisions, repeals the Public Utility Holding Company Act of 1935 making electric utility industry consolidation more possible and authorizing the FERC to review proposed mergers; changes the FERC regulatory scheme applicable to qualifying co-generation facilities; creates an Electric Reliability Organization to be overseen by the FERC to establish electric reliability standards; and modifies certain other aspects of energy regulations and Federal tax policies applicable to the Utility;
·	Future changes in governmental policies, legislative or regulatory actions by the California legislature, the U.S. Congress, the CPUC, the FERC, and the NRC, with regard to the structure of the electric industry and power markets, the Utility's allowed rates of return, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;
·	The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity or gas purchase costs from customers due to a regulatory determination that such costs were not reasonable or prudent, or for other reasons, resulting in write-offs of regulatory balancing accounts;
·	How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC's past decisions permitting the establishment of holding companies for the California investor-owned electric utilities and the outcome of the ~~regulatory proceedings pending at~~CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates, which may include (1) establishing reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changes to the CPUC's affiliate transaction rules;
·	The terms and conditions under which the CPUC authorizes the Utility to issue debt and ~~the FERC discussed in "Regulatory Matters" below, including the Utility's 2007 GRC and the Utility's request for a revenue requirement to fund pension contributions that may be required~~equity in the future;
·	Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses; and
·	Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies.

Pending Litigation

·	The outcome of pending litigation, including the outcome of the Chromium Litigation, as discussed below in "Part II, Item 1. Legal Proceedings" and in Note 7 of the Notes to the Consolidated Financial Statements; and
·	The timing and resolution of the pending appeals of the bankruptcy court order confirming the Utility's plan of reorganization under Chapter ~~11; and~~
·	The outcome of the litigation pending against the Utility in California state court involving allegations of injury allegedly caused by exposure to chromium at certain of the Utility's gas compressor stations and other pending litigation.11.

Competition and Bypass

Increased competition as a result of the ~~takeover~~continuing efforts by ~~condemnation of~~local public utilities to take over the Utility's distribution assets through exercise of their condemnation power or by duplication of the Utility's distribution assets or service, ~~by local public utilities,~~ and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

The extent to which the Utility's distribution customers are permitted to switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers become self-generators, results in stranded generating asset costs and non-recoverable procurement costs.

See the section entitled "Risk Factors" in PG&E Corporation's and the Utility's ~~combined~~ 2004 ~~Annual~~Financial Report for further discussion of 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.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Consolidated Statements of Income for the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 and 2004.

		Three Months Ended				Six Months Ended					Three Months Ended				Nine Months Ended
(in millions)	(in millions)	June 30,				June 30,				(in millions)	September 30,				September 30,

		2005		2004		2005		2004			2005		2004		2005		2004

Utility	Utility									Utility
Electric operating revenues	Electric operating revenues	$	1,780	$	2,063	$	3,439	$	3,851	Electric operating revenues	$	2,107	$	2,042	$	5,546	$	5,902
Natural gas operating revenues	Natural gas operating revenues	718		686		1,727		1,617		Natural gas operating revenues	697		581		2,424		2,198

Total operating revenues	Total operating revenues	2,498		2,749		5,166		5,468		Total operating revenues	2,804		2,623		7,970		8,100
Cost of electricity	Cost of electricity	487		685		884		1,254		Cost of electricity	742		792		1,626		2,003
Cost of natural gas	Cost of natural gas	347		278		967		857		Cost of natural gas	326		239		1,293		1,096
Operating and maintenance	Operating and maintenance	670		748		1,441		1,557		Operating and maintenance	738		671		2,179		2,271
Recognition of regulatory assets	Recognition of regulatory assets	-		-		-		(4,900)		Recognition of regulatory assets	-		-		-		(4,900)
Depreciation, amortization and decommissioning	Depreciation, amortization and decommissioning	454		352		839		650		Depreciation, amortization and decommissioning	481		405		1,320		1,054
Reorganization professional fees and expenses	Reorganization professional fees and expenses	-		4		-		6		Reorganization professional fees and expenses	-		-		-		6

Total operating (gain) expenses		1,958		2,067		4,131		(576)
Total operating expenses										Total operating expenses	2,287		2,107		6,418		1,530

Operating income	Operating income	540		682		1,035		6,044		Operating income	517		516		1,552		6,570
Interest income⁽¹⁾	Interest income⁽¹⁾	20		23		39		34		Interest income⁽¹⁾	20		11		59		44
Interest expense	Interest expense	(124)		(158)		(278)		(372)		Interest expense	(138)		(141)		(416)		(512)
Other income, net⁽²⁾		2		20		4		26
Other income (expense), net⁽²⁾										Other income (expense), net⁽²⁾	(7)		10		(3)		26

Income before income taxes	Income before income taxes	438		567		800		5,732		Income before income taxes	392		396		1,192		6,128
Income tax provision	Income tax provision	166		159		309		2,258		Income tax provision	148		152		457		2,410

Income available for common stock	Income available for common stock	$	272	$	408	$	491	$	3,474	Income available for common stock	$	244	$	244	$	735	$	3,718

PG&E Corporation, Eliminations and Other⁽³⁾	PG&E Corporation, Eliminations and Other⁽³⁾									PG&E Corporation, Eliminations and Other⁽³⁾
Operating revenues	Operating revenues	$	-	$	-	$	-	$	-	Operating revenues	$	-	$	-	$	-	$	-
Operating (gain) expenses	Operating (gain) expenses	-		10		(5)		20		Operating (gain) expenses	2		7		(2)		28

Operating income (loss)	Operating income (loss)	-		(10)		5		(20)		Operating income (loss)	(2)		(7)		2		(28)
Interest income	Interest income	(4)		2		(2)		5		Interest income	2		4		1		10
Interest expense	Interest expense	(7)		(18)		(14)		(34)		Interest expense	(7)		(18)		(22)		(53)
Other expense, net⁽²⁾	Other expense, net⁽²⁾	(4)		(34)		(7)		(67)		Other expense, net⁽²⁾	(7)		(6)		(13)		(72)

Income (loss) before income taxes		(15)		(60)		(18)		(116)
Loss before income taxes										Loss before income taxes	(14)		(27)		(32)		(143)
Income tax benefit	Income tax benefit	(10)		(24)		(12)		(47)		Income tax benefit	(9)		(11)		(21)		(58)

Net loss		$	(5)	$	(36)	$	(6)	$	(69)
Income (Loss) From Continuing Operations										Income (Loss) From Continuing Operations		(5)		(16)		(11)		(85)
Discontinued Operations										Discontinued Operations		13		-		13		-

Net Income (Loss)										Net Income (Loss)	$	8	$	(16)	$	2	$	(85)

Consolidated Total	Consolidated Total									Consolidated Total
Operating revenues	Operating revenues	$	2,498	$	2,749	$	5,166	$	5,468	Operating revenues	$	2,804	$	2,623	$	7,970	$	8,100
Operating (gain) expenses		1,958		2,077		4,126		(556)
Operating expenses										Operating expenses	2,289		2,114		6,416		1,558

Operating income	Operating income	540		672		1,040		6,024		Operating income	515		509		1,554		6,542
Interest income⁽¹⁾	Interest income⁽¹⁾	16		25		37		39		Interest income⁽¹⁾	22		15		60		54
Interest expense	Interest expense	(131)		(176)		(292)		(406)		Interest expense	(145)		(159)		(438)		(565)
Other expenses, net⁽²⁾		(2)		(14)		(3)		(41)
Other income (expense), net⁽²⁾										Other income (expense), net⁽²⁾	(14)		4		(16)		(46)

Income before income taxes	Income before income taxes	423		507		782		5,616		Income before income taxes	378		369		1,160		5,985
Income tax provision	Income tax provision	156		135		297		2,211		Income tax provision	139		141		436		2,352

Net income		$	267	$	372	$	485	$	3,405
Income From Continuing Operations										Income From Continuing Operations		239		228		724		3,633
Discontinued Operations										Discontinued Operations		13		-		13		-

Net Income										Net Income	$	252	$	228	$	737	$	3,633

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

Utility

Under cost of service ratemaking, the Utility's rates are determined based on its costs of service and are adjusted periodically to reflect differences between actual sales or demand compared to forecasted sales or demand used in setting rates. The Utility's electricity and natural gas distribution rates reflect the sum of individual revenue requirement components. The Utility collects base revenue requirements for the operation of its assets. In addition, the Utility recovers costs of purchasing gas and electricity on behalf of its customers. 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~~ 2004 ~~Annual~~Financial Report and below under "Regulatory Matters."

The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers (see further discussion in the Transportation and Storage section under Risk Management Activities of this MD&A). The Utility is also at risk for costs associated with meeting demand and maintaining electric transmission system sufficiency and reliability in the Utility's service area in excess of amounts allowed in its FERC-authorized transmission owner rates.

Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Consolidated Statements of Operations, reflecting the Utility's role as a billing and collection agent for the DWR's sales to the Utility's customers.

Electric Operating Revenues

The Utility records its electric distribution and generation revenues under cost-of-service revenue requirements approved by the CPUC in the Utility's 2003 GRC. As part of the GRC, the CPUC approved yearly adjustments to the Utility's 2003 base revenue requirements, or attrition adjustments, for 2004, 2005, and 2006 based on changes in the Consumer Price Index. The Utility's electric distribution and generation revenues for 2007 through 2009 will be determined in the 2007 GRC (see "Regulatory Matters" of this MD&A). Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts and are reflected in miscellaneous revenues in the table below.

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under the DWR allocated contracts, in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricit y.

The following table ~~shows~~provides a ~~breakdown~~summary of the Utility's electric operating revenues.

		Three Months Ended						Nine Months Ended
(in millions)		September 30,						September 30,

		2005			2004			2005			2004


Electric revenues			$	3,007		$	2,909		$	7,314		$	7,218
DWR pass-through revenue			(400)			(560)			(1,234)			(1,479)

Subtotal			2,607			2,349			6,080			5,739
Miscellaneous			(500)			(307)			(534)			163

Total electric operating revenues			$	2,107		$	2,042		$	5,546		$	5,902



Total electricity sales (in GWh)⁽¹⁾			23,306			22,932			61,572			61,313




(1)	Includes DWR electricity sales.

Three Months Ended
Six Months Ended
(in millions)
June 30,
June 30,
2005
2004
2005
2004
Electric revenues
$
2,223
$
2,140
$
4,307
$
4,309
DWR pass-through revenue
(388)
(449)
(834)
(919)
Subtotal
1,835
1,691
3,473
3,390
Miscellaneous
(55)
372
(34)
461
Total electric operating revenues
$
1,780
$
2,063
$
3,439
$
3,851
Total electricity sales (in GWh)⁽¹⁾
19,232
19,511
38,266
38,381
(1)
Includes DWR electricity sales.

For the three months ended ~~June~~September 30, 2005, the Utility's electric operating revenues ~~decreased~~increased approximately ~~$283~~$65 million, or ~~14%~~3%, compared to the same period in 2004 mainly due to the following factors:

·	The Utility is authorized to collect and remit a dedicated rate component, or DRC, from its electricity customers to repay the ERBs until they are fully retired in 2012. Also, in connection with the issuance of the ERBs, the Utility has established a balancing account, the Energy Recovery Bond Balancing Account, or ERBBA, to track various costs and benefits associated with the ERBs (see further discussion in "Regulatory Matters"). The DRC charge and revenue requirements associated with the ERBBA resulted in an increase of approximately $140 million in electric operating revenues for the three months ended September 30, 2005, with no similar amount for the same period in 2004;
·	Attrition revenues as authorized in the 2003 GRC and revenues authorized in the 2004 cost of capital proceeding resulted in an increase in electric operating revenues of approximately $25 million for the three months ended September 30, 2005, as compared to the same period in 2004; and
·	Miscellaneous other electric operating revenues, including revenues associated with public purpose programs, sales for resale, and rent from electric property, increased approximately $120 million in the three months ended September 30, 2005, as compared to the same period in 2004.

The above increases were partially offset by the following decreases to electric operating revenues:

·	Electric operating revenues decreased approximately ~~$230~~$100 million during the three months ended ~~June~~September 30, 2005, as compared to the same period in 2004, primarily due to lower electricity procurement and transmission costs, which are passed through to customers; and
·	Electric operating revenues decreased approximately $120 million as a result of a decrease in the revenue requirement associated with the Settlement Regulatory Asset. As a result of the refinancing of the Settlement Regulatory Asset on February 10, 2005 through issuance of the ERBs, the Utility was no longer authorized to collect this revenue requirement (see further discussion in the Overview to this MD&A and Note 4 of the Notes to the Condensed Consolidated Financial Statements)~~; and~~
·	The approval of the Utility's 2003 GRC in May 2004 resulted in the Utility recording revenues intended to cover the six month period ended June 30, 2004 during the second quarter of 2004. As a result, although the Utility received attrition revenues to adjust for wages and inflation for the three months ended June 30, 2005 as authorized in the 2003 GRC and an increase in revenues as a result of the 2004 cost of capital proceeding, total GRC and cost of capital revenues for the three month period ended June 30, 2005 were approximately $45 million lower than in the same period in 2004..

~~The above decreases were partially offset by the following increase to electric operating revenues:~~

The Utility is authorized to collect and remit a DRC from its electricity customers to repay the ERBs until they are fully retired. Also in connection with the issuance of the ERBs, the Utility has established a balancing account, the Energy Recovery Bond Balancing Account, or ERBBA, to track various costs and benefits associated with the ERBs (see further discussion in "Regulatory Matters"). The DRC charge and revenue requirements associated with the ERBBA resulted in an approximately $115 million electric operating revenue increase for the three months ended June 30, 2005, with no similar amount in the same period in 2004.

For the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility's electric operating revenues decreased approximately ~~$412~~$356 million, or ~~11%~~6%, compared to the same period in 2004 due to the following factors:

Electric operating revenues decreased approximately ~~$400~~$500 million ~~during the six months ended June 30, 2005, as~~ compared to the same period in 2004, primarily due to lower electricity procurement and transmission costs which are passed through to customers; and

Electric operating revenues decreased ~~$195~~approximately $310 million as a result of a decrease in the revenue requirement associated with the Settlement Regulatory Asset. As a result of the refinancing of the Settlement Regulatory Asset on February 10, 2005 through issuance of the ERBs, the Utility was no longer authorized to collect this revenue requirement (see further discussion in the Overview to this MD&A and Note 4 of the Notes to the Condensed Consolidated Financial Statements).

The above decreases were partially offset by the following increases to electric operating revenues:

·	Attrition revenues as authorized in the 2003 GRC and revenues authorized in the 2004 cost of capital proceeding resulted in an increase in electric operating revenues of approximately ~~$60~~$70 million for the ~~six~~nine months ended ~~June~~September 30, 2005, as compared to the same period in 2004; ~~and~~
·	The Utility's collection of the DRC charge and revenue requirements associated with the ERBBA resulted in an increase of approximately ~~$135~~$295 million in electric operating revenue increase for the ~~six~~nine months ended ~~June~~September 30, 2005, with no similar amount in the same period in 2004; and
·	Miscellaneous other electric operating revenues, including revenues associated with public purpose programs, sales for resale, and revenues associated with the Rate Reduction Bonds, increased approximately $90 million in the nine months ended September 30, 2005, as compared to the same period in 2004.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities, but excludes costs to operate the Utility's generation facilities, which are included in operating and maintenance expense. Electricity purchase costs and the cost of fuel used by owned generation facilities are passed through in rates to customers. The following table ~~shows~~provides a ~~breakdown~~summary of the Utility's cost of electricity and the total amount and average cost of purchased power, excluding in each case both the cost and volume of electricity provided by the DWR to the Utility's customers:

	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
(in millions)	June 30,				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Cost of purchased power	$	575	$	694	$	1,029	$	1,283	$	798	$	787	$	1,827	$	2,027
Proceeds from surplus sales allocated to the Utility	(132)		(35)		(233)		(98)		(98)		(35)		(331)		(133)
Fuel used in own generation	44		26		88		69		42		40		130		109

Total net cost of electricity	$	487	$	685	$	884	$	1,254	$	742	$	792	$	1,626	$	2,003

Average cost of purchased power per GWh	$	0.072	$	0.076	$	0.069	$	0.079	$	0.081	$	0.085	$	0.074	$	0.079

Total purchased power (GWh)	7,944		9,185		14,929		16,279		9,848		9,310		24,779		25,589

During the ~~three and six-month periods~~nine-months ended ~~June~~September 30, 2005, the Utility produced more electricity from its own generation facilities, thereby reducing the amount of electricity the Utility was required to purchase for its customers. ~~During~~Also, during the ~~three~~nine months ended ~~June~~September 30, 2005, the Utility's Diablo Canyon power plant was in full operation compared to the same period in 2004 when an approximately 6977 day ~~scheduled~~ refueling outage at Diablo Canyon required the Utility to purchase replacement power. ~~Also, due to above average rainfall during 2005, the Utility's hydroelectric generation facilities produced more electricity.~~ In addition, as of January 1, 2005, the Utility was no longer required to procure electricity for customers of the Western Area Power Administration. As a result, the Utility's cost of electricity decreased ~~significantly~~ in 2005 as compared to 2004.

