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 ~~September 30, 2004~~March 31, 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).

Yes X			No

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

Common Stock Outstanding, ~~October 27, 2004:~~April 28, 2005:
PG&E Corporation			~~403,127,461~~370,087,968 shares (excluding ~~23,815,500 shares~~24,665,500shares 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 ~~SEPTEMBER 30, 2004~~MARCH 31, 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		78
		Condensed Consolidated Balance Sheets		89
		Condensed Consolidated Statements of Cash Flows		1011
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	1113
	NOTE 2:		The Utility's Emergence from Chapter 11 ~~Filing~~	2122
	NOTE 3:		Debt	2522
	NOTE 4:		~~Discontinued Operations~~Energy Recovery Bonds	3027
	NOTE 5:		Shareholders' Equity	28
	NOTE 6:		Risk Management Activities	29
	NOTE 5:7:		~~Price Risk Management~~Commitments and Contingencies	31
	NOTE 6:8:		~~Commitments and Contingencies~~Subsequent Events	3338

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			4439
	Results of Operations			5144
	Liquidity and Financial Resources			5649
	Contractual Commitments			54
	Capital Expenditures ~~and Commitments~~			6155
	~~Regulatory Matters~~Off-Balance Sheet Arrangements			6455
	Contingencies			55
	Risk Management Activities			7458
	Critical Accounting Policies			7762
	Accounting Pronouncements Issued But Not Yet Adopted			63
	Taxation Matters			7863
	Additional Security Measures			7964
	Environmental and Legal Matters			7964

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			8064
ITEM 4.	CONTROLS AND PROCEDURES			8064

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			8166
ITEM 22..	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES			8267
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			68
ITEM 5.	OTHER INFORMATION			8370
ITEM 6.	EXHIBITS			8470

SIGNATURES				8572

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
(Unaudited)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2004
2003
2004
2003
Operating Revenues
   Electric
$
2,042
$
2,509
$
5,902
$
5,921
   Natural gas
581
553
2,198
2,037
      Total operating revenues
2,623
3,062
8,100
7,958
Operating Expenses
   Cost of electricity
792
661
2,003
1,813
   Cost of natural gas
239
234
1,096
1,011
   Operating and maintenance
677
678
2,297
2,113
   Recognition of regulatory assets
-
-
(4,900)
-
   Depreciation, amortization and decommissioning
406
312
1,056
910
   Reorganization professional fees and expenses
-
16
6
116
      Total operating expenses
2,114
1,901
1,558
5,963
Operating Income
509
1,161
6,542
1,995
   Reorganization interest income
-
9
8
36
   Interest income
15
6
46
13
   Interest expense
(159)
(342)
(565)
(857)
   Other income (expense), net
4
7
(46)
21
Income Before Income Taxes
369
841
5,985
1,208
   Income tax provision
141
333
2,352
454
Income From Continuing Operations
228
508
3,633
754
Discontinued Operations
   Gain/(Loss) from operations of NEGT
      (net of income tax benefit of $10 million and $230
      million for the three and nine months ended September       30, 2003)
-
2
-
(365)
Net Income Before Cumulative Effect of Changes
   in Accounting Principles
228
510
3,633
389
      Cumulative effect of changes in accounting principles
        of $(5) million in 2003 related to discontinued
        operations (net of income tax benefit of $3 million)         and $(1) million related to continuing operations (net         of income tax of $1 million)
-
-
-
(6)
Net Income
$
228
$
510
$
3,633
$
383
Weighted Average Common Shares Outstanding, Basic
399
387
397
384
Earnings Per Common Share
   from Continuing Operations, Basic
$
0.55
$
1.25
$
8.73
$
1.87
Net Earnings Per Common Share, Basic
$
0.55
$
1.26
$
8.73
$
0.95
Earnings Per Common Share
   from Continuing Operations, Diluted
$
0.53
$
1.22
$
8.55
$
1.84
Net Earnings Per Common Share, Diluted
$
0.53
$
1.23
$
8.55
$
0.93
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance At
(in millions)
September 30,
December 31,
2004
(Unaudited)
2003
ASSETS
Current Assets
   Cash and cash equivalents
$
1,856
$
3,658
   Restricted cash
2,365
403
   Accounts receivable:
     Customers (net of allowance for doubtful accounts of $63 million
       in 2004 and $68 million in 2003)
1,958
2,424
     Related parties
-
15
     Regulatory balancing accounts
849
248
   Inventories:
     Gas stored underground
226
166
     Materials and supplies
127
126
   Prepaid expenses and other
57
108
      Total current assets
7,438
7,148
Property, Plant and Equipment
   Electric
21,192
20,468
   Gas
8,468
8,355
   Construction work in progress
417
379
   Other
18
20
      Total property, plant and equipment
30,095
29,222
   Accumulated depreciation
(11,395)
(11,115)
      Net property, plant and equipment
18,700
18,107
Other Noncurrent Assets
   Restricted cash
-
361
   Regulatory assets
6,635
2,001
   Nuclear decommissioning funds
1,539
1,478
   Other
1,058
1,109
      Total other noncurrent assets
9,232
4,949
TOTAL ASSETS
$
35,370
$
30,204
See accompanying Notes to the Condensed Consolidated Financial Statements.

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

(in millions, except per share amounts)	Three Months Ended
	March 31,

	2005		2004

Operating Revenues
Electric	$	1,660	$		1,791
Natural gas	1,009		931

Total operating revenues	2,669		2,722

Operating Expenses
Cost of electricity	396		561
Cost of natural gas	620		578
Operating and maintenance	767		816
Recognition of regulatory assets	-		(4,900)
Depreciation, amortization and decommissioning	385		312
Reorganization professional fees and expenses	-		2

Total operating (gain) expenses	2,168		(2,631)

Operating Income	501		5,353
Reorganization interest income	-		8
Interest income	21		6
Interest expense	(161)		(231)
Other expense, net	(1)		(27)