During the three months ended ~~June~~September 30, 2005, the Utility's cost of electricity decreased approximately ~~$198~~$50 million, or ~~29%~~6%, compared to 2004 mainly due to the following factors:

·	The decrease in total purchased power of 1,241 gigawatt hours, or GWh, and the decrease in the average cost of purchased power of $0.004 per GWh in 2005 as compared to the same period in 2004 resulted in a decrease of approximately $119 million in the cost of purchased power; and
·	The increase in proceeds from surplus sales allocated to the Utility of ~~$97~~$63 million in the three months ended ~~June~~September 30, 2005, as compared to the same period in 2004, resulted in a corresponding decrease in the cost of electricity. The increase in proceeds from surplus sales was primarily a result of above average rainfall during 2005 which increased surplus conditions.
Partially offsetting this decrease was the following increase:
·	The increase in total purchased power, as compared to the same period in 2004, resulted in an increase of approximately $11 million in the cost of purchased power. The increase in total purchased power was primarily due to above average rainfall during 2005 which increased hydro runoff production.

During the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility's cost of electricity decreased approximately ~~$370~~$377 million, or ~~30%~~19%, compared to 2004, mainly due to the following factors:

·	The decrease in total purchased power of 1,350 GWh and the decrease in the average cost of purchased power of $0.010 per GWh in 2005 as compared to the same period in 2004 resulted in a decrease of approximately $254 million in the cost of purchased power; and
·	The increase in proceeds from surplus sales allocated to the Utility of ~~$135~~$198 million in the ~~six~~nine months ended ~~June~~September 30, 2005, as compared to the same period in 2004, resulted in a corresponding decrease in the cost of ~~electricity.~~electricity; and
·	The decrease in total purchased power and the decrease in the average cost of purchased power of $0.005 per GWh in 2005, as compared to the same period in 2004, resulted in a decrease of approximately $200 million in the cost of purchased power.

Natural Gas Operating Revenues

The Utility sells natural gas and provides natural gas transportation services to its customers. The Utility's natural gas customers consist of two categories: core and ~~noncore~~non-core customers. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The ~~noncore~~non-core customer class is comprised of industrial and larger commercial natural gas customers. The Utility provides natural gas delivery services to all core and ~~noncore~~non-core customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. While the Utility provides non-core customers with delivery service, it does not provide non-core customers with natural gas supply. When the Utility provides both supply and delivery, the Utility refers to ~~the s ervice~~th e service as natural gas bundled service. In 2004, core customers represented over 99% of the Utility's total customers and approximately 35% of its total natural gas deliveries, while ~~noncore~~non-core customers comprised less than 1% of the Utility's total customers and approximately 65% of its total natural gas deliveries.

The Utility's transportation system transports gas throughout California to the Utility's distribution system, which, in turn, delivers gas to end-use customers. Utility transportation and distribution services for all customers have historically been bundled or sold together at a combined rate.

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

	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
(in millions)	June 30,				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Bundled natural gas revenues	$	665	$	615	$	1,609	$	1,482	$	640	$	524	$	2,249	$	2,006
Transportation service-only revenues	53		71		118		135		57		57		175		192

Total natural gas operating revenues	$	718	$	686	$	1,727	$	1,617	$	697	$	581	$	2,424	$	2,198

Average bundled revenue per millions of Mcf of natural gas sold	$	11.33	$	12.00	$	9.68	$	9.07	$	16.20	$	13.48	$	10.93	$	9.92

Total bundled natural gas sales (in millions of Mcf)		59		51		167		163		40		39		207		202

The Utility's natural gas operating revenues increased approximately ~~$32~~$116 million, or 5%20%, during the three months ended ~~June~~September 30, 2005, compared to the same period in 2004 as a result of the following:

Excluding the impact of the ~~adjustments to 2004 revenues as a result of the~~ 2003 GRC decision and 2004 cost of capital proceeding discussed below, bundled natural gas operating revenues increased approximately ~~$120~~$113 million, or ~~22%~~21%, in the three months ended ~~June~~September 30, 2005 as compared to the same period in 2004. This increase was primarily ~~a result of~~due to an increase in ~~volume~~the cost of ~~approximately eight million Mcf, or thousand cubic feet, or 16%, combined with~~natural gas resulting in an increase in the average bundled revenue per millions of Mcf of natural gas sold of approximately ~~$0.60~~$2.49 per millions of Mcf, or 6%18%, ~~resulting from increases~~combined with an increase in ~~the cost~~volume of ~~natural gas,~~approximately 1 million Mcf, or thousand cubic feet, or 3%, for the three months ended ~~June~~September 30, ~~2005.~~

~~Partially offsetting this increase were the following decreases:~~

The approval of the 2003 GRC in May 2004 resulted in the Utility recording approximately $50 million in revenues related to 2003 in the second quarter of 2004 with no comparable amount in 2005. Also as a result of the 2003 GRC decision, the Utility recorded approximately $20 million in revenues related to the first quarter of 2004 in the second quarter of 2004, with no comparable amount in 2005; and

~~Transportation service-only~~Attrition revenues ~~decreased approximately $18 million, or 25%,~~as authorized in the ~~second quarter~~2003 GRC and revenues authorized in the 2004 cost of capital proceeding resulted in an increase in natural gas operating revenues of approximately $3 million for the three months ended September 30, 2005, as compared to the same period in 2004.

The Utility's natural gas operating revenues increased approximately ~~$110~~$226 million, or 7%10%, for the ~~six~~nine months ended ~~June~~September 30, 2005 compared to the same period in 2004 as a result of the following:

Excluding the impact of the ~~adjustments to 2004 revenues as a result of the~~ 2003 GRC decision and 2004 cost of capital proceeding discussed below, bundled natural gas operating revenues increased approximately ~~$177~~$278 million, or ~~12%~~14%, in the ~~six~~nine months ended ~~June~~September 30, 2005 as compared to the same period in 2004. This increase was primarily ~~a result~~due to an increase in the cost of natural gas resulting in an increase in the average bundled revenue per millions of Mcf of natural gas sold of approximately ~~$0.85~~$1.11 per millions of Mcf, or ~~10%~~11%, ~~resulting from increases in the cost of natural gas,~~ combined with an increase in volume of approximately ~~four~~5 million Mcf, or 2%, for the ~~six~~nine months ended ~~June~~September 30, 2005; and

Attrition revenues as authorized in the 2003 GRC and revenues authorized in the 2004 cost of capital proceeding resulted in an increase in natural gas operating revenues of approximately $15 million for the nine months ended September 30, 2005, as compared to the same period in 2005.

Partially offsetting ~~this increase~~these increases were the following decreases:

·	The approval of the 2003 GRC in May 2004 resulted in the Utility recording approximately $50 million in revenues related to 2003 in the second quarter of 2004 with no comparable amount in 2005; and
·	Transportation service-only revenues decreased approximately $17 million, or ~~13%~~9%, in the ~~six~~nine months ended ~~June~~September 30, 2005 as compared to the same period in ~~2004.~~2004, primarily as a result of a decrease in rates.

Cost of Natural Gas

The Utility's cost of natural gas includes the costs to purchase natural gas and the costs to transport natural gas on interstate pipelines, but excludes the costs associated with the Utility's intrastate ~~pipeline,~~pipelines, which are included in operating and maintenance expense. The following table ~~shows~~provides a ~~breakdown~~summary of the Utility's cost of natural gas:

	Three Months Ended				Six Months Ended				Three Months Ended				Nine Months Ended
(in millions)	June 30				June 30,				September 30,				September 30,

	2005		2004		2005		2004		2005		2004		2005		2004

Cost of natural gas sold	$	313	$	247	$	896	$	790	$	293	$	209	$	1,189	$	999
Cost of natural gas transportation	34		31		71		67		33		30		104		97

Total cost of natural gas	$	347	$	278	$	967	$	857	$	326	$	239	$	1,293	$	1,096

Average cost per millions of Mcf of natural gas sold	$	5.31	$	4.84	$	5.37	$	4.85	$	7.33	$	5.36	$	5.74	$	4.95

Total natural gas sold (in millions of Mcf)		59		51		167		163		40		39		207		202

In the three months ended ~~June~~September 30, 2005, the Utility's total cost of natural gas increased approximately ~~$69~~$87 million, or ~~25%~~36%, compared to the same period in 2004 primarily due to an increase in the average market price of natural gas purchased of approximately ~~$0.47~~$1.97 per millions of Mcf, or ~~10%~~37%, combined with an increase in volume of 8natural gas sold of 1 million Mcf, or ~~16%~~3%.

In the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility's total cost of natural gas increased approximately ~~$110~~$197 million, or ~~13%~~18%, compared to the same period in 2004 primarily due to an increase in the average market price of natural gas purchased of approximately ~~$0.52~~$0.79 per millions of Mcf, or ~~11%~~16%, combined with an increase in volume of ~~4 million~~5 Mcf, or 2%.

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.

During the three months ended ~~June~~September 30, 2005, the Utility's operating and maintenance expenses ~~decreased~~increased by approximately ~~$78~~$67 million, or 10%, as compared to the same period in 2004, mainly due to the following factors:

·	Operating and maintenance expenses ~~decreased~~increased approximately ~~$40~~$21 million ~~at Diablo Canyon~~related to an increase in the three months ended June 30, 2005, as compared to the same period in 2004, reflecting the scheduled refueling outage in the second quarter of 2004 with no similar refueling outage in the same period in 2005;customer rebates and administration expenses for low-income customer assistance programs and community outreach projects;
·	Operating and maintenance expenses ~~decreased~~increased approximately ~~$15~~$27 million related to an increase in gas transportation charges primarily as a result of rate increases for ~~the three months ended June 30, 2005, as compared~~pipeline demand and transportation; and
·	Operating and maintenance expenses increased approximately $16 million related to ~~the same period~~an increase in ~~2004~~consulting, contract and legal expenses reflecting increased use of outside services due to ~~decreases in employee benefit plan related expenses in 2005.~~various programs and initiatives.

During the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility's operating and maintenance expenses decreased by approximately ~~$116~~$92 million, or 7%4%, as compared to the same period in 2004, mainly due to the following factors:

·	Operating and maintenance expenses decreased approximately $30 million related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and the donation of land in 2004, with no similar amounts for the same period in 2005;
·	Operating and maintenance expenses decreased approximately $50 million at Diablo Canyon in the ~~six~~nine months ended ~~June~~September 30, 2005, as compared to the same period in 2004, reflecting costs associated with the scheduled refueling outage in the ~~six~~nine months ended ~~June~~September 30, 2004, with no similar refueling outage in the same period in 2005; and
·	Operating and maintenance expenses decreased approximately $30 million for the ~~six~~nine months ended ~~June~~September 30, 2005, as compared to the same period in 2004, due to expenses paid on behalf of the CPUC for its professional fees incurred in connection with the Chapter 11 proceeding with no similar amount in 2005.

Partially offsetting this decrease was the following increase:

·	Operating and maintenance expenses increased approximately $18 million related to an increase in consulting and legal expenses reflecting increased use of outside services due to various programs and initiatives.

Recognition of Regulatory Assets

In light of the satisfaction of various conditions to the implementation of the Utility's plan of reorganization, the Utility recorded the regulatory assets provided for under the settlement agreement in the first quarter of 2004. This resulted in the recognition of a one-time non-cash, pre-tax gain of $3.7 billion for the Settlement Regulatory Asset and $1.2 billion for the Utility retained generation regulatory assets, for a total after-tax gain of $2.9 billion.

Depreciation, Amortization and Decommissioning

In the three months ended ~~June~~September 30, 2005, the Utility's depreciation, amortization and decommissioning expenses increased by ~~approximately $102~~$76 million, or ~~29%~~19%, compared to the same period in 2004, primarily as a result of amortization of the ERB regulatory asset of approximately $70 million with no similar amount in 2004.

In the nine months ended September 30, 2005 the Utility's depreciation, amortization and decommissioning expenses increased approximately $266 million, or 25%, compared to the same period in 2004, primarily as a result of the following factors:

·	The Utility recorded approximately ~~$60~~$140 million for amortization of the ERB regulatory asset with no similar amount in 2004;
·	As a result of the 2003 GRC decision in May 2004 authorizing lower depreciation rates, the Utility recorded an approximately $37 million decrease to depreciation expense related to 2003 in the second quarter of 2004 with no similar reduction in the same period in 2005. The Utility also recorded an approximately $20 million reduction to depreciation expense related to the first quarter of 2004 during the second quarter of 2004 as a result of the 2003 GRC decision with no similar reduction in 2005; and
·	~~Depreciation expense increased approximately $10 million as a result of plant additions during the three months ended June 30, 2005.~~

Partially offsetting these increases was a decrease in decommissioning expense during the three months ended June 30, 2005, as compared to the same period in 2004. The Utility recorded approximately $30 million for decommissioning expense relating to 2003 as authorized in the 2003 GRC decision in May 2004, with no similar amount in the three months ended June 30, 2005.

In the six months ended June 30, 2005, the Utility's depreciation, amortization and decommissioning expenses increased by approximately $189 million, or 29%, compared to the same period in 2004, primarily as a result of the following factors:

·	~~The Utility recorded approximately $70 million for amortization of the ERB regulatory asset with no similar amount in 2004;~~
·	Amortization of the settlement regulatory assets increased approximately ~~$50~~$30 million in the ~~six~~nine months ended ~~June~~September 30, 2005 as compared to the same period in 2004. This increase is mainly due to the settlement regulatory assets being amortized over a ~~three-month~~six-month period in 2004 as compared to a ~~six-month~~nine-month period in 2005 combined with a change in the amortization methodology. In 2004 and prior to the issuance of the ERBs in 2005, the Settlement Regulatory Asset was amortized mortgage-style over a nine year period. After issuance of the ERBs, amortization of the Settlement Regulatory Asset fluctuates based on the DRC charge, which changes throughout the year due to fluctuations in volume and seasonality, and various expenses associated with the ERBs (see further discussion in "Regulatory Matters");
·	As a result of the 2003 GRC decision in May 2004 authorizing lower depreciation rates, the Utility recorded an approximately $37 million decrease to depreciation expense related to 2003 in the second quarter of 2004 with no similar reduction in the ~~six months ended June 30,~~same period in 2005; and
·	~~Depreciation increased approximately $20 million~~The remaining increase is primarily due to an increase in depreciation expense as a result of plant ~~additions during the six months ended June 30, 2005.~~additions.

Interest Income

In the three ~~months~~and nine-months ended June 30, 2005, interest income, including reorganization interest income, decreased by approximately $3 million, or 13%, compared to the same period in 2004 primarily due to interest income recorded to the ERBBA (see further discussion in "Regulatory Matters") retroactive to February 10, 2005 upon issuance of the ERBs.

~~In the six months ended June~~September 30, 2005, interest income, including reorganization interest income, increased by approximately $5$9 million and $15 million, respectively, or ~~15%~~82% and 34%, respectively, compared to the same ~~period~~periods in ~~2004. This increase is a result of an increase in~~2004, primarily due to higher average interest rates ~~during~~on the ~~period partially offset by interest recorded to the ERBBA as discussed above.~~Utility's short-term investments.

The Utility discontinued reporting in accordance with the American Institute of Certified Public Accountants' Statement of Position, or SOP, 90-7, "Financial ~~Reporting~~reporting by Entities in Reorganization Under the Bankruptcy Code," or SOP 90-7, upon its emergence from Chapter 11. Prior to that date, the Utility reported reorganization interest income separately on its Consolidated Statements of Income. Reorganization income reported in 2004 mainly included interest earned on cash accumulated during the Utility's Chapter 11 proceedings.

Interest Expense

In the three months ended ~~June~~September 30, 2005, the Utility's interest expense decreased by approximately ~~$34~~$3 million, or ~~22%~~2%, compared to the same period in 2004, primarily as a result of the following factors:

·	A decrease of approximately $25 million due to a lower average amount of debt outstanding and as a result of interest recorded to the ERBBA as a result of settlements with various power suppliers (see "Regulatory Matters" and Note 7 of the Notes to the Condensed Consolidated Financial Statements).

Partially offsetting this decrease was the following increase:

·	An increase of approximately $20 million related to interest associated with the ERBs which were issued on February 10, 2005, with no similar amount in 2004.

In the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility's interest expense decreased by approximately ~~$94~~$96 million, or ~~25%~~19%, compared to the same period in 2004, primarily ~~due to a lower average amount of debt outstanding and~~ as a result of ~~settlements with various power suppliers as discussed above.~~the following factors:

·	A decrease of approximately $200 million due to a lower average amount of debt outstanding and as a result interest recorded to the ERBBA as a result of settlements with various power suppliers (see "Regulatory Matters" and Note 7 of the Notes to the Condensed Consolidated Financial Statements).

Partially offsetting this decrease were the following increases:

·	An increase of approximately $60 million related to the interest on the First Mortgage Bonds/Senior Notes issued on March 23, 2004. This increase was mainly due to the First Mortgage Bonds/Senior Notes being outstanding over a six-month period in 2004 as compared to a nine-month period in 2005; and
·	An increase of approximately $51 million related to interest associated with the ERBs which were issued on February 10, 2005, with no similar amount in 2004.

Income Tax Expense

In the three months ended June 30, 2005, the Utility's tax expense increased approximately $7 million, or 4%, compared to the same period in 2004, mainly due to the tax effects of a tax regulatory asset related to the 2003 GRC recorded in the second quarter of 2004, offset by a decrease in pre-tax income of approximately $129 million for the three months ended June 30, 2005.

~~In the six months ended June~~September 30, 2005, the Utility's tax expense decreased approximately ~~$2 billion,~~$4 million, or ~~86%~~3%, compared to the same period in 2004, mainly due to a decrease in pre-tax income of $4 million and additional fixed asset deductions, for the three months ended September 30, 2005.

In the nine months ended September 30, 2005, the Utility's tax expense decreased approximately $2.0 billion, or 81%, compared to the same period in 2004, mainly due to a decrease in pre-tax income of approximately $4.9 billion for the ~~six~~nine months ended ~~June~~September 30, 2005. This decrease is primarily the result of the recognition of regulatory assets associated with the Settlement Agreement for the ~~six~~nine months ended ~~June~~September 30, 2004 with no similar amount recognized in ~~the same period in~~ 2005.

PG&E Corporation, Eliminations and ~~Others~~Other

Operating Revenues and Expenses

PG&E Corporation's revenues consist mainly of billings to the Utility and its other 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 its affiliates. ~~These allocations are made without mark-up.~~ Operating expenses are allocated to affiliates without mark-up and are eliminated in consolidation.

InFor the three months ended ~~June~~September 30, 2005, PG&E Corporation's operating expenses decreased by ~~$10~~approximately $5 million, or 71%, compared to the same period in 2004, primarily due to a reduction of general and administrative expenses retained at PG&E ~~Corporation.~~Corporation, along with a decrease in depreciation expense. The decrease in operating expenses of approximately ~~$25~~$30 million, or 107%, for the ~~six~~nine months ended ~~June~~September 30, 2005, compared to the same period in 2004, was primarily due to the receipt of insurance proceeds for legal costs and a reduction in general and administrative expenses retained at PG&E Corporation.

Interest Expense

PG&E Corporation's interest expense is not allocated to its affiliates. InFor the ~~second quarter of~~three months ended September 30, 2005, PG&E Corporation's interest expense decreased by approximately $11 million, or 61%, compared to the same period in 2004. For the ~~six~~nine months ended ~~June~~September 30, 2005, PG&E Corporation's interest expense decreased by approximately ~~$20~~$31 million, or ~~59%~~58%, compared to the same period in 2004. ~~The decreases during these periods compared to the same periods in 2004~~These fluctuations were primarily due to a reduction in the amount of outstanding debt, ~~due to~~as a result of the redemption of PG&E Corporation's 6⅞% Senior Secured Notes due 2008, $600 million principal amount, on November 15, ~~2004.~~2004, along with, for the nine months ended September 30, 2005, an increase in interest expense related to an interest payment PG&E Corporation made to the Utility for a refund received from the Internal Revenue Service, or IRS, for the 1999 and 2000 consolidated federal income tax returns.

Other Income (Expense)

PG&E Corporation's other expense ~~decreased~~increased by approximately ~~$30~~$1 million, or ~~88%~~17%, ~~and $60 million, or 90%, in~~for the three ~~and six~~ months ended ~~June~~September 30, 2005, ~~respectively,~~ compared to the same ~~periods~~period in ~~2004. These decreases were~~2004, primarily due to an increase in a pre-tax charge to earnings related to the changes in the market value of non-cumulative dividend participation rights included within PG&E Corporation's Convertible Subordinated Notes. In the nine months ended September 30, 2005, PG&E Corporation's other expense decreased by approximately $59 million, or 82%, primarily due to a reduction in the pre-tax charge to earnings related to ~~the~~ changes in market value of non-cumulative dividend participation rights included within PG&E Corporation's Convertible Subordinated Notes compared to the change in ~~2004.~~market value for the same period in the prior year.

Discontinued Operations

During the third quarter of 2005, PG&E Corporation received additional information from National Energy and Gas Transmission, Inc., or NEGT, regarding income to be included in PG&E Corporation's 2004 federal income tax return. This information was incorporated in the 2004 tax return, which was filed with the IRS in September 2005. As a result, the 2004 federal income tax liability was reduced by approximately $19 million. In addition, NEGT provided additional information with respect to amounts previously included in PG&E Corporation's 2003 federal income tax return. This change resulted in PG&E Corporation's 2003 federal income tax liability increasing approximately $6 million. These two adjustments, netting to $13 million, were recognized in income from discontinued operations in the third quarter of 2005.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The level of PG&E Corporation's and the Utility's current assets and current liabilities is subject to fluctuation as a result of seasonal demand for electricity and natural gas, energy commodity costs, and the timing and effect of regulatory decisions and financings, among other factors.

With the achievement of a 52% equity ratio in January 2005, the Utility reinstated the payment of a regular quarterly dividend. In addition, during the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility used cash (including the ERB proceeds) in excess of amounts needed for operations, debt service and repayment, ~~base~~ capital expenditures, and the payment of a quarterly dividend, to repurchase common stock. In turn, PG&E Corporation used the cash received from the Utility in the form of dividends and share repurchases to recommence the payment of a regular quarterly dividend and repurchase common stock from shareholders.

~~Liquidity~~

PG&E Corporation and the Utility intend to retain sufficient cash for operating needs and to manage debt levels to maintain access to credit. PG&E Corporation and the Utility target cash balances, which together with credit facilities, accommodate normal and unforeseen demands on ~~its~~their liquidity.

At ~~June~~September 30, 2005, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately ~~$1.5~~$1.2 billion, and restricted cash of approximately ~~$1.7~~$1.5 billion. PG&E Corporation and the Utility maintain separate bank accounts. At ~~June~~September 30, 2005, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately ~~$354~~$377 million. At ~~June~~September 30, 2005, the Utility had cash and cash equivalents of approximately ~~$1.1 billion,~~$856 million, and restricted cash of approximately ~~$1.7~~$1.5 billion. The Utility's restricted cash includes amounts deposited in escrow related to the remaining disputed Chapter 11 claims, collateral required by the California Independent System Operator, or ISO, and deposits under certain ~~third party~~third-party agreements.

PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

The Utility seeks to maintain or strengthen its credit ratings to provide efficient access to financial and trade credit, ~~and~~ to ensure adequate ~~liquidity.~~liquidity, and to reduce financing cost. As of ~~June~~September 30, 2005, ~~PG&E Corporation's and~~ the ~~Utility's~~ credit ratings on various financing instruments from Moody's Investors Service, or Moody's, and Standard & Poor's Rating Service, or S&P, ~~and Moody's Investors Service, or Moody's,~~ were as follows:

	Moody's	S&P

Utility

Corporate credit rating	Baa1⁽¹⁾	BBB⁽²⁾
Senior unsecured debt	Baa1⁽³⁾⁽⁴⁾	BBB⁽³⁾
Pollution control bonds backed by bond insurance	Aaa	AAA
Pollution control bonds backed by ~~Letters~~letters of ~~Credit~~credit	--	AA-/A-1+
Credit facility	--	BBB
Preferred ~~Stock~~stock	Baa3⁽⁵⁾	BB+⁽⁵⁾

PG&E Funding LLC

Rate ~~Reduction Bonds~~reduction bonds	Aaa	AAA

PG&E Energy Recovery Funding LLC

Energy ~~Recovery Bonds~~recovery bonds	Aaa	AAA

PG&E Corporation

Corporate credit rating	Baa3	--⁽²⁾⁽⁷⁾
Credit facility	Baa3⁽⁶⁾	--

Upgraded on March 3, 2005 from Baa3.
Upgraded on February 16, 2005 from BBB-. ~~S&P has not assigned a rating to PG&E Corporation.~~
~~Affirmed BBB senior secured rating on February 16, 2005.~~ As discussed in Note 3 in the Notes to the Condensed Consolidated Financial Statements, on April 22, 2005, the lien of the indenture securing the First Mortgage Bonds was released following confirmation by Moody's and S&P that the Utility's unsecured debt would be rated BBB by S&P and Baa1 by Moody's after the release of the lien.
Upgraded on March 3, 2005 from (P)Baa3.
Upgraded on March 3, 2005 from Ba2 by Moody's and on February 16, 2005 from BB by S&P.
Assigned on March 3, 2005.

S&P has not assigned a rating to PG&E ~~Corporation and the Utility have taken advantage of recent favorable market conditions by completing the following transactions:~~

·	On April 8, 2005, the Utility refinanced its existing $850 million working capital facility with a $1 billion working capital facility that has a term of 5 years, reduced fees and applicable margins, and less restrictive covenants;
·	On April 22, 2005, the Utility entered into an amendment to four reimbursement agreements totaling $620 million related to letters of credit that had been issued to support certain pollution control bonds aggregating $614 million issued on behalf of the Utility. In addition to containing more favorable provisions, the term of the amended agreements has been extended from three years to five years until April 22, 2010;
·	On May 24, 2005, the Utility entered into seven separate loan agreements with the California Infrastructure and Economic Development Bank to issue seven series of tax-exempt pollution control bonds, or PC Bonds Series A-G, of approximately $454 million. The funds received by the Utility were used to repay an approximately $454 million loan outstanding under the $1 billion working capital facility; and
·	On April 8, 2005, PG&E Corporation's unsecured $200 million credit facility was amended to include an extended 5-year term, expiring on December 10, 2009 and to conform the provisions regarding covenants, representations and events of default to those contained in the Utility's $1 billion working capital facility.

Corporation.

Currently, PG&E Corporation and the Utility have credit facilities totaling $200 million and $1.65 billion, respectively. As of September 30, 2005, PG&E Corporation and the Utility's available limits on these credit facilities are $200 million and $1.598 billion, respectively.

On ~~July 26, 2005,~~August 31, the Utility ~~sent notice to holders of~~redeemed all of the outstanding shares of the Utility's 7.04% Redeemable First Preferred Stock, totaling approximately $36 million aggregate par value ~~that the issue will be redeemed on August 31, 2005. In addition~~plus approximately $1 million related to ~~the $25.70 per share~~a $0.70 redemption ~~price, holders of the 7.04% Redeemable First Preferred Stock will be entitled to receive an amount equal to all accumulated and unpaid dividends on such shares to and including August 31, 2005.~~premium.

Dividends

On ~~June 15,~~September 21, 2005, the Board of Directors of the Utility declared a dividend of approximately ~~$118~~$117 million that was paid on ~~June 16,~~September 22, 2005 to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that held approximately 7% of the Utility's common stock.

PG&E Corporation ~~charged~~recorded dividends declared to Accumulated Earnings and the Utility ~~charged~~recorded dividends declared to Reinvested Earnings.

On October 19, 2005, the PG&E Corporation Board of Directors approved an annual cash dividend target of $1.32 per share ($0.33 quarterly), an increase from the previously approved target of $1.20 per share that reflects the improved financial performance of PG&E Corporation, but balances the forecast level of Utility capital investments. The new target is consistent with the previously approved dividend policy and dividend payout ratio range (the proportion of earnings paid out as dividends) of 50% to 70%. The Board of Directors retains authority to change its common stock dividend policy and its dividend payout ratio at any time, especially if unexpected events occur that would change the Board's views as to the prudent level of cash conservation. No dividend is payable until declared by the Board of Directors. The Board of Directors expects to declare a quarterly common stock dividend of $0.33 per share based on the new target at its meeting in December 2005.

Stock Repurchases

~~On February 22, 2005, under an accelerated share repurchase arrangement entered into on December 15, 2004,~~ PG&E Corporation ~~paid GS&Co. approximately $14 million as~~previously disclosed that (i) it anticipated it would use cash received from the Utility to repurchase a ~~price adjustment based on the daily volume weighted average price, or VWAP,~~total of $1.8 billion of PG&E Corporation common stock ~~over~~in 2005, (ii) its Board of Directors had authorized the ~~term~~repurchase of ~~the arrangement. PG&E Corporation charged the payment to Common Stock within Common Shareholders' Equity.~~

~~On March 4, 2005,~~shares in an aggregate amount of $1.05 billion, and (iii) this authorization was used when PG&E Corporation entered into an accelerated share repurchase arrangement with GS&Co. under which PG&E Corporation repurchased 29,489,400 shares of its common stock at an initial price of $35.60 per share (for an aggregate amount including commissions of approximately $1.05 billion). The repurchase was funded from available cash on hand and the repurchased shares were retired. PG&E Corporation charged approximately $460 million to Common Stock and approximately $591 million to Accumulated Earnings within Common Shareholders' Equity in respect of these transactions. Under the share forward component of the arrangement, or March 4, 2005 ~~arrangement, certain payments were required by both PG&E Corporation and GS&Co. upon termination. Most significantly, PG&E Corporation was to receive from, or be required to pay to, GS&Co.~~under which it repurchased 29,489,400 shares. (For a ~~price adjustment on the repurchased shares based on the difference between the amount it paid and the VWAP over the approximately six month intended arrangement period. Upon an early termination~~discussion of the March 4, 2005 arrangement, PG&E Corporation was required to compensate GS&Co. for its losses in connection with the arrangement unless the termination event resulted from the declaration of a dividend and a newaccelerated share ~~forward was executed to complete the March 4, 2005 arrangement. As discussed below, on June 15,~~repurchase arrangements, see Note 5.)

On October 19, 2005, the Board of Directors of PG&E Corporation ~~declared a cash dividend~~authorized the repurchase of up to $1.6 billion of common stock, from time to time, but no later than December 31, 2006 (although the actual repurchase or activity under the repurchase arrangements may occur after that date). The repurchases may be made directly by PG&E Corporation, or through one or more subsidiaries, through brokers and dealers on the New York Stock Exchange and/or the Pacific Exchange or in privately negotiated transactions, which may include accelerated or forward or similar stock purchase programs or the issuance of puts or similar instruments and/or the establishment of one or more "Rule 10b5-1 plans." Such repurchases are contingent on PG&E ~~Corporation common stock for~~Corporation's receipt of sufficient cash from the ~~second quarter of 2005.~~Utility.

~~Thus, on June 16,~~For 2005, PG&E Corporation ~~entered into a new share forward with GS&Co., or June 16, 2005 arrangement, based on 11,430,000 shares to complete~~anticipates that it will receive approximately $950 million from the ~~balance~~Utility as payment for the repurchase of the ~~March 4, 2005 arrangement. The net~~Utility's common stock. To make this payment, the Utility plans to use some of the ~~amounts payable between~~proceeds the ~~parties under~~Utility anticipates receiving from the ~~March 4,~~second series of ERBs expected to be issued in November 2005, ~~arrangement, including~~and additional cash on hand in excess of the Utility's authorized equity ratio and anticipated capital expenditures. (The actual amount of proceeds received by the Utility from the second series of ERBs will depend upon the amount of generator refunds received in cash by the ~~price adjustment based~~Utility before issuance of the ERBs.) Assuming receipt of $950 million from the Utility, PG&E Corporation expects to enter into an accelerated share repurchase arrangement for approximately $1.1 billion before the end of the year. This estimated amount includes approximately $150 million of the cash tha t PG&E Corporation has received through stock option exercises in 2005. Although additional repurchases of up to $500 million are authorized, PG&E Corporation anticipates that the potential for additional repurchases in 2006, beyond those associated with option exercises, is minimal and depends primarily on the ~~VWAP, was approximately $78,000 and was paid~~extent to ~~GS&Co., at PG&E Corporation's option in~~which the CPUC approves the Utility's forecasted capital expenditures.

It is expected that shares repurchased with cash ~~on June 30, 2005.~~

~~The June 16, 2005 arrangement is substantially identical to~~received through the ~~March 4, 2005 arrangement, requiring certain payments by both PG&E Corporation and GS&Co. As with the March 4, 2005 arrangement, the most significant~~exercise of these payments is the price adjustment with respect to the 11,430,000 shares based on the difference between the $35.60 purchase price per share and the VWAP over a period expected to extend to early September 2005. The price adjustment and any additional payments that PG&E Corporation may make under the June 16, 2005 arrangement can be settled, at PG&E Corporation's option, in cash or in shares of its common stock ~~or a combination of the two. Therefore, PG&E Corporation accounts for its payment obligations as equity.~~

Until the June 16, 2005 arrangement is completed or terminated, generally accepted accounting principles in the United States of America, or GAAP, requires PG&E Corporation to assume that it will issue shares to settle its obligations (up to a maximum of 22,860,000 shares). PG&E Corporation must calculateoptions would partially offset the number of shares ~~that would be required~~issued pursuant to ~~satisfy its obligations upon completion~~the exercise of those options, resulting in a minimal impact to the ~~June 16, 2005 arrangement based on~~number of shares outstanding and the ~~market price~~calculation of earnings per share. PG&E Corporation's repurchase of common stock atunder accelerated share repurchase arrangements increased both basic and diluted earnings per share by approximately $0.15 and $0.14, respectively, for the ~~end of a reporting period. The~~nine months ended September 30, 2005. Any additional stock repurchases made by PG&E Corporation in 2005 would not materially affect the average number of shares ~~that would be required to satisfy the obligations must be treated as~~ outstanding for purposes of calculating ~~diluted~~2005 earnings per share. ~~Based on the market price~~

The ultimate amount of stock repurchased by PG&E Corporation ~~stock at June 30,~~in 2005 and 2006 will be affected by, among other factors, the amount of proceeds received by the Utility from the second series of ERBs, as discussed above, changes to PG&E ~~Corporation would have an obligation to GS&Co.~~Corporation's and the Utility's liquidity needs, actual cash from the Utility's operations, the level of ~~approximately $25.3 million upon completion~~employee stock option exercises, and the actual level of the June 16 arrangement. Accordingly, approximatel y 674,000 additional shares of PG&E Corporation common stock attributable to the accelerated repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings per share.Utility's capital expenditures.

Utility Common Stock Repurchase

The Utility anticipates that it will use some of the proceeds from the second series of ERBs anticipated to be issued in November 2005, along with expected generator refunds, and additional estimated cash on hand of approximately $200 million, to repurchase additional shares of its common stock. In turn, PG&E Corporation anticipates that it would use the amounts received from the Utility to repurchase ~~a total of $1.8 billion of~~ its ~~common stock in 2005, increased from the previous estimate of $1.6 billion. Of this total, PG&E Corporation has used $1.05 billion to enter into the accelerated share repurchase arrangements described~~shares as discussed above. Additional repurchases are subject to authorization by the Board of Directors, except for shares repurchased with net cash proceeds received by PG&E Corporation upon exercise of stock options. The ultimate amount of stock repurchased by PG&E Corporation in 2005 will depend upon the aggregate amount of the second series of ERBs and the amount of any generator refunds received in cash by the Utility.