Income Before Income Taxes	360		5,109
Income tax provision	142		2,076

Net Income	$	218	$	3,033



Weighted Average Common Shares Outstanding, Basic	388		393



Net Earnings Per Common Share, Basic	$	0.55	$	7.36



Net Earnings Per Common Share, Diluted	$	0.54	$	7.15



Dividends Declared Per Common Share	$	0.30	$	-

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,
2004
(Unaudited)
2003
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
   Long-term debt, classified as current
$
457
$
310
   Rate reduction bonds, classified as current
290
290
   Accounts payable:
     Trade creditors
485
657
     Disputed claims
2,142
-
     Regulatory balancing accounts
464
186
     Other
444
402
   Interest payable
398
174
   Income taxes payable
305
256
   Other
1,124
899
      Total current liabilities
6,109
3,174
Noncurrent Liabilities
   Long-term debt
8,726
3,314
   Rate reduction bonds
657
870
   Regulatory liabilities
3,980
3,979
   Asset retirement obligations
1,280
1,218
   Deferred income taxes
3,049
856
   Deferred tax credits
122
127
   Investment in NEGT
1,211
1,216
   Preferred stock of subsidiary with mandatory redemption provisions
122
137
   Other
1,840
1,494
      Total noncurrent liabilities
20,987
13,211
Liabilities Subject to Compromise
   Financing debt
-
5,603
   Trade creditors
-
3,715
      Total liabilities subject to compromise
-
9,318
Commitments and Contingencies (Notes 1, 2, 3, 4, and 6)
-
-
Shareholders' Equity
   Preferred stock of subsidiaries
286
286
   Preferred stock, no par value, 80,000,000 shares, $100 par value,
     5,000,000 shares, none issued
-
-
   Common stock, no par value, authorized 800,000,000 shares,
     issued 425,035,028 common and 1,613,067 restricted shares in
     2004 and 412,147,679 common and 1,577,770 restricted
     shares in 2003
6,609
6,468
   Common stock held by subsidiary, at cost,23,815,500 shares
(690)
(690)
   Unearned compensation
(25)
(20)
   Accumulated earnings (deficit)
2,175
(1,458)
   Accumulated other comprehensive loss
(81)
(85)
      Total shareholders' equity
8,274
4,501
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
$
35,370
$
30,204
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

(in millions)	March 31,		December 31,
	2005 (Unaudited)		2004

ASSETS
Current Assets
Cash and cash equivalents	$	1,381	$	972
Restricted cash	1,858		1,980
Accounts receivable:
Customers (net of allowance for doubtful accounts of $88 million in 2005 and $93 million in 2004)	1,916		2,085
Regulatory balancing accounts	968		1,021
Inventories:
Gas stored underground	83		175
Materials and supplies	131		129
Prepaid expenses and other	55		46

Total current assets	6,392		6,408

Property, Plant and Equipment
Electric	21,689		21,519
Gas	8,574		8,526
Construction work in progress	518		449
Other	15		15

Total property, plant and equipment	30,796		30,509
Accumulated depreciation	(11,728)		(11,520)

Net property, plant and equipment	19,068		18,989

Other Noncurrent Assets
Regulatory assets	6,412		6,526
Nuclear decommissioning funds	1,627		1,629
Other	938		988

Total other noncurrent assets	8,977		9,143

TOTAL ASSETS	$	34,437	$	34,540




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
(in millions)
September 30,
2004
2003
Cash Flows From Operating Activities
   Net income (loss)
$
3,633
$
383
   Loss from discontinued operations
-
365
   Cumulative effect of changes in accounting principles
-
6
   Net income from continuing operations
3,633
754
   Adjustments to reconcile net income (loss) to net cash provided by operating activities:
      Depreciation, amortization and decommissioning
1,056
910
      Recognition of regulatory assets
(4,900)
-
      Deferred income taxes and tax credits, net
2,360
339
      Other deferred charges and noncurrent liabilities
(183)
636
      Loss from retirement of long-term debt
-
89
      Gain on sale of assets
(18)
(10)
   Net effect of changes in operating assets and liabilities:
      Restricted cash
150
(28)
      Accounts receivable - customer
42
(23)
      Inventories
(61)
(96)
      Accounts payable - trade
78
262
      Accrued taxes
4
517
      Regulatory balancing accounts, net
(323)
(397)
      Other working capital
572
(26)
   Payments authorized by the bankruptcy court on amounts classified as liabilities subject      to compromise
(1,022)
(83)
   Other, net
102
72
Net cash provided by operating activities
1,490
2,916
Cash Flows From Investing Activities
   Capital expenditures
(1,110)
(1,183)
   Proceeds from sale of assets
28
14
   Increase in restricted cash
(1,751)
-
   Other, net
(55)
(24)
Net cash used in investing activities
(2,888)
(1,193)
Cash Flows From Financing Activities
   Proceeds from issuance of long-term debt, net of issuance costs of $74 million
7,346
582
   Long-term debt matured, redeemed or repurchased
(7,553)
(1,067)
   Rate reduction bonds matured
(213)
(213)
   Preferred stock with mandatory redemption provisions redeemed
(15)
-
   Preferred dividends paid
(88)
-
   Common stock issued
121
120
   Other, net
(2)
(2)
Net cash provided by (used in) financing activities
(404)
(580)
Net change in cash and cash equivalents
(1,802)
1,143
Cash and cash equivalents at January 1
3,658
3,532
Cash and cash equivalents at September 30
$
1,856
$
4,675
Supplemental disclosures of cash flow information
   Cash received for:
      Reorganization interest income
$
13
$
30
   Cash paid for:
      Interest (net of amounts capitalized)
522
555
      Income taxes paid, net
96
(531)
      Reorganization professional fees and expenses
21
84
Supplemental disclosures of noncash investing and financing activities
   Transfer of liabilities and other payables subject to compromise from
     operating assets and liabilities
(2,877)
193
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

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

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$		-	$	300
Long-term debt, classified as current			457		758
Rate reduction bonds, classified as current	290			290
Energy recovery bonds, classified as current	197			-
Accounts payable:
Trade creditors	500			762
Disputed claims and customer refunds	2,142			2,142
Regulatory balancing accounts	574			369
Other	499			352
Interest payable	432			461
Income taxes payable	388			185
Deferred income taxes	374			394
Other	879			905

Total current liabilities	6,732			6,918

Noncurrent Liabilities
Long-term debt	6,722			7,323
Rate reduction bonds	506			580
Energy recovery bonds	1,691			-
Regulatory liabilities	3,869			4,035
Asset retirement obligations	1,325			1,301
Deferred income taxes	3,490			3,531
Deferred tax credits	119			121
Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,800,000 shares, due 2005-2009)	120			122
Other	1,756			1,690

Total noncurrent liabilities	19,598			18,703

Commitments and Contingencies (Notes 1, 2, 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 393,170,435 common and 1,400,062 restricted shares in 2005 and 417,014,431 common and 1,601,710 restricted shares in 2004	6,196			6,518
Common stock held by subsidiary, at cost, 24,665,500 shares	(718)			(718)
Unearned compensation	(31)			(26)
Accumulated earnings	2,379			2,863
Accumulated other comprehensive loss	(5)			(4)

Total common shareholders' equity	7,821			8,633

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	34,437		$	34,540




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions)
(Unaudited)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2004
2003
2004
2003
Operating Revenues
   Electric
$
2,042
$
2,509
$
5,902
$
5,921
   Natural gas
581
553
2,198
2,040
      Total operating revenues
2,623
3,062
8,100
7,961
Operating Expenses
   Cost of electricity
792
661
2,003
1,823
   Cost of natural gas
239
234
1,096
1,040
   Operating and maintenance
671
657
2,271
2,098
   Recognition of regulatory assets
-
-
(4,900)
-
   Depreciation, amortization, and decommissioning
405
311
1,054
916
   Reorganization professional fees and expenses
-
16
6
116
      Total operating expenses
2,107
1,879
1,530
5,993
Operating Income
516
1,183
6,570
1,968
   Reorganization interest income
-
9
8
36
   Interest income
11
2
36
6
   Interest expense (noncontractual interest expense of $31 million      for the nine months ended September 30, 2004, and $32 million      and $99 million for the three and nine months ended September      30, 2003, respectively)
(141)
(237)
(512)
(681)
   Other income, net
14
15
43
41
Income Before Income Taxes
400
972
6,145
1,370
   Income tax provision
152
383
2,410
508
Income Before Cumulative Effect of a Change in
   Accounting Principle
248
589
3,735
862
     Cumulative effect of change in accounting principle
       (net of income tax benefit of $1 million for the nine months
       ended September 30, 2003)
-
-
-
(1)
Net Income
248
589
3,735
861
   Preferred dividend requirement
4
6
17
18
Income Available for Common Stock
$
244
$
583
$
3,718
$
843
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,
2004
(Unaudited)
2003
ASSETS
Current Assets
   Cash and cash equivalents
$
980
$
2,979
   Restricted cash
2,004
403
   Accounts receivable:
     Customers (net of allowance for doubtful accounts of $63 million in 2004
       and $68 million in 2003)
1,958
2,424
     Related parties
3
17
     Regulatory balancing accounts
849
248
   Inventories:
     Gas stored underground
226
166
     Materials and supplies
127
126
   Prepaid expenses and other
53
100
      Total current assets
6,200
6,463
Property, Plant and Equipment
   Electric
21,193
20,468
   Gas
8,467
8,355
   Construction work in progress
417
379
      Total property, plant and equipment
30,077
29,202
   Accumulated depreciation
(11,377)
(11,100)
      Net property, plant and equipment
18,700
18,102
Other Noncurrent Assets
   Regulatory assets
6,635
2,001
   Nuclear decommissioning funds
1,539
1,478
   Other
997
1,051
      Total other noncurrent assets
9,171
4,530
TOTAL ASSETS
$
34,071
$
29,095
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)
September 30,
December 31,
2004
(Unaudited)
2003
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
   Long-term debt, classified as current
$
457
$
310
   Rate reduction bonds, classified as current
290
290
   Accounts payable:
     Trade creditors
484
657
     Disputed claims
2,142
-
     Related parties
33
224
     Regulatory balancing accounts
464
186
     Other
423
365
   Interest payable
383
153
   Income taxes payable
131
-
   Deferred income taxes
253
86
   Other
817
673
      Total current liabilities
5,877
2,944
Noncurrent Liabilities
   Long-term debt
7,844
2,431
   Rate reduction bonds
657
870
   Regulatory liabilities
3,980
3,979
   Asset retirement obligations
1,280
1,218
   Deferred income taxes
3,567
1,334
   Deferred tax credits
122
127
   Preferred stock with mandatory redemption provisions
122
137
   Other
1,736
1,464
      Total noncurrent liabilities
19,308
11,560
Liabilities Subject to Compromise
   Financing debt
-
5,603
   Trade creditors
-
3,899
      Total liabilities subject to compromise
-
9,502
Commitments and Contingencies (Notes 1, 2, 3 and 6)
-
-
Shareholders' Equity
   Preferred stock without mandatory redemption provisions
     Nonredeemable, 5% to 6%, outstanding 5,784,825shares
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 321,314,760 shares
1,606
1,606
   Common stock held by subsidiary, at cost, 19,481,213 shares
(475)
(475)
   Additional paid-in capital
2,040
1,964
   Reinvested earnings
5,424
1,706
   Accumulated other comprehensive loss
(3)
(6)
      Total shareholders' equity
8,886
5,089
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
$
34,071
$
29,095
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
PG&E CORPORATION							PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS						CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
		(Unaudited)
								(Unaudited)
		Nine Months Ended
(in millions)	(in millions)	September 30,					(in millions)	Three Months Ended
								March 31,
		2004		2003
								2005			2004

Cash Flows From Operating Activities	Cash Flows From Operating Activities						Cash Flows From Operating Activities
Net income	Net income	$	3,735	$		861	Net income	$	218		$	3,033
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income to							Adjustments to reconcile net income to
net cash provided by operating activities:							net cash provided by operating activities:
Depreciation, amortization and decommissioning	Depreciation, amortization and decommissioning	1,054		916			Depreciation, amortization and decommissioning	385			312
Recognition of regulatory assets	Recognition of regulatory assets	(4,900)		-			Recognition of regulatory assets	-			(4,900)
Deferred income taxes and tax credits, net	Deferred income taxes and tax credits, net	2,395		122			Deferred income taxes and tax credits, net	(63)			1,926
Other deferred charges and noncurrent liabilities	Other deferred charges and noncurrent liabilities	(121)		395			Other deferred charges and noncurrent liabilities	(45)			237
Tax benefit on employee stock options exercises							Tax benefit on employee stock options exercises	25			-
Gain on sale of assets	Gain on sale of assets	(18)		(10)			Gain on sale of assets	-			(16)
Cumulative effect of a change in accounting principle		-		2
Net effect of changes in operating assets and liabilities:	Net effect of changes in operating assets and liabilities:						Net effect of changes in operating assets and liabilities:
Restricted cash	Restricted cash	150		(44)			Restricted cash	96			(128)
Accounts receivable	Accounts receivable	42		(8)			Accounts receivable	169			352
Inventories	Inventories	(61)		(96)			Inventories	90			82
Accounts payable	Accounts payable	77		350			Accounts payable	(115)			(257)
Accrued taxes	Accrued taxes	87		437			Accrued taxes	202			65
Regulatory balancing accounts, net	Regulatory balancing accounts, net	(323)		(397)			Regulatory balancing accounts, net	254			(53)
Other working capital	Other working capital	285		77			Other working capital	(182)			287
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(1,022)		(83)			Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	-			(20)
Other, net	Other, net	28		17			Other, net	14			(33)