Utility

Operating Activities

The Utility's cash flows from operating activities consist of sales to its customers and payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. Cash flows from operating activities are also impacted by collections of accounts receivable and payments of liabilities previously recorded.

The Utility's cash flows from operating activities for the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

	Six Months Ended					Nine Months Ended
(in millions)	June 30,					September 30,

	2005			2004		2005			2004

Net income	$	499		$	3,486	$	747		$	3,735
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	839		650
Depreciation, amortization, decommissioning and allowance for equity funds used during construction						1,294		1,054
Recognition of regulatory assets, net of tax	-		(2,904)			-		(2,904)
Other deferred charges and noncurrent liabilities	(83)		79
Deferred income taxes and tax credits, net						(638)		399
Change in accounts payable	(222)		170			(83)		77
Change in regulatory balancing accounts, net	565		(440)			940		(323)
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	-		(1,022)			-		(1,022)
Other changes in operating assets and liabilities	6		508			(133)		242

Net cash provided by operating activities	$	1,604		$	527	$	2,127		$	1,258

Net cash provided by operating activities increased by approximately ~~$1.08 billion~~$869 million during the ~~six~~nine months ended ~~June~~September 30, 2005, compared to the same period in 2004. This is mainly due to the following factors:

·	~~Regulatory balancing accounts~~Net income increased approximately $156 million, including $240 million for the impact of depreciation, amortization, and decommissioning and allowance for equity funds used during construction which are non-cash items and excluding the one-time non-cash gain, after tax, of the approximately $2.9 billion related to the recognition of the regulatory assets established under the Settlement Agreement in 2004;
·	Deferred income taxes and tax credits decreased by approximately $1$1.0 billion ~~in 2005. This is~~ primarily due to ~~an increase in various settlements recorded by the Utility in the~~ balancing ~~accounts as well as seasonality affecting usage;~~account activity;
·	Other deferred charges and noncurrent liabilities decreased by approximately $160 million in 2005 mostly due to costs associated with the issuance of long-term debt in 2004 with no similar amount in 2005;
·	Accounts payable decreased by approximately ~~$390~~$160 million in 2005 primarily due to decreases in power and gas purchases;
·	Regulatory balancing accounts increased by approximately $1.2 billion in 2005. This is primarily due to an increase in the balancing accounts payable due to seasonality affecting usage;
·	Other operating assets and liabilities decreased by approximately ~~$500~~$375 million; and
·	Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise decreased by approximately $1.0 billion in 2005. On the effective date of the Utility's plan of reorganization, the Utility paid all allowed creditor claims, with no comparable amount in 2005.

Investing Activities

The Utility's investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash flows from operating activities have been sufficient to fund the Utility's capital expenditure requirements during the ~~six~~nine months ended ~~June~~September 30, 2005 and 2004. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other factors.

The Utility's cash flows from investing activities for the ~~six month periods~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

	Six Months Ended				Nine Months Ended
(in millions)	June 30,				September 30,

	2005		2004		2005		2004

Capital expenditures	$	(803)	$	(737)	$	(1,318)	$	(1,110)
Net proceeds from sale of assets	17		25		19		28
Decrease (increase) in restricted cash	321		(1,741)		453		(1,601)
Other investing activities, net	12		(54)		3		(50)

Net cash used in investing activities	$	(453)	$	(2,507)	$	(843)	$	(2,733)

Net cash used in investing activities decreased by approximately ~~$2.05~~$1.9 billion during the ~~six~~nine months ended ~~June~~September 30, 2005, compared to the same period in 2004, mostly due to an increase in restricted cash of approximately $2$1.6 billion in 2004, with ~~no such amount in~~a decrease of approximately $450 million 2005. In 2004, funds were deposited into escrow to pay disputed claims when resolved. When disputed claims are resolved, the amounts related to these claims are released from escrow.

Financing Activities

In 2005, the Utility obtained $1.9 billion of proceeds from the ERBs, which refinanced a portion of the Settlement Regulatory Asset. It used the proceeds to repay debt and repurchase equity.

The Utility's cash flows from financing activities for the ~~six month periods~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

	Six Months Ended				Nine Months Ended
(in millions)	June 30,				September 30,

	2005		2004		2005		2004

Repayments under credit facilities and short-term borrowing	$	(300)	$	-	$	(300)	$	-
Proceeds from long-term debt issued		451		6,892		451		7,346
Net proceeds from energy recovery bonds issued		1,874		-		1,874		-
Long-term debt matured, redeemed, or repurchased		(1,354)		(7,098)		(1,554)		(7,552)
Rate reduction bonds matured		(141)		(141)		(214)		(213)
Energy recovery bonds matured		(14)		-		(77)		-
Common stock dividends paid	(220)		-		(330)		-
Preferred dividends paid	(8)		(88)		(12)		(88)
Preferred stock with mandatory redemption provisions redeemed	(122)		(11)		(122)		(15)
Preferred stock without mandatory redemption provisions redeemed					(36)		-
Common stock repurchased	(960)		-		(960)		-
Other financing activities					69		(2)

Net cash used in financing activities	$	(794)	$	(446)	$	(1,211)	$	(524)

For the ~~six~~nine months ended ~~June~~September 30, 2005, net cash used in financing activities increased by approximately ~~$348~~$687 million compared to the same period in 2004, mainly due to the following factors:

·	During the first quarter of 2005, the Utility repaid $300 million it borrowed under its $850 million working capital facility;
·	In 2004, in connection with the Utility's plan of reorganization, the Utility issued approximately ~~$6.9~~$7.3 billion, net of issuance costs, in long-term debt. On May 24, 2005, the Utility entered into seven loan agreements with the California Infrastructure and Economic Development Bank to issue PC Bonds Series A-G, totaling ~~$451~~$454 million, ~~net of~~including issuance costs of $3 ~~million. As a result, long-term debt issued decreased by approximately $6.4 billion in 2005;~~million;
·	In February 2005, PERF issued approximately $1.9 billion of ERBs with no similar issuance in 2004 (see Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion). In March 2005, the Utility used proceeds from the issuance of ERBs to repurchase $960 million of its common stock from PG&E Corporation;
·	In January 2005, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $300 million, and on February 24, 2005, the Utility used a portion of the ERB proceeds to defease $600 million of Floating Rate First Mortgage Bonds. In April 2005, the Utility repaid $454 million under certain reimbursement obligations the Utility entered into in April 2004 when its plan of reorganization under Chapter 11 became effective. On July 3, 2005, the remaining $200 million of Floating Rate First Mortgage Bonds were redeemed. During the ~~second quarter of~~nine months ended September 30, 2004, repayments on long-term debt totaled approximately ~~$7 billion. As a result, repayments on long-term debt decreased approximately $5.7~~$7.5 billion;
·	During the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility paid ~~$220~~$330 million in common stock dividends to PG&E Corporation and ~~$14~~$21 million to PG&E Holdings LLC, a wholly owned subsidiary of the Utility; ~~and~~
·	During the ~~six~~nine months ended ~~June~~September 30, 2005, the Utility redeemed $122 million of preferred stock with mandatory redemption provisions ~~and it is now fully redeemed~~ compared to ~~$11~~$15 million in 2004; and
·	During the nine months ended September 30, 2005, the Utility redeemed $36 million of preferred stock without mandatory redemption provisions with no similar redemption in 2004.

PG&E Corporation

As of ~~June~~September 30, 2005, PG&E Corporation had stand-alone cash and cash equivalents of approximately ~~$354~~$377 million. PG&E Corporation's sources of funds are dividends and share repurchases from the Utility, issuance of its common stock and external financing. The Utility paid a cash dividend of ~~$118~~$117 million to PG&E Corporation and PG&E Holdings LLC on ~~June 16,~~September 22, 2005. The Utility did not pay any dividends to, nor repurchase shares from, PG&E Corporation during 2004.

Operating Activities

PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility and other affiliates 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's consolidated cash flows from operating activities for the ~~six month periods~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

	Six Months Ended				Nine Months Ended
(in millions)	June 30,				September 30,

	2005		2004		2005		2004

Net income	$	485	$	3,405	$	737	$	3,633
Discontinued operations					(13)		-

Net income from continuing operations					724		3,633
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	839		651
Depreciation, amortization, decommissioning and allowance for equity funds used during construction					1,295		1,056
Deferred income taxes and tax credits, net	(115)		2,053		(658)		364
Recognition of regulatory asset, net of tax	-		(4,900)
Recognition of regulatory assets, net of tax					-		(2,904)
Other deferred charges and noncurrent liabilities	(75)		12		(133)		(183)
Tax benefit on employee stock option exercises	37		-
Other changes in operating assets and liabilities	412		(603)		889		(626)

Net cash provided by operating activities	$	1,583	$	618	$	2,117	$	1,340

Net cash provided by operating activities increased by approximately ~~$965~~$777 million during the ~~six~~nine months ended ~~June~~September 30, 2005, compared to the same period in 2004. This increase was primarily related to an increase in the Utility's net cash provided by operating activities as discussed above, the recognition of tax benefits on the exercise of employee stock options during the ~~six~~nine months ended ~~June~~September 30, 2005, with no similar amount in 2004, and the payment of approximately $84 million to participating individuals in the senior executive retention program in January 2004, with no similar payment in 2005.

Investing Activities

On March 8, 2005, PG&E Corporation received $960 million in proceeds for the repurchase of 22,023,283 shares of Utility common stock by the Utility. This transaction was eliminated in consolidation. PG&E Corporation, on a stand-alone basis, did not have any other material investing activities during the ~~six~~nine months ended ~~June~~September 30, 2005 or the same period in 2004.

Financing Activities

PG&E Corporation's consolidated cash flows from financing activities consist mainly of cash generated from debt refinancing and the issuance of common stock.

PG&E Corporation's consolidated cash flows from financing activities for the ~~six month periods~~nine months ended ~~June~~September 30, 2005 and 2004 were as follows:

	Six Months Ended				Nine Months Ended
(in millions)	June 30,				September 30,

	2005		2004		2005		2004

Repayments under credit facilities and short-term borrowings	$	(300)	$	-	$	(300)	$	-
Net proceeds from issuance of energy recovery bonds	1,874		-		1,874		-
Net proceeds from issuance of long-term debt	451		6,892		451		7,346
Long-term debt matured, redeemed or repurchased	(1,356)		(7,098)		(1,556)		(7,553)
Rate reduction bonds matured	(141)		(141)		(214)		(213)
Energy recovery bonds matured	(14)		-		(77)		-
Preferred stock with mandatory redemption provisions redeemed	(122)		(11)		(122)		(15)
Preferred stock without mandatory redemption provisions redeemed					(36)		-
Common stock issued	190		97		231		121
Common stock repurchased	(1,065)		-		(1,087)		-
Preferred dividends paid	(8)		(88)		(12)		(88)
Common stock dividends paid	(111)		-		(223)		-
Other, net	(6)		-		58		(2)

Net cash used in financing activities	$	(608)	$	(349)	$	(1,013)	$	(404)

PG&E Corporation's net cash used in financing activities increased by ~~$259~~$609 million for the ~~six~~nine months ended ~~June~~September 30, 2005, compared to the same period in 2004. The decrease was primarily related to the Utility's financing activities as discussed above, PG&E Corporation's repurchase of approximately 29.5 million shares of PG&E common stock under accelerated share repurchase agreements in March and June of 2005 at an initial purchase price of $1.05 billion, and the first and second quarter dividend payment. As discussed above, the Utility's repurchase of its common stock from PG&E Corporation totaling $960 million in March 2005 was eliminated in consolidation.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual obligations and commitments in connection with business activities. These obligations need to be funded in the future and 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. Refer to ~~Note~~Notes 3 and 7 in the Notes to the Condensed Consolidated Financial Statements and PG&E Corporation's and the Utility's ~~combined~~ 2004 ~~Annual~~Financial Report for further discussion.

Utility

The Utility's contractual commitments include power purchase agreements (including agreements with qualifying facilities, irrigation districts and water agencies, and renewable energy providers), natural gas supply and transportation agreements, nuclear fuel agreements, operating leases, and other commitments.

~~Capital Expenditures~~CAPITAL EXPENDITURES

The Utility's investment in plant and equipment is necessary to replace aging and obsolete equipment and to accommodate anticipated electricity and natural gas load growth. It is estimated that the Utility's capital expenditures will approximate $1.9 billion in ~~each of~~ 2005 and $2.4 billion in 2006 (excluding the capitalized portion of a 2006 pension contribution), resulting in a projected rate base of $15.2 billion in 2005 and $16.2 billion in 2006. The Utility also projects average annual capital expenditures related to its electric and gas distribution and existing generation businesses of $1.5 billion over the 2007-2009 period excluding potential investments in advanced metering infrastructure, as discussed ~~below).~~below, and potential investment in new generation and ongoing investments in its electric and gas transmission operations. If these additional potential investments are made, total capital expenditures could be app roximately $2.5 billion per year from 2007-2009.

Advanced Metering Infrastructure

The CPUC is assessing the viability of implementing an advanced metering infrastructure, or AMI, for residential and small commercial customers. This infrastructure would enable California investor-owned electric utilities to measure usage of electricity on a time-of-use basis and to charge demand responsive rates. The goal of demand responsive rates is to encourage customers to reduce energy consumption during peak demand periods and to reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility is implementing demand responsive tariffs for large industrial customers who already have advanced metering systems in place, and a statewide pilot program was recently completed to test whether and how much residential and small commercial customers will respond to demand responsive rates.

On ~~March 15,~~September 22, 2005, the ~~Utility filed an~~CPUC approved the Utility's application ~~with the CPUC~~ to spend up to $49 million on pre-deployment activities to implement AMI. The CPUC authorized the Utility to recover from customers up to $11.7 million in pre-deployment expenses and $37.4 million in pre-deployment capital additions. The pre-deployment phase consists of activities to prepare the Utility's existing systems to accept data from its proposed advanced metering system, and to establish and test processes for ~~advanced metering. This application has not yet been approved, however a decision is expected~~meter and communication system installation and billing. The authorized pre-deployment funding translates into combined electric and gas distribution revenue requirements of approximately $13.8 million in ~~Fall 2005.~~2005, $6.3 million in 2006, and $6.2 million in 2007. On ~~June 16,~~October 24, 2005, the Utility Reform Network, or TURN, filed ~~with~~an application for rehearing of the CPUC's September 22 decision, alleging that the decision is not supported by substantial evidence in the record and would result in an unreasonable rate increase. The Utility has until November 8, 2005 to respond to TURN's application for rehearing.

The Utility anticipates that the CPUC anwill issue a decision on the Utility's application for approval of deployment of its full ~~advanced metering infrastructure~~AMI project ~~at an~~in May 2006. In its original application filed in June 2005, the Utility estimated that full deployment of AMI would cost of $1.46 billion, ~~consisting of~~including an estimated capital cost of ~~$1.26~~$1.25 billion, ~~estimated expense of $213 million, and a present value revenue requirement of $2,227 million,~~ based on a ~~five year~~five-year installation schedule for virtually all of the Utility's electric and gas customers starting in 2006. The Utility's application indicated, however, that the incremental revenue requirement (after operational savings are taken into account) will be approximately a one percent increase to the Utility's combined gas and electric revenue requirement. Over time, ~~the advanced metering project~~AMI benefits are expected to have a positive (reduction) impact on rates as reduction in procurement-related costs due to demand ~~resp onse~~response are reflected in the total costs passed through to customers and as other uses and benefits of advanced metering infrastructure are developed.

On October 13, 2005, the Utility amended its application to include updated deployment schedules and new cost estimates that are slightly higher than previously estimated, reflecting the revised schedule for regulatory review and recent contract negotiations with potential vendors. The ~~schedule in this proceeding calls for~~supplemental filing indicated that with a final CPUC decision on the project expected in May 2006, AMI deployment is expected to begin in the Fall of 2006 and conclude in 2011. Overall project costs are now estimated to be ~~issued~~approximately $1.61 billion, including $1.41 billion of estimated capital expenditures. It is expected that the additional capital expenditures of $160 million would be incurred primarily in ~~May 2006.~~2010 and 2011. The Utility expects that approximately 89% of the AMI project costs would be offset by the anticipated operational savings and efficiencies resulting from AMI. The remaining 11% is expected to be offset by ele ctric procurement savings resulting from voluntary customer participation in demand response options.

PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility's application for approval of full deployment of its AMI project.

Off-Balance Sheet Arrangements

For financing and other business purposes, PG&E Corporation and the Utility utilize certain arrangements that are not reflected in their 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 are used to enable PG&E Corporation or the Utility to obtain financing or execute commercial transactions on favorable terms, and amounts due under these contracts are contingent upon terms contained in these arrangements. For further information related to letter of credit agreements, credit facilities, pollution control bond insurance reimbursement agreements, aspects of PG&E Corporation's accelerated share repurchase program, and PG&E Corporation's guarantee related to certain ~~National Energy & Gas Transmission, or~~ NEGT indemnity obligations and the ~~U tility's~~Utility's workers' compensation ~~obligations,~~obligatio ns, see Notes 3, 5, and 7 of the Notes to the Condensed Consolidated Financial Statements.

~~Contingencies~~

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies that are discussed below. Also, refer to Note 7 in the Notes to the Condensed Consolidated Financial Statements for further discussion.

Regulatory Matters

This section of the MD&A discusses significant regulatory issues pending before the CPUC, the FERC, or the NRC, the resolution of which may affect the Utility's and PG&E Corporation's financial condition or results of operations. The information presented below should be read in conjunction with PG&E Corporation's and the Utility's ~~combined~~ 2004 ~~Annual~~Financial Report.