Net cash provided by operating activities	Net cash provided by operating activities	1,408		2,539			Net cash provided by operating activities	1,048			887


Cash Flows From Investing Activities	Cash Flows From Investing Activities						Cash Flows From Investing Activities
Capital expenditures	Capital expenditures	(1,110)		(1,182)			Capital expenditures	(349)			(342)
Proceeds from sale of assets		28		14
Increase in restricted cash		(1,751)		-
Net proceeds from sale of assets							Net proceeds from sale of assets	11			18
Decrease (increase) in restricted cash							Decrease (increase) in restricted cash	26			(6,917)
Other, net	Other, net	(50)		(25)			Other, net	26			(65)

Net cash used in investing activities	Net cash used in investing activities	(2,883)		(1,193)			Net cash used in investing activities	(286)			(7,306)

Cash Flows From Financing Activities	Cash Flows From Financing Activities						Cash Flows From Financing Activities
Proceeds from issuance of long-term debt, net of issuance costs of $74 million		7,346		-
Net repayments under credit facilities and short-term borrowings							Net repayments under credit facilities and short-term borrowings	(300)			-
Proceeds from issuance of long-term debt, net of issuance costs of $153 million in 2004							Proceeds from issuance of long-term debt, net of issuance costs of $153 million in 2004	-			6,547
Proceeds from issuance of energy recovery bonds, net of issuance costs of $14 million in 2005							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	Long-term debt matured, redeemed or repurchased	(7,552)		(280)			Long-term debt matured, redeemed or repurchased	(902)			(310)
Rate reduction bonds matured	Rate reduction bonds matured	(213)		(213)			Rate reduction bonds matured	(74)			(74)
Preferred stock with mandatory redemption provisions redeemed							Preferred stock with mandatory redemption provisions redeemed	(2)			-
Common stock issued							Common stock issued	120			58
Common stock repurchased							Common stock repurchased	(1,065)			-
Preferred dividends paid	Preferred dividends paid	(88)		-			Preferred dividends paid	(4)			-
Preferred stock with mandatory redemption provisions redeemed		(15)		-
Other, net		(2)		(1)

Net cash used in financing activities		(524)		(494)

Net cash (used in) provided by financing activities							Net cash (used in) provided by financing activities	(353)			6,221

Net change in cash and cash equivalents	Net change in cash and cash equivalents	(1,999)		852			Net change in cash and cash equivalents	409			(198)
Cash and cash equivalents at January 1	Cash and cash equivalents at January 1	2,979		3,343			Cash and cash equivalents at January 1	972			3,658

Cash and cash equivalents at September 30		$	980	$		4,195

Cash and cash equivalents at March 31							Cash and cash equivalents at March 31	$	1,381	$	3,460

Supplemental disclosures of cash flow information	Supplemental disclosures of cash flow information						Supplemental disclosures of cash flow information
Cash received for:	Cash received for:						Cash received for:
Reorganization interest income	Reorganization interest income	$	13	$		30	Reorganization interest income	$	6	$	8
Cash paid for:	Cash paid for:						Cash paid for:
Interest (net of amounts capitalized)	Interest (net of amounts capitalized)	466		475			Interest (net of amounts capitalized)	267			197
Income taxes paid (refunded), net		94			(32)
Income taxes refunded, net							Income taxes refunded, net	(14)			-
Reorganization professional fees and expenses	Reorganization professional fees and expenses	21		84			Reorganization professional fees and expenses	-			5
Supplemental disclosures of noncash investing and financing activities	Supplemental disclosures of noncash investing and financing activities						Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise (to) from operating assets and liabilities, net		(2,877)		193
Common stock dividends declared but not yet paid							Common stock dividends declared but not yet paid	111			-
Transfer of liabilities and other payables subject to compromise to operating assets and liabilities							Transfer of liabilities and other payables subject to compromise to operating assets and liabilities	$	-	$	(257)

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 INCOME
			(Unaudited)

			Three Months Ended
(in millions)			March 31,

				2005		2004

Operating Revenues
	Electric			$	1,660	$	1,791
	Natural gas			1,009		931

		Total operating revenues		2,669		2,722

Operating Expenses
	Cost of electricity			396		561
	Cost of natural gas			620		578
	Operating and maintenance			773		808
	Recognition of regulatory assets			-		(4,900)
	Depreciation, amortization and decommissioning			385		311
	Reorganization professional fees and expenses			-		2

		Total operating (gain) expenses		2,174		(2,640)

Operating Income				495		5,362
	Reorganization interest income			-		8
	Interest income			20		3
	Interest expense			(154)		(213)
	Other income, net			4		13

Income Before Income Taxes				365		5,173
	Income tax provision			142		2,099

Net Income					223	3,074
	Preferred dividend requirement			4		8

Income Available for Common Stock				$	219	$	3,066




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
					Balance At

(in millions)					March 31,		December 31,
					2005		2004
					(Unaudited)

ASSETS
Current Assets
	Cash and cash equivalents				$	1,056	$	783
	Restricted cash				1,857		1,980
	Accounts receivable:
			Customers (net of allowance for doubtful accounts of
				$88 million in 2005 and $93 million in 2004)	1,916		2,085
			Related parties		2		2
			Regulatory balancing accounts		968		1,021
	Inventories:
			Gas stored underground and fuel oil		83		175
			Materials and supplies		131		129
	Prepaid expenses and other				54		43

		Total current assets			6,067		6,218

Property, Plant and Equipment
	Electric				21,689		21,519
	Gas				8,574		8,526
	Construction work in progress				518		449

		Total property, plant and equipment			30,781		30,494
	Accumulated depreciation				(11,715)		(11,507)

		Net property, plant and equipment			19,066		18,987

Other Noncurrent Assets
	Regulatory assets				6,412		6,526
	Nuclear decommissioning funds				1,627		1,629
	Other				892		942