Cost of Capital Proceeding

Under the Settlement Agreement, the ~~Utility is entitled to earn an~~Utility's authorized ROE ofshall be no less than 11.22% ~~on an~~and the authorized ~~52%~~ equity ratio for ratemaking purposes shall be no less than 52% until the Utility's long-term issuer credit ratings are at least A- from S&P or A3 from Moody's. The Utility's current long-term issuer credit ratings are BBB from S&P and Baa1 from Moody's.

On May 9, 2005, the Utility filed a cost of capital application with the CPUC to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006. In the cost of capital proceeding, the CPUC (1) establishes the proportions of common equity, preferred equity, and debt that will comprise the Utility's total authorized capital structure for a specific year, and (2) establishes the rate of return that the Utility is authorized to earn on the common equity, preferred equity, and debt components of its capital structure. The following table compares the currently authorized amounts for 2005 and the requested amounts for 2006:

2005 Authorized
2006 Requested
Cost
Capital
Structure
Weighted
Cost
Cost
Capital
Structure
Weighted
Cost
Long-term debt.........................................................
6.10%
45.5%
2.78%
6.05%
46.0%
2.78%
Preferred stock...........................................................
6.42%
2.5%
0.16%
5.87%
2.0%
0.12%
Common equity...........................................................
11.22%
52.0%
5.83%
11.50%
52.0%
5.98%
Return on rate base......................................................

8.77%

8.88%

	2005 Authorized			2006 Requested

	Cost	Capital Structure	Weighted Cost	Cost	Capital Structure	Weighted Cost

Long-term debt............................	6.10%	45.5%	2.78%	6.05%	46.0%	2.78%
Preferred stock.............................	6.42%	2.5%	0.16%	5.87%	2.0%	0.12%
Common equity............................	11.22%	52.0%	5.83%	11.50%	52.0%	5.98%
Return on rate base.......................			8.77%			8.88%

The Utility's proposed cost of capital would increase the 2006 cost of capital revenue requirement by approximately $22 million over the currently authorized revenue requirement for electricity and natural gas distribution and electricity generation operations, based on the Utility's currently authorized rate base.

The Utility did not include a request for a 2006 rate of return for its electric transmission operations in this application to the CPUC because the FERC regulates electric transmission rates. Also, the Utility did not include a request for a 2006 rate of return for its gas transmission and storage operations because the CPUC previously set revenue requirements for the Utility's gas transmission and storage assets through 2007 in a separate proceeding.

The Utility has proposed that any changes to its revenue requirement resulting from adjustments to its authorized 2006 cost of capital be effective January 1, 2006. The Utility expects the CPUC will issue a final decision on this proceeding by the end of 2005.

Energy Recovery Bond Balancing Account

In connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the unamortized portion of the Settlement Regulatory Asset and associated federal and state income and franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, using a securitized financing supported by a dedicated rate component, or DRC. On February 10, 2005, PERF issued approximately $1.9 billion of ERBs. ~~It is anticipated that~~The refinancing of the ~~second series would be issued in November 2005~~Settlement Regulatory Asset through issuance of the ERBs, resulted in the ~~aggregate amount~~elimination of a portion of the Settlement Regulatory Asset on which the Utility was entitled to earn an 11.22% rate of return on equity, or ROE. As a result, the Utility's net income for the three and nine-month periods ended September 30, 2005 were reduced by approximately ~~$800 million.~~$27 million and $73 million, compared to the same periods in 2004, when the Utility earned the 11.22% ROE on the Settlement Regulatory Asset. Total net income for 2005 is estimated to be reduced by approximately $100 million, compared to 2004, due to the elimination of the 11.22% ROE on the Settlement Regulatory Asset.

In connection with the issuance of the ERBs, the Utility ~~has~~ established a balancing account, ~~the~~or ERBBA, as authorized by the CPUC, to track various costs and benefits associated with the ERBs. The ERBBA tariff was approved by the CPUC on May 4, 2005. Among other ERB-related costs and benefits, the Utility is required to use the ERBBA to return to customers the benefits of energy supplier refunds received after the second series of ERBs is issued. The energy supplier refunds that the Utility receives between the issuance of the first and second series of ERBs will be used to reduce the size of the second series of ERBs. The ERBBA tariff also provides that reasonable net interest costs on energy supplier claims and refunds incurred subsequent to the issuance of the first series of ERBs shall be deducted in order to calculate the net amount of energy supplier refunds.

As of ~~June~~September 30, 2005, the Utility had accrued approximately $1.3 billion of net disputed claims filed by various energy suppliers in its Chapter 11 proceeding. The ~~Utility has~~ERBBA liability balance was approximately $364 million as of September 30, 2005, which includes approximately $335 million credited ~~approximately $385 million~~ to the ERBBA ~~as of June 30, 2005~~ as a result of energy supplier settlements after deduction for net interest costs of approximately ~~$70~~$80 million related to net disputed claims. The ~~amount~~ERBBA balance as of ~~this credit will reduce the estimated amount~~September 30, 2005 includes a reserve of ~~the second series of ERBs to~~ approximately ~~$800 million subject to the approval of the CPUC financing team. The Utility reserved approximately $50~~$65 million of net interest costs charged to ERBBA related to the net disputed claims for the period between April 12, 2004, the effective date of the Utility's plan of reorganization, and February 10, 2005, when the first series of ERBs was issued, and certain energy supplier refund litigation costs, pending recovery.

It is anticipated that the second series would be issued in November 2005 in the aggregate amount of approximately $850 million. This amount reflects energy supplier settlements credited to the ERBBA. The proceeds of the second series of ERBs will be paid by PERF to the Utility to pre-fund the Utility's tax liability that will be due as the Utility collects the DRC from its customers over the term of the first series of ERBs. Until taxes are fully paid, the Utility will compensate customers for the use of the ERB proceeds as well as for the use of theafter-tax proceeds of energy supplier refunds received before the second series of ERBs is issued. The carrying cost to be credited to customers will be computed at the Utility's authorized rate of return on rate base. It is estimated that the carrying cost credit, assuming the principal amount of the second series of ERBs is ~~$800~~$850 million and energy supplier refunds of approximately ~~$385~~$335 million ($~~230~~200 million, after-tax) are received before the ERBs are issued, would be approximately $125 million in 2006. The equity portion of this carrying cost credit, of approximately $55 million, would reduce 2006 net income. The actual amount will depend on the principal amount of the second series of ERBs and the after-tax amount of energy supplier refunds received by the Utility before the second series of ERBs is issued. The carrying cost credit and the resulting reduction to net income will decline as the taxes are paid, reaching zero in 2012 when the ERBs and related taxes are paid in full.

Electricity Generation Resources

Procurement Cost Balancing Account and Mandatory Rate Adjustments

California law allows the Utility to recover its reasonably incurred wholesale electricity procurement costs. The Energy Resource Recovery Account, or ERRA, a balancing account authorized by the CPUC, tracks the difference between the authorized revenue requirement and the actual costs incurred under the Utility's authorized electricity resource procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs recorded in the ERRA at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of the Utility's prior year electricity procurement revenues, excluding amounts collected for the DWR allocated contracts. ~~As of June 30, 2005, the ERRA had an over-collected balance of approximately $189 million.~~ On July 12, 2005, the CPUC approved the Utility's 2005 ERRA trigger amount of approximately $164 million. As of S eptember 30, 2005, the ERRA had an over-collected balance of approximately $202 million.

On July 15, 2005, the Utility filed an application to address its current ~~overcollection~~over-collection in the ERRA. Because the Utility projects its ERRA balance ~~overcollection~~over-collection will decrease below the 5% level by 2005 year end, the Utility does not propose an ERRA rate change as part of this application. ~~In February 2005, the~~The CPUC approved the ~~2005 ERRA revenue requirement of $2.14 billion based~~application on ~~forecast costs.~~September 22, 2005.

In June 2005, the Utility filed ~~its~~in 2006 ERRA forecast revenue requirement of $2.41 billion. On October 14, 2005, the Utility filed an update to its 2006 ERRA forecast revenue requirement to $2.82 billion to reflect the effects of increased natural gas prices and other changes to the electric portfolio that result in higher prices for electricity to the Utility's customers. A final decision on the 2006 ERRA revenue requirement is expected before the end of 2005.

The CPUC performs periodic compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility's procurement activities are in compliance with its approved procurement plans. The cost of procurement activities could be disallowed up to a maximum of two times the Utility's administration costs associated with procurement each year. For 2005, this amount is $36 million. In April 2005, the CPUC approved the Utility's application related to its procurement activities recorded in the ERRA for the period of January 1, 2003 through May 31, 2003, finding that the Utility's contract administration, least cost dispatch, procurement activities, and generation fuel costs were in compliance with its 2003 updated procurement plan. In July 2005, the CPUC approved the ~~Utility~~Utility's application related to the remainder of the record period (i.e., June 1, 2003 to December 31, 2003) ~~that~~and found the Utility's ~~c ontract~~contract administration, least cost dispatch, procurement activities, and generation fuel costs to be in compliance with its 2003 updated procurement plan.

In February 2005, the Utility filed an ERRA compliance review application for the January 1, 2004 to December 31, 2004 record period. On July 1, 2005, the Office of Ratepayer Advocates, or ORA, issued its report on the Utility's ERRA compliance review for the January 1, 2004 to December 31, 2004 record period. In its report, the ORA found that the Utility's electric contract administration and least cost dispatch of resources were reasonable. However, the ORA recommends a disallowance of approximately $2 million related to utility retained generation operations. ~~Final~~On October 17, 2005, a CPUC administrative law judge, or ALJ, released a proposed decision finding that the Utility's administration of its power purchase agreements, procurement of least cost dispatch power activities, and associated procurement revenues and expenses for 2004 were reasonable and prudent, thus rejecting the ORA's proposed disallowance. F inal action on the 2004 record period application is expected before the end of 2005. PG&E Corporation and the Utility are unable to predict whether an actual disallowance will result or the size of any potential disallowance. In addition, it is uncertain whether the CPUC will modify or eliminate the maximum disallowance for future years.

New Long-Term Generation Resource Commitments

In accordance with the Utility's CPUC-approved long-term electricity procurement plan, in March 2005 the Utility ~~has~~ requested offers from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided ~~under~~by utility-owned projects or ~~turnkey developments, or under~~ third-party power purchase agreements) for ~~approximately 1,200~~up to 2,200 megawatts, or MW, of peaking ~~resources by 2008~~ and ~~an additional 1,000 MW of~~ load-following resources, ~~by 2010.~~beginning in 2008. In addition, the Utility requested offers for new sources of generation to replace its existing 135 MW Humboldt Bay generating facility, which is estimated to be retired in 2009.

Initial offers were submitted to the Utility in late April 2005. The Utility ~~has~~ selected participants to provide additional information through second round offers. Final offers were submitted in late October. The Utility anticipates ~~submitting executed~~completing contract negotiations as early as the end of this year. The contracts that the Utility ultimately executes will depend on the outcome of these negotiations and an updated assessment of the Utility's future power needs. Further, as discussed under Note 7 of the Notes to the Consolidated Financial Statements, the Utility has requested that the CPUC permit the Utility to acquire and complete the Contra Costa Unit 8 facility, a modern 530 MW electric generating facility that the Utility has agreed to acquire pursuant to a settlement agreement the Utility entered into with Mirant Corporation and certain of its subsidiaries. CPUC hearings are scheduled to begin on December 5, 200 5 and a final decision is expected on this application by March 15, 2006. The Utility's assessment of its generation resource needs may be affected by whether the CPUC approves the Utility's application to acquire and complete the Contra Costa 8 facility.

As previously disclosed, the CPUC's December 2004 decision adopting the long-term procurement plans of the California investor-owned electric utilities, or IOUs, requires load-serving entities, including the IOUs, electric service providers and community choice aggregators, but not local publicly owned utilities, to achieve an electricity planning reserve margin of 15% to 17% in excess of peak loads by June 1, 2006. On October 27, 2005, the CPUC issued a decision that reaffirms and clarifies the policy framework the CPUC established in previous decisions addressing resource adequacy. The October 2005 decision sets forth numerous rules in furtherance of that policy, including a penalty provision for ~~approval~~failure to acquire sufficient capacity needed to meet resource adequacy requirements. The penalty is equal to three times the cost of the new capacity the deficient load-serving entity should have secured, but for 2006 only the penalty is set at one-half of the amount. The Utility's CPUC-approved long-term procurement plan forecasts that the Utility will be able to meet the resource adequacy requirements. If the CPUC determines that the Utility has not met the requirements, the Utility could be subject to penalties in an amount determined by the ~~fourth quarter of 2005.~~CPUC in accordance with the new penalty provision.

Renewable Energy Contracts

The California Renewables Portfolio Standard, or RPS, requires California utilities to increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year beginning in 2003, referred to as the RPS target, so that the amount of electricity purchased from renewable resources equals at least 20% of its ~~total~~bundled retail sales by the end of 2017. The CPUC intends that the 20% goal be met by 2010. The CPUC has also stated that compliance with the 20% goal must be met through actual deliveries of power, although it has adopted flexible compliance rules that allow the Utility to meet a portion of its RPS target through the execution of contracts for future delivery of power. Unless waived by the CPUC, and subject to the CPUC's flexible compliance rules, the penalty for failing to procure at least 75% of the annual RPS target is 5 cents per each kWh of the ~~short fall,~~sho rtfall, subject to an overall annual penalty maximum of $25 million per utility.

In July and August 2005, the CPUC approved the Utility's execution of ~~three~~four new renewable power purchase contracts that will help the Utility meet its ~~end of year~~ 2005 RPS target. In addition, the CPUC approved the 2005 RPS solicitation for bids from renewable energy providers, which the Utility ~~expects to issue~~issued on August 4, 2005. As a result of this solicitation, the Utility may enter into additional contracts for future deliveries that would fully satisfy its end of year 2005 and 2006 RPS ~~target.~~targets.

DWR Allocated Contracts

The Utility acts as a billing agent for the collection of the DWR's revenue requirements from the Utility's customers. The DWR's revenue requirements consist of a power charge to pay for the DWR's costs of purchasing electricity under its contracts and a bond charge to pay for the DWR's costs associated with its $11.3 billion bond offering completed in November 2002. In December 2004, the CPUC issued a decision on the permanent cost allocation methodology for the DWR's power charge revenue requirements in 2004 and subsequent years, among the three California investor-owned electric utilities. In January 2005, the CPUC granted limited rehearing of its permanent cost allocation decision to address how to calculate the above-market costs of the DWR power contracts. In June 2005, the CPUC ~~adopted a~~issued an alternate decision ~~which modifies~~on the permanent cost allocation methodology used to allocate DWR's costs of purchasing ~~electrici ty among~~electricity amo ng the three California investor-owned electric utilities. AsIn August 2005, a ~~result,~~Petition to Modify the alternate decision was filed. A final decision on the petition to modify the DWR permanent cost allocation is expected by year end 2005. The Utility anticipates its DWR annual revenue requirement will increase in 2006. However, since the DWR revenue requirement is a pass-through to the Utility customers, any adjustments thereto should not affect the Utility's results of operations.

Diablo Canyon Steam Generator Replacement Projects

On ~~February 24,~~August 15, 2005, the ~~CPUC~~final environmental impact report, or EIR, required by the California Environmental Quality Act was issued ~~an interim decision on~~with respect to the Utility's proposal to replace the turbines, steam generators and other equipment at the two nuclear operating units at the Utility's Diablo Canyon nuclear power plant, referred to as the Steam Generator Replacement Project, or SGRP. The final EIR found that, for the SGRP ~~application.~~as a whole, there are no environmental impacts that are significant, provided certain mitigation measures are implemented. On October 13, 2005, a CPUC ALJ issued a proposed decision that, if approved by the CPUC, would certify the EIR as final and approve the Utility's SGRP. The proposed decision also recommends the adoption of the CPUC's findings made in its February 24, 2005 interim decision ~~concluded~~ that the SGRP is cost-effective, that $706 million, as adjusted for actual inflation and cost of ca pital, is a reasonable estimate of the SGRP cost, and that the Utility cannot recover costs in excess of $815 million, as adjusted for actual inflation and cost of capital. The proposed decision also would adopt the interim decision's finding that (i) if the costs did not exceed $706 million, the CPUC did not intend to conduct an after-the-fact reasonableness review of the SGRP costs but that such a review was not precluded, and (ii) if the SGRP cost exceeds $706 million, as adjusted for actual inflation and cost of capital, ~~is a reasonable estimate~~or the CPUC later finds that it has reason to believe the costs may be unreasonable regardless of the ~~SGRP cost. The interim decision also concluded that an after-the-fact reasonableness review of~~amount, the entire SGRP cost will be subject to a reasonableness review. It is ~~not required, but not precluded either. It adopts~~expected that the CPUC will issue a ~~maximum allowable SGRP cost cap~~final decision by the end of ~~$815 million as adjusted for actual inflation and cost~~2005.