		Total other noncurrent assets			8,931		9,097

TOTAL ASSETS					$	34,064	$	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)			March 31,			December 31,
			2005			2004
			(Unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Short term borrowings		$		-	$	300
	Long-term debt, classified as current				457		757
	Rate reduction bonds, classified as current		290			290
	Energy recovery bonds, classified as current		197			-
	Accounts payable:
		Trade creditors	500			762
		Disputed claims and customer refunds	2,142			2,142
		Related parties	20			20
		Regulatory balancing accounts	574			369
		Other	484			337
	Interest payable		426			461
	Income taxes payable		322			102
	Deferred income taxes		351			377
	Other		741			869

		Total current liabilities	6,504			6,786

Noncurrent Liabilities
	Long-term debt		6,442			7,043
	Rate reduction bonds		506			580
	Energy recovery bonds		1,691			-
	Regulatory liabilities		3,869			4,035
	Asset retirement obligations		1,325			1,301
	Deferred income taxes		3,587			3,629
	Deferred tax credits		119			121
	Preferred stock with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,800,000 shares, due 2005-2009)		120			122
	Other		1,625			1,555

		Total noncurrent liabilities	19,284			18,386

Commitments and Contingencies (Notes 1, 2 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		1,900			2,041
	Reinvested earnings		5,066			5,667
	Accumulated other comprehensive loss		(5)			(3)

		Total shareholders' equity	8,276			9,130

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	34,064		$	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)	Three Months Ended
	March 31,

	2005			2004

Cash Flows From Operating Activities
Net income	$		223	$	3,074
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization and decommissioning	385			311
Recognition of regulatory assets	-			(4,900)
Deferred income taxes and tax credits, net	(70)			2,014
Other deferred charges and noncurrent liabilities	(49)			279
Gain on sale of assets	-			(16)
Net effect of changes in operating assets and liabilities:
Decrease (increase) in restricted cash	97			(126)
Accounts receivable	169			353
Inventories	90			82
Accounts payable	(115)			(256)
Accrued taxes	220			98
Regulatory balancing accounts, net	254			(53)
Other working capital	(179)			253
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	-			(20)
Other, net	10			(84)

Net cash provided by operating activities	1,035			1,009

Cash Flows From Investing Activities
Capital expenditures	(349)			(342)
Net proceeds from sale of assets	11			18
Decrease (increase) in restricted cash	26			(6,917)
Other, net	26			(65)

Net cash used in investing activities	(286)			(7,306)

Cash Flows From Financing Activities
Net repayments under credit facilities and short-term borrowings	(300)			-
Proceeds from issuance of long-term debt, net of issuance costs of $153 million in 2004	-			6,547
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	(900)			(310)
Rate reduction bonds matured	(74)			(74)
Common stock dividends paid	(110)			-
Preferred dividends paid	(4)			-
Preferred stock with mandatory redemption provisions redeemed	(2)			-
Common stock repurchased	(960)			-

Net cash (used in) provided by financing activities	(476)			6,163

Net change in cash and cash equivalents	273			(134)
Cash and cash equivalents at January 1	783			2,979


Cash and cash equivalents at March 31	$		1,056	$	2,845



Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	6		$	8
Cash paid for:
Interest (net of amounts capitalized)	169			175
Income taxes paid, net	-			-
Reorganization professional fees and expenses	-			5
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	$	-		$	(257)

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 holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility 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. ~~Both PG&E Corporation and the Utility are headquartered in San Francisco, California.~~

As discussed further in Note 2, on April 12, 2004, the Utility's plan of reorganization, or Plan of Reorganization, under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, became effective, at which time the Utility emerged from Chapter 11.

PG&E Corporation's other significant subsidiary, National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., headquartered in Bethesda, Maryland, was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. For the reasons described below in Note 4, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial Statements. In addition, as discussed in Note 4, effective July 8, 2003, PG&E Corporation no longer consolidates the earnings and losses of NEGT or its subsidiaries and began accounting for its ownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled.

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

The accompanying interim unaudited Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles ~~generally accepted~~ 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 not contain all of the information and footnotes required by GAAP for complete financial statements. Both PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets at December 31, ~~2003,~~2004, were derived from the audited Consolidated Balance Sheets included in ~~the Current~~their combined 2004 Annual Report on Form ~~8-K dated June 18, 2004 (which supercedes~~10-K, or Annual Report, filed with the ~~information included in the combined 2003 Annual Report). Certain reclassifications of the 2003 amounts have been made to conform to the 2004 presentation.~~Securities and Exchange Commission, or SEC.

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, provisions for losses that are deemed probable from 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 ~~taxes,~~tax related liabilities, litigation, and in the Utility's review for 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 on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict, actual results could differ from these estimates. 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 ~~the~~their financial position and results of operations for the ~~interim~~ periods presented. ~~These adjustments are of a normal recurring nature.~~

During the ~~period that~~Utility's proceeding under Chapter 11 of the ~~Utility was in~~U.S. Bankruptcy Code, or Chapter 11, PG&E Corporation's and the Utility's Consolidated Financial Statements were ~~prepared~~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, certain claims against the Utility existing before the Utility's Chapter 11 filing were classified as liabilities subject to compromise on PG&E Corporation's and the Utility's Consolidated Balance Sheets. Additionally, 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. The Consolidated Financial Statements as~~2004 when the Utility's plan of ~~and~~reorganization under Chapter 11 became effective, or the Effective Date. As discussed below, in Note 2, the U.S. Bankruptcy Court for the ~~periods ending September 30, 2003 and December 31, 2003, have been presented in accordance with SOP 90-7. Although~~Northern District of California, which oversaw the ~~Utility emerged from~~Utility's Chapter 11 ~~on April 12, 2004, the bankruptcy court retained~~proceeding, retains jurisdiction, among other things, to resolve the remaining disputed claims made in the Utility's Chapter 11 ~~case. Upon the effective date of the Utility's Plan of Reorganization, $1.8 billion was deposited into escrow, pending the resolution of disputed claims, and has been classified as restricted cash~~proceeding.

This quarterly report should be read in ~~current assets on~~conjunction with PG&E Corporation's and the Utility's ~~September 30, 2004~~ Consolidated ~~Balance Sheets. The related remaining pre-petition claims are subject~~Financial Statements and Notes to ~~resolution by the bankruptcy court.~~

~~Adoption of New Accounting Policies and Summary of Significant Accounting Policies~~

The accounting policies used by the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC. Except as disclosed below, PG&E Corporation and the Utility are following the same accounting policies discussed in their Current Report on Form 8-K dated June 18, 2004 (which supercedes the information included in the combined 2003 Annual Report).