As of ~~capital, and~~September 30, 2005, the Utility ~~will not be allowed to recover~~has incurred approximately $50.8 million in SGRP costs in excess of this amount. The Utility will file an advice letter to request authority to implement a rate increase, subject to refund, for each unit at the time each unit begins commercial operations. Afterunder various construction and installation ~~is complete, and both units are operational,~~contracts the Utility ~~will be re quired to file an application to include the costs permanently in rates.~~has executed. The interim decision does not approve or disapprove the SGRP, guarantee or approve the recovery of any expenditures related thereto, or dictate the outcome of the environmental review of the SGRP pursuant to the California Environmental Quality Act, or CEQA. A final decision, which will include the results of the CEQA review, is expected in September 2005. As of June 30, 2005, expenditures on the project of approximately $35.7 million have been incurred. These expenditures are expected to increase to approximately $59 million by September 2005 when the CPUC's final decision approving the project is expected. If the CPUC approves the project, the Utility estimates it ~~would~~will spend up to an additional ~~$20.3~~$27.5 million inbefore the ~~last quarter of 2005.~~CPUC issues a final decision. If the CPUC does not approve the ~~projects,~~SGRP, then the Utility ~~will~~would terminate the contracts and seek to recover the ~~project~~SGRP costs that it incurred before termination from customers through the abandoned project process.

Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities and Public Purpose Programs

On ~~April 4,~~October 27, 2005, the ~~Utility filed a motion with the~~ CPUC ~~seeking approval of~~approved a settlement agreement entered into ~~on April 4, 2005~~ between the Utility and the CPUC's ~~ORA.~~ORA on April 4, 2005. The settlement ~~agreement proposes the resolution of~~resolved the Utility's claims that have been pending for several years for shareholder incentives earned by the Utility for the successful implementation of demand-side management, energy efficiency, and low-income energy efficiency programs for past program years 1994 through ~~2001. The Utility's claims for shareholder incentives are~~2001, which were addressed in the Utility's Annual Earnings Assessment Proceeding, or AEAP. In addition to resolving claims made in the ~~pending~~ AEAPs, the settlement ~~agreement proposes to resolve~~resolved all future claims for shareholder incentives relating to past program years that the Utility would otherwise have made in future AEAPs through 2010.

The Utility's total current and future shareholder incentive claims aggregate to approximately $207 million. Under the settlement agreement, the parties have agreed that the results to date show that the energy savings anticipated in the Utility's shareholder incentive claims are being realized. The ~~parties have proposed that the Utility receive~~decision approved shareholder incentives of approximately $186 million to resolve the Utility's claims in the pending and future AEAPs. ~~The parties have proposed that~~Of this amount, approximately $160 million will be collected from electric customers and approximately $26 million will be collected from gas customers, in proportion to the relative allocations of the original claims. The Utility has already collected $28 million of the $160 million from electric customers.

~~PG&E Corporation and~~As a result of the CPUC's decision, the Utility ~~cannot predict whether or when the CPUC~~ will ~~approve the settlement agreement. Assuming the CPUC approves the settlement agreement, the Utility would~~ record pre-tax income of approximately $186 million ~~during~~in the fourth quarter ~~in which the settlement agreement is approved by the CPUC.~~2005.

~~Pending~~ CPUC ~~Investigations~~Energy Efficiency Programs

On ~~March 17,~~September 22, 2005, the CPUC ~~issued an order~~authorized 2006 through 2008 energy efficiency portfolio plans and program funding levels for the Utility and the other investor-owned California utilities. The decision approves over $850 million in the Utility's energy efficiency programs over the next three years, 20% of which is to be awarded to third-parties through a competitive bid process. The energy efficiency funding is part of a larger effort by the state of California to secure California's energy future and reduce consumption of fossil fuels that ~~institutes an~~are linked to global climate change. The funding level for 2005 program year is approximately $190 million. The increased funding level will enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs. The decision also authorizes the Utility to begin implementation of selected programs immediately to help customers w ith their winter gas bills. The CPUC has authorized the Utility to recover the funding for energy efficiency programs from customers through rates.

Pending CPUC Investigations

On October 18, 2005, the Utility, the CPUC'S Consumer Protection and Safety Division, or CPSD, and the City and County of San Francisco, entered into a settlement agreement to resolve the issues raised in the CPUC's investigation into the circumstances surrounding a fire that occurred at the Utility's Mission Street substation in San Francisco in December 2003 and the ensuing power outage.~~Approximately 100,000 of~~ Under the Utility's customers were affected by the outage, which began in the early evening of December 20, 2003. While most customers had their power restored by the next morning, the outage lasted more than 24 hours for some customers. Noting thatsettlement, the Utility ~~had failed~~will make payments totaling $6.5 million, for which it will not seek rate recovery, consisting of (1) $3 million to hire an independent consultant to implement ~~its own recommendations made following an investigation of a 1996 fire~~reliability improvements in San Francisco; (2) $1 million in capital expenditures to make improvements at the same substation, the CPUC's order found that good cause exists to consider the safety and reliability of the Utility's other indoor substations. The order also noted that the CPUC has authority to impose penalties in the amount of $500 to $20,000 per day per offenseHunters Point substation; (3) $750,000 for ~~viol ations of the Public Utilities Code. The order states that the CPUC may consider a penalty for each customer that lost power or for each day the outage was ongoing.~~

~~In addition, the CPUC issued a press release noting that CPUC staff also would investigate the causes of~~ a fire safety program and ~~power outage that originated at~~specialized equipment for the Mission Street substation on March 26, 2005, that affected approximately 23,500 of the Utility's customers. It is presently unknown whether the CPUC will open a separate investigation, or whether the CPUC will address the 2005 fire as part of the current investigation. The CPUC's Consumer Protection and Safety Division, or CPSD, andSan Francisco Fire Department; (4) $750,000 to the City and County of San Francisco ~~have filed testimony~~to spend on infrastructure to improve public safe ty in the ~~current investigation criticizing the Utility's response~~event of electric outages; (5) $500,000 to support development of a CPUC substation inspection program; and (6) $500,000 to be paid to the ~~March 2005 fire.~~State of California's General Fund. The ~~Utility, however, believes the March 2005 incident demonstrated the effectiveness~~settlement agreement is subject to approval of the ~~changes made in its practices and facilities following the December 2003 incident.~~

The CPSD has recommended that the Utility pay a penalty of approximately $10 million, based on a per-day penalty of $3,225 multiplied by approximately 3,100 days since 1996 when the earlier fire and outage occurred at the Mission Street substation. The City and County of San Francisco has recommended that the Utility pay a penalty of approximately $14 million. The Utility will file a response to the recommendations by August 19, 2005.CPUC. A final decision on the ~~investigation~~settlement is expected during the first quarter of 2006. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

The CPUC also is conducting an investigation into the Utility's billing and collection practices that ~~has been opened~~began at the request of TURN after the CPUC's January 13, 2005 decision that characterized the definition of "billing error" in a revised Utility tariff to include delayed bills and Utility-caused estimated bills as being consistent with "existing CPUC policy, tariffs, and requirements." The Utility ~~Reform Network,~~contends that prior to this decision, "billing error" under the Utility's former tariffs did not encompass delayed bills or ~~TURN.~~Utility-caused estimated bills. On ~~July 15,~~August 11, 2005, the CPUC approved a schedule proposed by the Utility and the CPSD ~~filed a joint motion for an extension of the schedule in this investigation requesting the CPUC approve a schedule~~ that would require CPSD's report to be due on December 16, 2005, the Utility's response to be due on February 17, 2006, and rebuttal testimony to be due on March 31, 2006, with hearings to begin on April ~~17, 2006~~.24, 2006. On September 22, 2005, the CPUC denied the Utility's application for rehearing of the CPUC's January 13, 2005 decision and on October 28, 2005 the Utility filed a petition asking the appellate court to review the CPUC's decision denying rehearing of its earlier decision.

If the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may impose penalties on the Utility or order the Utility to refund any amounts collected in violation of tariffs, plus interest, to customers who paid such amounts. PG&E Corporation and the Utility continue to believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

2007 GRC

On August 1, 2005, the Utility tendered its Notice of Intent, or NOI, to file its 2007 GRC application. On October 3, 2005, the CPUC accepted the Utility's NOI. In the 2007 GRC, the CPUC will determine the amount of authorized base revenues to be collected from customers to recover the Utility's basic business and operational costs for its gas and electric distribution and electric generation operations for the period 2007 through 2009. These revenue requirements are determined based on a forecast of costs for 2007 (the "test year"). The NOI indicates that the Utility's GRC application will request an increase in electric and gas distribution revenue requirements of $393 million and $61 million, respectively, over the projected authorized 2006 revenue requirements to maintain current service levels to support increased investment in distribution infrastructure as plant in service is upgraded and replaced, and to adjust for wages and inflation. The NOI also indicates ~~th e~~the Utility will request an increase of $48 million, over the projected authorized 2006 revenue requirement, to cover increases in operational costs for the Utility's fossil, hydro, and nuclear generation facilities and administrative costs associated with electric procurement activities. (The projected 2006 revenue requirements assume the minimum increase over 2003 revenues approved by the CPUC in the Utility's 2003 GRC). The NOI indicated that the Utility's preliminary forecast of average annual distribution and generation capital expenditures over the 2007-2009 period would be approximately $1.5 ~~billion, slightly higher than the $1.3 billion previously forecast.~~billion.

~~The~~In its NOI, the Utility also has indicated that it will seek an increase of $167 million for 2008 and $242 million for 2009 designed to avoid a reduction in earnings in years between GRCs that would otherwise occur because of increases in rate base and expenses.

The NOI proposes that the Utility's 2008 and 2009 total gas and electric revenue requirements be reduced by $41 million in 2008 and $97 million in 2009 to capture an estimate of net savings that the Utility anticipates may be realized from the operating and cost efficiencies achieved through implementation of specific initiatives identified by the Utility to provide better, faster and more cost-effective service to its customers. In addition, due to uncertainty about savings to be realized from these initiatives, the Utility will propose a sharing mechanism by which shareholders and customers would share equally in any earnings that would exceed an actual ROE equal to the then-authorized ROE plus 50 basis points, with the customers receiving 100% of the earnings that would exceed an actual ROE equal to the then-authorized ROE plus 3.00%. If the Utility's actual ROE would be less than an amount equal to the then-aut horized ROE minus 50 basis points, shareholders and customers would share the shortfall equally. ~~For example,~~The following table summarizes the proposed sharing mechanism based on the Utility's currently authorized ROE of 11.22%, shareholders and customers would share equally in any earnings that would exceed an 11.72% ROE and customers would receive 100% of the earnings that would exceed a 14.22% ROE. If the Utility's ROE would be less than 10.72%, shareholders and customers would share the shortfall (i.e., the difference between 10.72% and the ROE used to determine the shortfall) equally.:

ROE
Customer
Shareholder
Below 10.72%
50%
50%
10.72% - 11.72%
0%
100%
11.73% - 14.22%
50%
50%
Above 14.22%
100%
0%

~~After addressing any deficiencies that may be identified and after acceptance for filing by the Executive Director of the CPUC, the~~The Utility ~~must wait 60 days~~intends to file ~~the actual~~its GRC application with the ~~CPUC. Hearings will then be held and a decision issued setting~~CPUC by December 2, 2005. After the GRC application is filed, the ALJ overseeing the 2007 ~~revenue requirement~~GRC will set a schedule to determine the expected dates for hearings, the issuance of a proposed decision, the issuance of a final decision, and ~~addressing~~ other ~~issues.~~procedural events. A final decision is expected from the CPUC by the end of 2006.

PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the 2007 through 2009 period, when a final decision in this proceeding will be received, or the impact it will have on their financial condition or results of operations.

FERC Transmission Rate Case

On August 1, 2005, the Utility filed an application with ~~the~~ FERC requesting ~~authority to recover approximately $655 million in electric transmission retail~~ rates ~~annually, effective October 1, 2005. The proposed rates represent an~~that would provide a revenue requirement increase of approximately $110 million over current retail transmission rates. ~~The~~On September 26, 2005, FERC accepted the filing and suspended the requested ~~increase is mainly attributable~~rate changes for five months, to ~~significant capital additions~~become effective March 1, 2006, subject to refund. FERC also established hearing and ~~replacements made to the Utility's system to accommodate load growth, maintain infrastructure, and ensure safe and reliable service. In addition, the request includes a return on equity of 12.00%.~~settlement judge procedures. PG&E Corporation and the Utility are unable to predict what amount of revenue requirements ~~and the effective date the~~ FERC will authorize, when a final decision will be received from ~~the~~ FERC, or the impact it will have on the results of operations.

Defined Benefit Pension Plan Contributions

On July 13, 2005, the Utility filed a petition requesting the CPUC to authorize it to resume contributions to its employee pension trust beginning in 2006 based on the funded status of the pension fund. If the CPUC grants the petition, the Utility will file an application before December 2005 requesting approval of the revenue requirement increase necessary to fund the contributions, separate from the 2007 GRC application to be filed in early December 2005. The petition estimates the annual revenue requirement associated with the pension contributions for its generation and distribution businesses to be approximately $185 million, and it requests that the amount be recovered in rates beginning January 1, 2006, subject to refund to customers if the CPUC later disapproves the contributions. Should the CPUC not grant the petition, the Utility will include ~~the~~a pension request in its 2007 GRC application. In the ~~Utili ty's~~Utility 's last GRC decision in 2004, the CPUC denied the Utility's request to resume pension contributions based on a finding that the pension plan's funded status was in excess of 100%. The Utility is also asking FERC in its transmission owner rate case filing discussed above to allow approximately $14 million annual revenue requirement associated with the pension contributions for its electric transmission business to be recovered in rates beginning March 1, 2006.

Natural Gas Supply and Transportation

In December 2004, the CPUC issued a final decision approving the Gas Accord III Settlement Agreement that sets the Utility's gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005. The decision extends the terms of a settlement agreement originally reached in 1997 called the Gas Accord. Under the agreement, the Utility agreed to not have a balancing account for the over-collections or under-collections of natural gas transportation or storage revenues, thus assuming the risk of not recovering its full natural gas transportation and storage costs that have not been contracted for under fixed reservation charges with its core customers. (See discussion below under "Risk Management Activities - "Transportation and Storage").

The original Gas Accord market structure included an incentive mechanism for recovery of core procurement costs, or CPIM, which is used to determine the reasonableness of the Utility's costs of purchasing natural gas for its customers. Under the CPIM, the Utility's purchase costs for a twelve month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive in their rates three-fourths of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareh older award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this cost recovery mechanism remains in place, changes in the price of natural gas are not expected to materially impact net income.

On October 6, 2005, the CPUC granted the Utility authority to purchase hedges on behalf of the Utility's core gas customers, and to book the costs of such hedges in a separate balancing account, outside of CPIM. This action was undertaken because of rapidly rising natural gas prices in the wake of Hurricanes Katrina and Rita. The CPUC's decision authorizes enhanced hedging activity on behalf of core customers for the winter of 2005-2006 and for two subsequent winters. The Utility also has agreed to forego a shareholder award under the CPIM for the 2004-2005 CPIM year.

Spent Nuclear Fuel Storage Proceedings

On October 17, 2005, the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, heard oral argument on an appeal filed by several interveners challenging the NRC's March 2004 decision to authorize the Utility to construct a dry cask storage facility at Diablo Canyon to store spent nuclear fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. A decision is anticipated in late in 2005 or the first quarter of 2006. Construction of the on-site dry cask storage facility began in the third quarter 2005. The Utility also has requested the NRC to approve an alternative on-site storage project to install a temporary storage rack in each unit's existing spent fuel storage pool that would permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. At the projected level of operation for Diablo Canyon, the Utility's current facilities are able to store on-site all spent fuel produced through a pproximately 2007. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2007, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2007 and until such time as additional spent fuel can be safely stored. If electricity from Diablo Canyon were unavailable, the Utility would be required to purchase electricity from other more expensive sources to meet its customers' demand.

CPUC Proceeding Regarding Holding Companies and their Affiliates

On October 27, 2005 the CPUC issued an Order Instituting Rulemaking, or OIR, to allow the CPUC to re-examine the relationship between California energy utilities and their parent holding companies and affiliates. The OIR was issued in response to the recent enactment by Congress of the Energy Policy Act of 2005, which, among other things, repealed the Public Utility Holding Company Act of 1935 and ordered the FERC to review its rules regarding dispositions, consolidations, or acquisitions made by entities that are subject to the FERC's jurisdiction under the Federal Power Act. The CPUC noted that as a result of these changes, the parent holding companies of the California energy utilities may try to expand the unregulated activities of the utilities' affiliates, may try to merge with or acquire other companies or may be acquired by other companies and that it was necessary for the CPUC to review its existing regula tions and to consider whether additional, new rules or regulations are needed. The CPUC requires that the California energy utilities and their parent holding companies submit certain financial and other information by November 30, 2005. The CPUC set forth a preliminary procedural schedule that calls for proposed rules to be issued in January 2006 and a final decision in March 2006. The CPUC may propose rules to ensure that the California energy utilities retain sufficient capital and the ability to access capital in order to meet their customers' needs, and to address the potential conflicts between the utilities' ratepayers' interests and the parent holding companies' and affiliates' interests in order to ensure that these conflicts do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. After reviewing the information submitted by the California energy utilities and their parent holding companies, the CPUC may propose additional rules or regulation s regarding, but not necessarily limited to, (1) reporting requirements for the allocation of capital between utilities and their non-regulated affiliates by the parent holding companies, and (2) changes to the CPUC's affiliate transaction rules.

PG&E Corporation and the Utility cannot predict whether any rules that the CPUC may adopt will have a material impact on their results of operations or financial condition.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk and credit risk. The Utility actively manages market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk-taking, reduce earnings volatility and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigati on) and not for speculative purposes. The Utility's risk management activities include the use of energy and financial instruments, including forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

The Utility estimates fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market data is not available, the Utility uses models to estimate fair value.