~~Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003~~

In May 2004, the Financial Accounting Standards Board, or the 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 supersedes FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," and provides guidance on the accounting, disclosure, effective date, and transition requirements related to the Medicare Prescription Drug Act. FSP 106-2 is effective for the third quarter of 2004. The companies have determined that the Utility's postretirement medical plan, or the Plan, the only benefit plan potentially affected by the Medicare Prescription Drug Act (and FSP 106-2), does not qualify for the federal subsidy under the terms of the Medicare Prescription Drug Act. The adoption of FSP 106-2 did not hav e any impact on the Consolidated Financial Statements included in their combined 2004 Annual 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 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 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.

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

	March 31,

(in millions, except share amounts)	2005			2004


Net income	$	218		$	3,033
Less: distributed earnings to common shareholders		111			-

Undistributed earnings			107		3,033


Common shareholders earnings
Basic
Distributed earnings to common shareholders		111			-
Undistributed earnings allocated to common shareholders			102		2,893

Total common shareholders earnings, basic	213			2,893

Diluted
Distributed earnings to common shareholders	111			-
Undistributed earnings allocated to common shareholders			102		2,897

Total common shareholders earnings, diluted	$	213		$	2,897


Weighted average common shares outstanding, basic	388			393
9.50% Convertible Subordinated Notes	19			19

Weighted average common shares outstanding and participating securities, basic	407			412


Weighted average common shares outstanding, basic	388			393
Employee stock options, restricted stock and PG&E Corporation shares held by grantor trusts	4			7
PG&E Corporation warrants	-			4
Rounding	-			1

Weighted average common shares outstanding, diluted	392			405
9.50% Convertible Subordinated Notes	19			19

Weighted average common shares outstanding and participating securities, diluted	411			424


Net earnings per common share, basic
Distributed earnings, basic	$	0.29		$	-
Undistributed earnings, basic		0.26			7.36

Total	$	0.55		$	7.36




Net earnings per common share, diluted
Distributed earnings, diluted	$	0.28		$	-
Undistributed earnings, diluted		0.26			7.15

Total	$	0.54		$	7.15

Options to purchase 6,500 and 8,542,006 PG&E Corporation orcommon shares were outstanding during the ~~Utility. The Medicare Prescription Drug Act could subsequently affect~~three months ended March 31, 2005 and 2004, respectively, but not included in the ~~Plan in terms~~computation of ~~lower participation rates, which would lower~~diluted earnings per common share because the ~~Plan's benefit obligation~~option exercise prices were greater than the average market price.

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

Consolidation of Variable Interest Entities

~~In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities," or FIN 46R. FIN 46R provides that an~~

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, or FASB, 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 ~~any~~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 determined that it was the primary beneficiary of one LIHP, resulting in its ~~consolidation. Accordingly,~~consolidation, and an increase in total assets and total liabilities of ~~$14~~$10 million ~~for the LIHP have been included~~ in PG&E Corporation's and the Utility's Consolidated Balance Sheets. The consolidated LIHP has issued debt in the amount of $6$4 million, which is secured by assets of the partnership, totaling ~~$27~~$24 million, and the Utility's commitment to make capital infusions of approximately ~~$13~~$10 million over the next five 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 ~~$6 million.~~$5 million at March 31, 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. ~~Previously, the Utility was not able to determine whether certain power purchase contracts represented variable interests in VIEs. During the third quarter, the~~The Utility determined that none of its current power purchase agreements represent significant variable interests. The ~~Emerging Issues Taskforce, or the EITF, continues~~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.

~~Changes in~~Adoption of New Accounting ~~for Certain Derivative Contracts~~Policies and Summary of Significant Accounting Policies

~~In November 2003, the FASB approved an amendment to an interpretation issued~~The accounting policies used by the Derivatives Implementation Group C15, or DIG C15, as previously amended in October 2001 and December 2001, that changed the definition of normal purchases and sales for certain power contracts that contain option-like features.

PG&E Corporation and the Utility ~~had previously adopted~~include those necessary for rate-regulated enterprises, which reflect the ~~new DIG C15 guidelines prospectively for new derivative instruments entered into after June 30, 2003. On January 1, 2004, PG&E Corporation~~ratemaking policies of the California Public Utilities Commission, or CPUC, and the ~~Utility adopted~~Federal Energy Regulatory Commission, or FERC.

Accounting and Disclosure Requirements Related to the ~~new DIG C15 guidelines~~Medicare Prescription Drug, Improvement and Modernization Act of 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 supersedes FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," and provides guidance on the accounting, disclosure, effective date, and transition requirements related to the Medicare Prescription Drug Act. FSP 106-2 was effective for ~~certain power contracts that contain option-like features that existed prior to July 1, 2003.~~the third quarter of 2004. The adoption of ~~DIG C15~~FSP 106-2 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

~~Regulation~~ The U.S. Department of Health and ~~Statement of Financial Accounting Standards No. 71~~

Human Services issued the final regulations on prescription drug benefits on January 21, 2005. Despite the initial preliminary conclusion that theUtility's postretirement medical plan, or the Plan, did not qualify for the federal subsidy, the final regulations may allow the Plan to qualify for the federal subsidy. PG&E Corporation and the Utility ~~account for~~are continuing to evaluate the ~~financial~~ effects, if any, of ~~regulation in accordance with "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~~final regulations on the ~~costs of providing service. The Utility is regulated by the CPUC, the FERC~~Plan, and the ~~Nuclear Regulatory Commission, or~~impact on the NRC, among others. As discussed further in Note 2, during the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations. As a result, as of March 31, 2004, the Utility recorded a generation regulatory asset of approximately $1.2 billion. SFAS No. 71 now 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 would be included for ratemaking purposes in the future. 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 the following:~~

(in millions)
September 30,
2004

December 31,
2003
Settlement Regulatory Asset
$
3,256
$
-
Utility retained generation regulatory assets
1,200
-
Rate reduction bond assets
815
1,054
Regulatory assets for deferred income tax
470
324
Unamortized loss, net of gain, on reacquired debt
351
277
Qualifying facilities restructuring costs
144
151
Environmental compliance costs
177
139
Regulatory assets associated with Plan of Reorganization
174
-
Other, net
48
56
Total regulatory assets
$
6,635
$
2,001

~~Amortization of regulatory assets is charged to expense during the period that the costs are reflected in regulated revenues.~~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 (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 further discussion in Note 2, The Utility's Chapter 11 filing). As of September 30, 2004, the Utility has recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $300 million ($180 million after-tax) for supplier settlements and approximately $110 million ($65 million after-tax) for amortization of the Settlement Regulatory Asset.Consolidated Financial Statements.