Price Risk

Convertible Subordinated Notes

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,655 shares of common stock of PG&E Corporation, at a conversion price of approximately $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's outstanding common shares. To date, the conversion price has not required adjustment. In addition, holders of the Convertible Subordinated Notes are entitled to receive pass-through dividends at the same payout as common stockholders with the number of shares determined by dividing the principal amount of the Convertible Subordinated Notes by the conversion price. OnIn connection with each common stock dividend that was p ayable to holders of PG&E Corporation common stock on April 15, July 15 and ~~July~~October 15, 2005, PG&E ~~Corporat ion~~Corporation paid approximately $6 million of ~~"pass-through~~"pass through dividends" to the holders of ~~the~~ Convertible Subordinated Notes. The holders have a one-time right to require PG&E Corporation to repurchase the Convertible Subordinated Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including liquidated damages and unpaid "pass-through dividends," if any).

In accordance with Statement of Financial Accounting Standards, or SFAS, No. 133, "Accounting for Derivative Instruments and Hedging Activities," or SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and ~~marked to market on~~recorded at fair value in PG&E Corporation's Consolidated Financial Statements. Changes in the fair value are recognized in PG&E Corporation's Consolidated Statements of Income as a non-operating expense ~~(in~~or income (included in Other ~~expense,~~income (expense), net)~~, and reflected at fair value on PG&E Corporation's Consolidated Balance Sheet at June 30, 2005.~~. At ~~June~~September 30, 2005 and 2004, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately ~~$91~~$93 million and $70 million, respectively, of which ~~$20~~$21 million and $9 million, respectively, is classified as a current liability (in Current liabilities-Other) and ~~$71~~$72 mill ion and $61 million, respectively, is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in value of the liability was immaterial for the ~~quarter~~quarters ended ~~June~~September 30, 2005 ~~was immaterial. The mark to market change was approximately $33 million, pre-tax, for the quarter ended June 30,~~and 2004.

Electricity

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. In addition, the Utility purchases and sells electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

It is estimated that the residual net open position (the amount of energy needed to meet the demands of customers, plus applicable capacity or reserve margins that is not satisfied from the Utility's own generation facilities, purchase contracts or DWR contracts allocated to the Utility's customers) will change over time for a number of reasons, including:

·	Periodic expirations of existing energy and capacity purchase contracts, or entering into new energy and capacity purchase contracts;
·	Fluctuation in the output of hydroelectric and other ~~renewable~~ power facilities owned or under contract;
·	Changes in the Utility's customers' electricity demands due to customer and economic growth and weather, and implementation of new energy efficiency and demand response programs, community choice aggregation, and a core/noncore retail market structure;
·	~~Changes to planning reserve and operating requirements, and what is eligible to meet these requirements;~~
·	The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and
·	The acquisition, retirement or closure of ~~Utility~~ generation facilities.

In addition, lengthy, unexpected outages of the Utility's generation or contracted facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility's residual net open position. As noted (see "Spent Nuclear Fuel Storage Proceedings" above) it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2007, if suitable storage facilities are not available for spent nuclear fuel, which would cause an increase in the Utility's residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, the CPUC approved, with certain modifications, the Utility's long-term electricity procurement plan, or LTPP, for the 2005 through 2014 period. The LTPP is ~~detailed~~discussed above under "Regulatory Matters" and in the "Regulatory Matters" section of the MD&A in PG&E Corporation's and the Utility's combined 2004 ~~Annual~~Financial Report.

The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an ~~under~~under- or over-collection exceeding 5% of the Utility's prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility's administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility's net income while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the ~~CPUC~~CPU C may in the future disallow portions or the full costs of transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.

~~Nuclear Fuel~~Natural Gas (Electric Portfolio)

A portion of the Utility's electric portfolio is exposed to natural gas price risk. The Utility ~~purchases nuclear fuel for Diablo Canyon through~~manages this risk in accordance with its risk management strategies, which are included in procurement plans approved by the CPUC. Gas price risk is expected to increase when the fixed price amendments to the Utility's contracts with ~~terms ranging from two~~qualifying facility generators expire in July 2006. Following expiration, payments under these contracts will be based on gas price indices. Due to ~~five years. These long-term nuclear fuel agreements are with large, well-established international producers in order~~recent natural gas price volatility, the Utility sought changes to ~~diversify~~ its ~~commitments and provide security of supply.~~

~~Some nuclear fuel purchases are subject to tariffs of up to 8% on imports from certain countries. In~~gas hedging strategy for its electric portfolio. On September 22, 2005 the ~~past,~~CPUC approved the Utility's long-term nuclear fuel contracts were not subject to these tariffs. However, these contracts expired at the end of 2004, and prices under existing and future contracts may be higher as a result of such tariffs. In addition, because of an increase in U.S. demand for uranium comparedproposed electric portfolio gas hedging plan. The expenses associated with the ~~domestic supply, uranium prices~~hedging plan are ~~trending higher~~expected to be recovered in ~~2005. During~~ the ~~quarter ended June 30, 2005, the Utility did not enter into any nuclear fuel purchase agreements.~~

~~As the Utility replaces contracts that expired at the end of 2004 with new higher priced uranium contracts, nuclear fuel costs will rise. These costs are recovered in~~ ERRA (see the "Electricity Generation Resources" section of this MD&A)~~, therefore, the changes in nuclear fuel prices are not expected to materially impact net income.~~.

Natural Gas (Core Customers)

The Utility generally enters into physical and financial natural gas commodity contracts from one to thirty 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, significant volumes of gas may be purchased in the monthly and, to a lesser extent, daily spot market. The Utility's cost of natural gas purchased for its core customers includes the commodity cost, the cost of Canadian and interstate transportation, intrastate gas transmission and ~~gas~~ storage costs.

Under the ~~Core Procurement Incentive Mechanism, or~~ CPIM the Utility's purchase costs for a fixed twelve-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive, in their rates, three-fourths of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this cost recovery mechanism remains in place, changes in the price of natural gas ~~ar e~~are not expected to materially impact net in come.

On October 6, 2005, the CPUC approved the Utility's hedging plan for the winters of 2005-06, 2006-07, and 2007-08. Core customers will pay the cost of these hedges and receive any payouts as these transactions are handled outside of the CPIM. The Utility is at risk to the extent that the CPUC may disallow portions of the hedging cost if the Utility does not follow its filed plan. As part of the hedging plan the Utility also has agreed to forego a shareholder award under the CPIM for the 2004-2005 CPIM year.

Nuclear Fuel

The Utility purchases nuclear fuel for Diablo Canyon through contracts with terms ranging from two to five years. These long-term nuclear fuel agreements are with large, well-established international producers in order to diversify its commitments and provide security of supply.

Some nuclear fuel purchases are subject to tariffs of up to 20% on imports from certain countries. The Department of Commerce ruling that imposed these tariffs is currently under appeal. The prices under existing and future contracts may be higher as a result of such tariffs. In addition, because of an increase in the United States' demand for uranium compared with the domestic supply, uranium prices are trending higher in 2005. During the quarter ended September 30, 2005, the Utility entered into two nuclear fuel purchase agreement for delivery of uranium concentrates in years 2005 through 2008, one agreement for the delivery of uranium enrichment services in 2005, and one agreement for the delivery of uranium enrichment services in years 2007 through 2009. These contracts do not meet the definition of derivative instruments as they are not subject to net settlement. Therefore, these contracts are subject to a ccrual accounting and will not be marked to market on the financial statements.

As the Utility continues to replace contracts that expired at the end of 2004 with new higher priced uranium contracts, nuclear fuel costs will rise. These costs are recovered in the ERRA (see the "Electricity Generation Resources" section of this MD&A), therefore, the changes in nuclear fuel prices are not expected to materially impact net income.

Transportation and Storage

The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers. Non-core customers contract with the Utility for natural gas transportation and storage, along with natural gas parking and lending (market center) services. The Utility is at risk for any natural gas transportation and storage revenue volatility. Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. There are significant seasonal and annual variations in the demand for natural gas transportation and storage services. The Utility sells most of its pipeline capacity based on the volume of natural gas that is transported by its customers. As a result, the Utility's natural gas transportation revenues fluctuate.

The Utility uses value-at-risk to measure the Utility's exposure to market conditions that could impact transportation and storage revenues based on changes in market prices and demand for pipeline and storage services over a rolling 12-month holding period. This calculation is based on a 99% confidence level, which means that there is a 1% probability that the impact to revenues on a pre-tax basis will be at least as large as the reported value-at-risk. The Utility's value-at-risk calculated under this methodology was approximately ~~$31~~$39 million at ~~June~~September 30, 2005. The Utility's high, low, and average value-at-risk during the three months ended ~~June~~September 30, 2005 were approximately ~~$39~~$42 million, ~~$31~~$33 million and ~~$35~~$36 million, respectively. Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, inadequate indication of the exposure of a portfolio to extreme price ~~movements~~movemen ts and not capturing the intra-day risk related to position changes.

Beginning January 1, 2005, the Utility began calculating value-at-risk using the methodology described above on a prospective basis only. For comparative purposes in 2005, the Utility will continue to report value-at-risk for the transportation and storage portfolio under the methodology formerly used in addition to value-at-risk calculated under the enhanced methodology.

Prior to January 1, 2005, the Utility used value-at-risk to measure the expected maximum change over a one-day period in the rolling 18-month forward value of its transportation and storage portfolio. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a loss in value in one day at least as large as the reported value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95% probability that the value of the portfolio resulting from a one-day price movement would not decline by more than $5 million. This value-at-risk methodology provides an indication of the Utility's exposure to potential market conditions that could impact revenues based on one-day price changes.

The Utility's daily value-at-risk for its transportation and storage portfolio calculated under the methodology used prior to January 1, 2005 was approximately $2$5 million at ~~June~~September 30, 2005 and approximately $3$4 million at ~~June~~September 30, 2004. A comparison of daily values-at-risk is included in order to provide context around the one-day amounts. The Utility's high, low and average transportation and storage value-at-risk during the ~~six~~nine months ended ~~June~~September 30, 2005 were approximately $4$5 million, $1 million and $2 million, respectively. The Utility's high, low and average transportation and storage value-at-risk during the ~~six~~nine months ended ~~June~~September 30, 2004 were approximately $6 million, $2 million and $4$3 million, respectively.

Value-at-risk calculated under the methodology used prior to January 1, 2005 has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, mismatch of one-day liquidation period assumed in the value-at-risk methodology as compared to the longer term holding period of the storage and transportation portfolio, and inadequate indication of the exposure of a portfolio to extreme price movements. In addition, this value-at-risk methodology does not measure intra-day risk from position changes nor does it measure volumetric uncertainty in the demand for pipeline services.

Due to the limitations of this value-at-risk methodology, the Utility enhanced the calculation methodology as described above to (1) capture uncertainty with respect to demand (volumetric uncertainty) for pipeline services, (2) reflect the market conditions in which the pipeline operates by increasing the holding period to 12 months, and (3) include the uncertainty associated with the option exposure in the pipeline portfolio.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on variable rate obligations.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At ~~June~~September 30, 2005, 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 an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

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.

PG&E Corporation had gross accounts receivable of approximately ~~$2.1~~$2.2 billion at ~~June~~September 30, 2005 and ~~approximately $2.2 billion at~~ December 31, 2004. The majority of the accounts receivable were associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately ~~$91~~$105 million at ~~June~~September 30, 2005 and approximately $93 million at December 31, 2004 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not ~~considered~~c onsidered likely.

The Utility manages credit risk for its wholesale customers and counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility's wholesale customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes ~~immediate~~ action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies heavily on 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 Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today), plus or minus any outstanding net receivables or payables, before the application of credit collateral. During the three months ended ~~June~~September 30, 2005, the Utility recognized no material losses due to contract defaults or bankruptcies. At June 30, 2005, there were two counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. Both of these counterparties were investment grade, representing a total of approximately 44% of the Utility's net wholesale credit exposure.

CRITICAL ACCOUNTING POLICIES

The preparation of Consolidated Financial Statements in accordance with Generally Accepted Accounting Principles, or GAAP, involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial condition 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 outlined below.

Regulatory Assets and Liabilities

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No.71, "Accounting for the Effects of Certain Types of Regulation," as amended, or 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 except for the operations of a natural gas pipeline.

Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be ~~charged~~recorded to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable, as defined in SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5, that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, CPUC and FERC administrative law judge proposed decisions, final regulatory orders and the strength or status of applications for regulatory rehearings or state court appeals. The Utility also maintains regulatory balancing ~~a ccounts,~~accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that can be recovered through rates.

If the Utility determined that it could not apply SFAS No. 71 to its operations or, if under SFAS No. 71 it could not conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be ~~charged~~recorded to income in the period in which they were incurred. If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At ~~June~~September 30, 2005, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately ~~$7.1 billion~~$6.5billion and regulatory liabilities (including current balancing accounts payable) of approximately ~~$4.9~~$5.1 billion.

Unbilled Revenues

The Utility records revenue as electricity and natural gas are delivered. A portion of the revenue recognized has not yet been billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with recent historical usage and rate patterns. At ~~June~~September 30, 2005, the Utility had recorded approximately ~~$550~~$580 million in unbilled revenues.

Environmental Remediation Liabilities

Given the complexities of the legal and regulatory environment regarding environmental laws, the process of estimating environmental remediation liabilities is a subjective one. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable, as defined in SFAS No. 5, and the cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At ~~June~~September 30, 2005, the Utility's accrual for undiscounted environmental liability was approximately ~~$410~~$414 million. The Utility's undiscounted future costs could increase to as much as ~~$578~~$584 million if other potentially responsible parties are not able to contribute to the settlement of these costs or the extent of contamination or necessary remediation is greater than anticipated.

Asset Retirement Obligations

The Utility accounts for its nuclear generation and certain fossil generation facilities under SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process.

There are uncertainties regarding the ultimate cost associated with retiring the assets the Utility has accounted for in accordance with SFAS No. 143. These include, but are not limited to changes in assumed dates of decommissioning, regulatory requirements, technology, cost of labor, materials, and equipment. At ~~June~~September 30, 2005, the Utility's estimated cost of retiring these assets was approximately ~~$1.3~~$1.4 billion.

Pension and Other Postretirement Plans

Certain employees and retirees of PG&E Corporation and its subsidiaries participate in qualified and non-qualified non-contributory defined benefit pension plans. Certain retired employees and their eligible dependents of PG&E Corporation and its subsidiaries also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as other benefits). Amounts that PG&E Corporation and the Utility recognize as costs and obligations to provide pension benefits under SFAS No. 87, "Employers' Accounting for Pensions," and other benefits under SFAS No. 106, "Employers Accounting for Postretirement Benefits other than Pensions," are based on a variety of factors. These factors include the provisions of the plans, employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the ~~comp lexity~~complexit y of these calculations, the long-term nature of these obligations and the importance of the assumptions utilized, PG&E Corporation's and the Utility's estimate of these costs and obligations is a critical accounting estimate.

In accordance with accounting rules, changes in benefit obligations associated with these assumptions may not be recognized as costs on the income statement. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-value of the related plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery is based on the lesser of the amounts collected in rates or the annual contributions on a tax-deductible basis to the appropriate trusts.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Refer to Note 1 in the Notes to the Condensed Consolidated Financial Statements for further discussion.

ADDITIONAL SECURITY MEASURES

Various federal regulatory agencies have issued guidance and the NRC has issued orders regarding additional security measures to be taken at various facilities, including generation facilities, transmission substations and natural gas transportation facilities. The guidance and the orders require additional capital investment and increased operating costs. However, neither PG&E Corporation nor the Utility believes that these costs will have a material impact on its respective consolidated financial condition or results of operations.

ENVIRONMENTAL AND LEGAL MATTERS

PG&E Corporation and the Utility are subject to laws and regulations established both to maintain and improve the quality of the environment. Where PG&E Corporation's and the Utility's properties contain hazardous substances, these laws and regulations may require PG&E Corporation and the Utility to remove those substances or to remedy effects on the environment.

In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion. As previously disclosed, the Utility has recorded a $160 million reserve in its financial statements with respect to the chromium litigation described in Note 7. Given recent rulings and appellate writs regarding the Utility's motions, and the California Supreme Court's current review of similar issues in unrelated litigation, PG&E Corporation and the Utility are unable to predict whether the ultimate outcome of this matter, after taking into account the amount already reserved at ~~June~~September 30, 2005, would have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation's and ~~Pacific Gas and Electric Company's, or~~ the Utility's primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management, or PRM, activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these PRM activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See the "Risk Management Activities" section included in Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations).

ITEM 4: CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation's and ~~Pacific Gas and Electric Company's, or~~ the Utility's disclosure controls and procedures as of ~~June~~September 30, 2005, 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 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

As of January 1, 2004, PG&E Corporation and the Utility adopted Financial Accounting Standards Board, or FASB, revision to FASB Interpretation No. 46, ''Consolidation of Variable Interest Entities,'' or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of low-income housing partnerships that were determined to be variable interest entities, or VIEs, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of VIEs. Therefore, PG&E Corporation's and the Utility's evaluation of disclosure controls and procedures performed as of ~~June~~September 30, 2005 did not include these entities in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for consolidated VIEs.

There were no changes in internal controls over financial reporting that occurred during the quarter ended ~~June~~September 30, 2005, 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

For additional information regarding certain of the legal proceedings presented below, see Note 7 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company Chapter 11 Filing

On June 13, 2005, the California Court of Appeal summarily denied the petitions for review of the California Public Utilities Commission's, or the CPUC's, order approving the Settlement Agreement and order denying rehearing of its approval order that had been filed by the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet. CCSF and Aglet have not appealed the appellate court's denial of their petitions and the time period within which an appeal could be filed has elapsed.