~~Regulatory Liabilities~~

~~Regulatory liabilities comprise the following:~~

(in millions)
September 30,
2004

December 31,
2003
Cost of removal obligations
$
1,942
$
1,810
Employee benefit plans
726
925
Asset retirement costs
626
584
Public purpose programs
203
185
Rate reduction bonds
177
175
Surcharge liability
128
125
Other
178
175
Total regulatory liabilities
$
3,980
$
3,979

~~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 authorized revenue requirements. 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.

~~Earnings (Loss) Per Share~~

Earnings (loss) per share is calculated utilizing the "two-class" method by dividing earnings (loss) allocated to common shareholders by the weighted average number of common shares outstanding during the period.

Three Months Ended
Nine Months Ended
September 30,
September 30,
(in millions, except per share amounts)
2004
2003
2004
2003
Income from continuing operations
$
228
$
508
$
3,633
$
754
Discontinued operations
-
2
-
(365)
Net income before cumulative effect of changes in
  accounting principles
228
510
3,633
389
Cumulative effect of changes in accounting principles
-
-
-
(6)
Net Income for basic and diluted calculations
$
228
$
510
$
3,633
$
383
Weighted average common shares outstanding, basic
399
387
397
384
9.50% Convertible Subordinated Notes
19
19
19
19
Weighted average common shares outstanding and
  participating securities, basic
418
406
416
403
Weighted average common shares outstanding, basic
399
387
397
384
Employee stock options and PG&E Corporation shares held by
  grantor trusts
7
5
6
2
PG&E Corporation warrants
2
5
3
5
Weighted average common shares outstanding, diluted
408
397
406
391
9.50% Convertible Subordinated Notes
19
19
19
19
Weighted average common shares outstanding and
  participating securities, diluted
427
416
425
410
Earnings (Loss) Per Common Share, Basic
Income from continuing operations
$
0.55
$
1.25
$
8.73
$
1.87
Discontinued operations
-
-
-
(0.91)
Cumulative effect of changes in accounting principles
-
-
-
(0.01)
Rounding
-
0.01
-
-
Net earnings
$
0.55
$
1.26
$
8.73
$
0.95
Earnings (Loss) Per Common Share, Diluted
Income from continuing operations
$
0.53
$
1.22
$
8.55
$
1.84
Discontinued operations
-
-
-
(0.89)
Cumulative effect of changes in accounting principles
-
-
-
(0.01)
Rounding
-
0.01
-
(0.01)
Net earnings
$
0.53
$
1.23
$
8.55
$
0.93

On March 31, 2004, the FASB ratified the consensus reached by the EITF, on EITF Issue 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06. EITF 03-06 provides additional guidance related to the calculation of earnings per share under SFAS No. 128, "Earnings per Share," or SFAS No. 128, which includes application of the "two-class" method in computing earnings per share, identification of participating securities, and requirements for the allocation of undistributed earnings (and losses) to participating securities.

PG&E Corporation currently has outstanding $280 million in convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes meet the criteria of a participating security in the calculation of basic earnings per share using the "two-class" method of SFAS No. 128. Therefore, EITF 03-06 requires that earnings be allocated between common stock and the participating security. PG&E Corporation adopted EITF 03-06 in the first quarter of 2004 and for all subsequent and all prior periods presented.

In applying the "two-class" method, the following reflects the earnings (loss) allocated to common shareholders after the inclusion of participation rights related to PG&E Corporation's 9.50% Convertible Notes in the allocation of earnings. The 9.50% Convertible 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.

Three Months Ended
Nine Months Ended
September 30,
September 30,
Earnings (loss) allocated to common shareholders, basic
2004
2003
2004
2003
Income from continuing operations
$
218
$
484
$
3,467
$
718
Discontinued operations
-
2
-
(348)
Cumulative effect of changes in accounting principles
-
-
-
(6)
$
218
$
486
$
3,467
$
364
Earnings (loss) allocated to common shareholders, diluted
Income from continuing operations
$
218
$
485
$
3,471
$
719
Discontinued operations
-
2
-
(348)
Cumulative effect of changes in accounting principles
-
-
-
(6)
$
218
$
487
$
3,471
$
365

The following options to purchase PG&E Corporation common shares were outstanding, but not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price: nine months ended September 30, 2004 - 8,045,805, nine months ended September 30, 2003 - 17,687,167, three months ended September 30, 2004 - 7,705,881, and three months ended September 30, 2003 - 11,130,315.

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

~~Stock-Based Compensation~~

PG&E Corporation and the Utility apply the intrinsic-value method prescribed in Accounting Principles Board 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 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 nine months ended September 30, 2004 and 2003:

Three Months Ended
Nine Months Ended
September 30,
September 30,
(in millions, except per share amounts)
2004
2003
2004
2003
Net Earnings:
As reported
$
228
$
510
$
3,633
$
383
Deduct: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of related tax effects
3
4
10
11
Pro forma
$
225
$
506
$
3,623
$
372
Basic earnings per share:
As reported
0.55
1.26
8.73
0.95
Pro forma
0.54
1.25
8.71
0.92
Diluted earnings per share:
As reported
0.53
1.23
8.55
0.93
Pro forma
0.53
1.23
8.57
0.92

~~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:~~

Three Months Ended
Nine Months Ended
September 30,
September 30,
(in millions)
2004
2003
2004
2003
Net Earnings:
As reported
$
244
$
583
$
3,718
$
843
Deduct: Total stock-based employee compensation expense
determined under the fair value based method for all awards,
net of related tax effects
2
2
6
6
Pro forma
$
242
$
581
$
3,712
$
837

At September 30, 2004, a total of 2,088,920 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,280,000 shares were granted to Utility employees. At September 30, 2004, approximately 1,613,427 shares of restricted stock awarded to eligible employees of PG&E Corporation and its subsidiaries were outstanding, of which 1,062,697 shares were granted to Utility employees. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. In general, for shares 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 share price. For shares granted in 2004, the restrictions lapse automatically over a period of four years at the rate of 25% per year, and the compensation expense remains fixed at the value of the stock at grant date. Compensation expense associated with all restricted stock is recognized on a quarterly basis by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuances reflected in PG&E Corporation's Consolidated Statements of Income was approximately $3.1 million for the three-month period ended September 30, 2004 and $6.2 million for the nine-month period ended September 30, 2004, of which approximately $1.8 million for the three-month period ended September 30, 2004 and $3.8 million for the nine-month period ended September 30, 2004 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the restricted stock issuances reflected in PG&E Corporation's Consolidated Balance Sheet at September 30, 2004 was approximately $25 million.