In addition, two former CPUC commissioners who did not vote to approve the Settlement Agreement filed an appeal of the bankruptcy court's confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed their appeal. The former commissioners have appealed the District Court's order with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Briefing is complete, and the Ninth Circuit is likely to schedule oral arguments on the appeal by the end of the year. On April 12, 2005, the District Court entered an order dismissing a second appeal of the confirmation order that had been filed by the City of Palo Alto, but which the City of Palo Alto subsequently had agreed to dismiss voluntarily.

PG&E Corporation and Pacific Gas and Electric Company, or the Utility, believe the former commissioners' appeal of the confirmation order is without merit and will be rejected. If the bankruptcy court's confirmation order or the Settlement Agreement is overturned or modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations, and the Utility's ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected.

The Utility's Chapter 11 proceeding has been previously disclosed in PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K in "Part I, Item 3: Legal Proceedings" and in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the ~~quarter~~quarters ended March 31, 2005 and June 30, 2005 in "Part II, Item 1: Legal Proceedings." For additional information, see Note 2 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company v. Michael Peevey, et al.

For information regarding this matter, see "Part I, Item 3: Legal Proceedings" in PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K.

In re: Natural Gas Royalties Qui Tam Litigation

For information regarding this matter, see "Part I, Item 3: Legal Proceedings" in PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K.

Diablo Canyon Power Plant

For information regarding matters relating to the Diablo Canyon Power Plant, see PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K.

Compressor Station Chromium Litigation

~~The~~On October 3, 2005, the Utility ~~has filed 14 motions in~~received a ruling issued by the Superior Court for the County of Los Angeles, or Superior Court, ~~challenging~~granting one of the ~~test~~Utility's pre-trial motions in litigation brought against the Utility by plaintiffs who allege that exposure to chromium at or near certain of the Utility's natural gas compressor stations caused personal injuries, wrongful deaths, or other injuries, or the Chromium Litigation. As a result of the ruling, the Superior Court dismissed one plaintiff who was scheduled to participate in the first trial who claimed that chromium caused her Crohn's disease. The ruling also applies to seven other plaintiffs who are claiming that exposure to chromium caused them to contract Crohn's disease. Also, on September 20, 2005, in response to another pre-trial motion that had been filed by the Utility, three plaintiffs who were scheduled to participate in the first trial voluntarily di smissed their claims. These pre-trial motions challenged the plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries. ~~In February~~However, as previously disclosed, the Superior Court has denied other pre-trial motions made by the Utility and also has denied the Utility's motions for reconsideration of the denials. On October 19, 2005, the Superior Court ~~denied two of these motions.~~took under submission the Utility's motion for summary judgment that plaintiffs have failed to prove that exposure to chromium caused leukemia.

The Utility ~~filed motions for reconsideration~~has sought appellate court review of ~~these orders with~~ the Superior ~~Court and also filed a request with~~Court's denials of the ~~appellate court seeking to overturn or modify~~Utility's earlier pre-trial motions based on the ~~orders because~~argument that they are inconsistent with recent California appellate decisions (one of which is now under review by the California Supreme Court) concerning the admissibility of expert testimony and the requirements for proving medical causation. ~~After these motions for reconsideration and~~The Utility also requested the ~~request were filed,~~appellate court to order the Superior Court to stay the upcoming trial until after the California Supreme Court ~~granted review of one of these recent~~issues its decision. The appellate ~~decisions. In April~~court ordered the plaintiffs to file a brief addressing the issues raised by the Utility. Plaintiffs' brief was filed on September 23, 2005 and the ~~Superior Court heard arguments~~Utility's responses were filed on ~~both motions for reconsideration~~September 30 and ~~denied~~October 3, 2005. The appellate court's decision as to whether to consider the ~~motions in July 2005.~~

~~On June 9, 2005, the Superior Court denied another~~merits of the Utility's ~~motions~~appeal is still pending.

The trial for the 14 remaining plaintiffs who were selected to ~~exclude evidence,~~participate in the first trial was scheduled to begin on January 9, 2006, but has been moved to February 7, 2006. Counsel for the Utility and counsel for the plaintiffs are engaged in settlement discussions. PG&E Corporation and the Utility ~~filed a motion for reconsideration. On July 18, 2005,~~cannot predict the ~~Superior Court denied this motion for reconsideration. The Superior Court denied another~~outcome of ~~the Utility's motions to exclude evidence on June 29, 2005.~~these discussions.

As previously disclosed, the Utility has recorded a $160 million reserve in its financial statements with respect to the chromium litigation. Given recent rulings and appellate writs regarding the Utility's motions, and the California Supreme Court's current review of similar issues in unrelated litigation, PG&E Corporation and the Utility are no longer able to predict whether the ultimate outcome of this matter, after taking into account the amount already reserved at ~~June~~September 30, 2005, would have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations. The dismissals entered on September 20 and the October 3 ruling have not altered this assessment of the ultimate outcome of the Chromium Litigation.

For more information regarding the ~~chromium litigation,~~Chromium Litigation, see "Part I, Item 3: Legal Proceedings" in PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K, "Part II, Item 1: Legal Proceedings" in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the ~~quarter~~quarters ended March 31, 2005, and June 30, 2005, and Note 7 to the Notes to the Condensed Consolidated Financial Statements.

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

On May 17, 2005, the plaintiffs filed a petition with the California Court of Appeal seeking an order requiring the San Francisco Superior Court, or Superior Court, to vacate its March 2005 decision finding that the standard for calculating the number of alleged violations of Section 17200 in this case is a "per act" test (not the "per victim" and "per [customer] bill" standards advocated by the plaintiffs). Plaintiffs argued that, by selecting the "per act" test to determine the number of violations, the Superior Court decided disputed factual questions and improperly exceeded the scope of the legal issue defined for the bifurcated trial. PG&E Corporation filed a response on June 9, 2005, pointing out that the Superior Court's March 2005 decision resolved only the legal question of what standard should be applied in determining the number of Section 17200 violations, that the issues raised by the plaintiffs ar e not yet ripe for decision, and that the March 2005 ruling does not preclude discovery, as plaintiffs claim. On July 27, 2005, the California Court of Appeal summarily denied plaintiffs' petition.

As previously ordered by the Superior Court, in June 2005, the plaintiffs provided a definitive list of transactions they claim violate Section 17200. In order to add to this list later, plaintiffs will be required to show good cause. At a case management conference on July 20, 2005, the Superior Court directed plaintiffs to update their transactions list by explaining why the transactions were allegedly unlawful under Section 17200. The next case management conference is scheduled for September 22, 2005.

For more information regarding these cases, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2004 Annual Report on Form 10-K and "Part II, Item 1: Legal Proceedings" of PG&E Corporation's and the Utility's combined Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, 2005 and June 30, 2005.

Nuclear Regulatory Commission Findings Regarding Retired Nuclear Facility at Humboldt Bay

On August 19, 2005, the NRC issued an inspection report concluding that the Utility was unable to account for the location of three 18-inch segments of used nuclear fuel at its retired nuclear generation facility at Humboldt Bay near Eureka, California. The NRC issued its report after the Utility filed its final report in May 2005 updating the NRC as to the Utility's efforts to locate the used fuel. In June 2004, the Utility notified the NRC when the Utility discovered that it had conflicting records on the location of three, 18-inch long cut segments. These records indicate that the segments were either stored in the used fuel pool in 1968 or were shipped to a licensed nuclear waste reprocessing facility in 1969.

The Utility's final report to the NRC in May 2005 details the work that was conducted to determine the possible location of the segments and to rule out unlikely locations and scenarios. These activities included: 1) a meticulous review of the records, record-keeping processes and reporting associated with the used fuel pool and with shipments of used fuel and other radioactive materials; 2) interviews of former and current plant personnel and contractors; 3) a physical search of the used fuel pool and the rest of the Humboldt Bay site; 4) an analysis of the possibility of theft or diversion; and 5) an analysis of the cause of the problem. In the process, the Utility also established a more accurate inventory for all spent nuclear material stored onsite. In its report, the Utility reaffirmed to the NRC that the Utility has current controls in place for storing and accounting for these materials. The Utility's exh austive investigation points to two reasonable possibilities regarding the location of the fuel segments: 1) they remain in the used fuel pool as broken, fragments rather than as intact, 18-inch cut segments, or 2) they were shipped offsite to one of three licensed facilities. The condition of the apparently cut fuel rod fragments - after nearly 40 years of storage in a container within the used fuel pool under other irradiated material - makes conclusive positive identification very difficult. The conclusion that the fuel fragments may have been found in the used fuel pool over the last year is supported by an independent expert analysis. The Utility's final report also documents findings related to four very small pieces of non-fuel nuclear material which could not be located during the comprehensive physical inventory. The Utility's report concludes that it is very likely that these pieces were shipped to a low level radioactive waste facility.

In its August 19, 2005 report, the NRC determined that the Utility's inability to conclusively locate the used fuel did not pose any threat to the health and safety of the public. The NRC's report states that it is considering taking escalated enforcement action against the Utility and may impose penalties on the Utility for failure to keep full and complete inventory records of these materials.

PG&E Corporation and the Utility do not believe that the ultimate outcome of this matter will have a material adverse effect on their results of operations or financial condition.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931 shares of common stock of PG&E Corporation at an exercise price of $0.01 per share. During the quarter ended ~~June~~September 30, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase ~~125,673~~18,919 shares, and received ~~125,635~~18,913 shares of PG&E Corporation common stock. As of ~~June~~September 30, 2005, warrant holders had exercised, on a net exercise basis, warrants to purchase ~~4,922,549~~4,941,468 shares, and had received ~~4,920,758~~4,939,671 shares of PG&E Corporation common stock since the warrants were issued.

~~Pacific Gas and Electric Company, or the~~The Utility did not make any sales of unregistered equity securities during the quarter ended ~~June~~September 30, 2005, the period covered by this report.

Issuer Purchases of Equity Securities

Period
Total Number of Shares Purchased

Average Price Paid Per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾⁽³⁾

Approximate Dollar Value of Shares that may yet be Purchased Under the Plans or Programs

Preferred Stock

Common Stock

Preferred Stock

Common Stock

Preferred Stock

Common Stock

Preferred Stock

Common
Stock
April 1 through April 30, 2005

-

-
$
-
$
-

-

-
$
-
$
-
May 1 through May 31, 2005

4,800,000⁽¹⁾

-
$
25.13424
$
-

-

-
$
-
$
-
June 1 through June 30, 2005

-

-

-

-

-

-

-

-
Total
4,800,000

-
$
25.13424
$
-

-

-
$
-
$
-

(1)
On May 31, 2005, the Utility redeemed all outstanding shares of the Utility's 6.57% Redeemable First Preferred Stock and 6.30% Redeemable First Preferred Stock totaling approximately $120 million aggregate par value. In addition to the $25 per share redemption price, holders of the 6.57% Redeemable First Preferred Stock and the 6.30% Redeemable First Preferred Stock received an amount equal to all accumulated and unpaid dividends on such shares to and including May 31, 2005.
(2)
On September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time to time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.
(3)
As previously reported, on December 15, 2004, PG&E Corporation's Board of Directors authorized the repurchase of up to $975 million of its outstanding common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors of PG&E Corporation increased the repurchase authorization to $1.05 billion with such repurchases to be effected from time to time, but no later than June 30, 2006. As disclosed in a Form 8-K filed on March 4, 2005, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on March 4, 2005, under which PG&E Corporation repurchased 29,489,400 shares for an aggregate purchase price of approximately $1.05 billion. On June 16, 2005, PG&E Corporation entered into a new share forward agreement with the broker based on 11,430,000 shares to complete the balance of the March 4, 2005 arrangement. For furth er information, see the "Liquidity and Financial Resources" section included in Part I, Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

On April 20, 2005, PG&E Corporation and Pacific Gas and Electric Company held their joint annual meeting of shareholders. Information regarding the voting results of the meetings is contained in PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, Part II, Item 4.

Period		Total Number of Shares Purchased			Average Price Paid Per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(2)(3)(4)			Approximate Dollar Value of Shares that may yet be Purchased Under the Plans or Programs

		Preferred Stock	Common Stock		Preferred Stock		Common Stock	Preferred Stock	Common Stock		Preferred Stock		Common Stock

July1 through July 31, 2005		-	-	$	-	$	-	-	-	$	-	$	-
August 1 through August 31, 2005		1,438,498⁽¹⁾	-	$	25.84667	$	-	-	-	$	-	$	-
September 1 through September 30, 2005		-	-		-		-	-	-		-		-

Total		1,438,498	-	$	25.84667	$	-	-	-	$	-	$	-






(1)	On August 31, 2005, the Utility redeemed all outstanding shares of the Utility's 7.04% Redeemable First Preferred Stock totaling approximately $36 million aggregate par value plus approximately $1 million related to a $0.70 redemption premium. In addition to the $25.70 per share redemption price, holders of the 7.04% Redeemable First Preferred Stock received an amount equal to all accumulated and unpaid dividends on such shares to and including August 31, 2005.
(2)	On September 15, 2004, the PG&E Corporation Board of Directors authorized PG&E Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time to time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.
(3)	As previously reported, on December 15, 2004, the PG&E Corporation Board of Directors authorized the repurchase of up to $975 million of its outstanding common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors of PG&E Corporation increased the repurchase authorization to $1.05 billion with such repurchases to be effected from time to time, but no later than June 30, 2006. As disclosed in a Form 8-K filed on March 4, 2005, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on March 4, 2005, under which PG&E Corporation repurchased 29,489,400 shares for an aggregate purchase price of approximately $1.05 billion. On June 16, 2005, PG&E Corporation entered into a new share forward agreement with the broker based on 11,430,000 shares to complete the balance of the March 4, 2005 arrangement. For fur ther information, see the "Liquidity and Financial Resources" section included in Part I, Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations.
(4)	On October 19, 2005, the PG&E Corporation Board of Directors authorized PG&E Corporation and its subsidiaries to repurchase up to $1.6 billion in shares of PG&E Corporation's common stock, from time to time, but no later than December 31, 2006 (although the actual repurchase or activity under the repurchase arrangements may occur after that date). The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 21, 2005. Such repurchases are contingent on PG&E Corporation's receipt of sufficient cash from the Utility. For further information, see the "Liquidity and Financial Resources" section included in Part I, Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 5. OTHER INFORMATION

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

~~Pacific Gas and Electric Company, or the~~The Utility's, earnings to fixed charges ratio for the three months and nine months ended ~~June~~September 30, 2005, was ~~4.35.~~3.71 and 3.74, respectively. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months and nine months ended ~~June~~September 30, 2005, was ~~4.10.~~3.59 and 3.57, respectively. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into the Utility's Registration Statement Nos. 33-62488 and 333-109994 relating to various series of the Utility's first preferred stock and its senior notes, respectively.

ITEM 6. EXHIBITS

3.1	Bylaws of ~~Pacific Gas and Electric Company~~PG&E Corporation amended as of ~~June 15, 2005~~
~~10.1~~	Master Confirmation dated March 4, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co., as amended and supplemented by a Supplemental Confirmation dated June 16,October 19, 2005
10.2*	~~Supplemental Executive Retirement Plan of PG&E Corporation, as amended effective as of June 15, 2005~~
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.

~~SIGNATURES~~

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

~~PG&E CORPORATION~~
~~CHRISTOPHER P. JOHNS~~
~~Christopher P. Johns~~
~~Senior Vice President and Controller~~
~~(duly authorized officer and principal accounting officer)~~

~~PACIFIC GAS AND ELECTRIC COMPANY~~
~~DINYAR B. MISTRY~~
~~Dinyar B. Mistry~~
~~Vice President and Controller~~
~~(duly authorized officer and principal accounting officer)~~

~~Dated: August 3, 2005~~

~~EXHIBIT INDEX~~

~~3.1~~3.2	Bylaws of Pacific Gas and Electric Company amended as of ~~June 15,~~October 19, 2005
~~10.1~~10.1*	~~Master Confirmation~~Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated ~~March 4, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co., as amended and supplemented by a Supplemental Confirmation dated June 16,~~September 21, 2005
10.2*	~~Supplemental Executive Retirement Plan~~Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation ~~as amended effective as~~Board of ~~June 15,~~Directors on October 19, 2005
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.

SIGNATURES

PG&E CORPORATION
G. ROBERT POWELL
G. Robert Powell
Vice President and Controller
(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY
DINYAR B. MISTRY
Dinyar B. Mistry
Vice President and Controller
(duly authorized officer and principal accounting officer)

Dated: November 2, 2005

EXHIBIT INDEX


3.1	Bylaws of PG&E Corporation amended as of October 19, 2005
3.2	Bylaws of Pacific Gas and Electric Company amended as of October 19, 2005
10.1*	Severance Agreement and Release by and between Pacific Gas and Electric Company and Gordon R. Smith dated September 21, 2005
10.2*	Actions taken by the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors on October 19, 2005
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.

Other Long Term Debt Guarantees⁽¹⁾

(in millions)

Utility				At June 30, 2005

Facility	Series	Termination Date		Commitment			Outstanding

Pollution control bond bank reimbursement agreements	96 C, E, F, 97 B	April 2010		$	620	$	620
Pollution control bond -- bond insurance reimbursement agreements	96A	December 2016	(2)		200		200
Pollution control bond -- bond insurance reimbursement agreements	2004 A -- D	December 2023	(2)		345		345
Pollution control bond -- bond insurance reimbursement agreements	2005 A -- G	2016 -- 2026	(2)		454		454

				$	1,619	$	1,619






(1) Off-balance sheet commitments
(2) Principal and debt service insured by the bond insurance company

ROE	Customer	Shareholder

Below 10.72%	50%	50%
10.72% - 11.72%	0%	100%
11.73% - 14.22%	50%	50%
Above 14.22%	100%	0%