~~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 defined benefit pension plan.

PG&E Corporation

Utility
(in millions)
2004

2003

2004

2003
Three months ended September 30

Net income available for common stock
$
228

$
510

$
244

$
583
Net reclassification from OCI to earnings (net of income tax
  expense of $1 million in 2003)
-
2
-
-
Other

-

1

-

-
Comprehensive income
$
228

$
513

$
244

$
583
Nine months ended September 30

Net income available for common stock
$
3,633

$
383

$
3,718

$
843
Net gain (loss) in OCI from current period hedging
  transactions and price changes in accordance with
  SFAS No. 133 (net of income tax expense of $2 million in 2004
  and benefit of $4 million in 2003)
3

(5)

3

-
Net reclassification from OCI to earnings (net of income tax
  benefit of $3 million in 2003)
-

17

-

-
Foreign currency translation adjustment (net of income tax
  expense of $2 million in 2003)
-

3

-

-
Retirement plan remeasurement (net of income tax benefit of $41
  million in 2003)

-

(60)

-

(60)
Other

1

1

-

-
Comprehensive income
$
3,637

$
339

$
3,721

$
783

The above changes to other comprehensive income, or OCI, are stated net of income tax expense (benefit) of $2 million for the nine-month period ended September 30, 2004, and $1 million for the three-month and ($46) million for the nine-month periods ended September 30, 2003.

~~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):

Hedging
Transactions in
Accordance with
SFAS No. 133
Foreign
Currency
Translation
Adjustment
Retirement
Plan
Remeasurement

Other
Accumulated
Other
Comprehensive
Income (Loss)
Balance at December 31, 2002
$
(90)
$
(3)
$
-
$
-
$
(93)
Period change in:
   Mark-to-market adjustments for hedging
     transactions in accordance with SFAS
     No. 133
(5)
-
-
-
(5)
   Net reclassification to earnings
17
-
-
-
17
   Other
-
3
(60)
1
(56)
Balance at September 30, 2003
$
(78)
$
-
$
(60)
$
1
$
(137)
Balance at December 31, 2003
$
(81)
$
-
$
(4)
$
-
$
(85)
Period change in:
   Mark-to-market adjustments for hedging
     transactions in accordance with SFAS
     No. 133
3
-
-
-
3
   Other
-
-
-
1
1
Balance at September 30, 2004
$
(78)
$
-
$
(4)
$
1
$
(81)

Hedging
Transactions in
Accordance with
SFAS No. 133
Foreign
Currency
Translation
Adjustment
Retirement
Plan
Remeasurement

Other
Accumulated
Other
Comprehensive
Income (Loss)
Balance at June 30, 2003
$
(80)
$
-
$
(60)
$
-
$
(140)
Net reclassification to earnings
2
-
-
-
2
Other
-
-
-
1
1
Balance at September 30, 2003
$
(78)
$
-
$
(60)
$
1
$
(137)
Balance at June 30 and September 30, 2004
$
(78)
$
-
$
(4)
$
1
$
(81)

There was no movement in the component balances of accumulated other comprehensive income (loss) during the third quarter of 2004. An amount of $77 million is included in accumulated other comprehensive income (loss) related to discontinued operations at September 30, 2004, and at September 30, 2003. This amount will be recognized in connection with PG&E Corporation's elimination of its equity interest in NEGT in the fourth quarter of 2004 (see further discussion in Note 4, Discontinued Operations).

Related Party Agreements and Transactions

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 ~~support~~ services in support of operations. These services are priced either at the fully loaded cost (~~i.e~~i.e.., direct costs and ~~allocation~~allocations of overhead costs) or at the higher 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 to the Utility and other subsidiaries using ~~a variety of~~agreed allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other ~~cost-causal methods.~~cost allocation methodologies. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or GTNW, ~~formerly~~f ormerly known as PG&E Gas Transmission, Northwest Corporation. ~~Effective April 1, 2003, the Utility~~GTNW is no longer ~~purchases natural gas from NEGT~~a related party after the cancellation of PG&E Corporation's equity interest in National Energy ~~Trading Holdings Corporation,~~& Gas Transmission, Inc., or NEGT, ET, formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are subsidiaries of NEGT. The Utility sold natural gas transportation capacity and other ancillary services to NEGT ET until NEGT's Chapter 11 proceeding was imminent. These services were priced at either tariff rates or fair market value, depending on the ~~nature~~effective date of ~~the services provided.~~its plan of reorganization, October 29, 2004. Through July 7, 2003, all significant intercompany transactions ~~are~~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 September 30,

Nine Months
Ended September 30,
Receivable (Payable)
Balance Outstanding at
September 30,
December 31,
(in millions)
2004
2003
2004
2003
2004
2003
Utility revenues from:
Administrative services provided to
  PG&E Corporation
$
2
$
2
$
6
$
6
$
2
$
-
Natural gas transportation capacity services   provided to NEGT ET
-
2
-
6
-
-
Trade deposit due from GTNW
-
-
-
-
-
15
Utility expenses from:
Administrative services received from
  PG&E Corporation
$
23
$
40
$
65
$
137
$
(27)
$
(396)
Interest accrued on pre-petition liability due   to PG&E Corporation
-
2
2
5
-
(2)
Administrative services received
  from NEGT
-
-
-
2
-
(1)
Software purchases from NEGT
-
-
-
1
-
-
Gas commodity services
  received from NEGT ET
-
-
-
10
-
-
Gas transportation services received
  from GTNW
14
14
43
43
(5)
(8)

	Three Months Ended					Receivable (Payable) Balance Outstanding at
(in millions)

		March 31,				March 31,		December 31,

		2005		2004		2005		2004

Utility revenues from:
Administrative services provided to PG&E Corporation		$	1	$	2	$	1	$	1
Utility expenses from:
Administrative services received from PG&E Corporation		$	25	$	22	$	(20)	$	(20)
Interest accrued on pre-petition liabilities due to PG&E Corporation		-		2		-		-
Natural gas transportation services received from GTNW		-		15		-		-

As discussed ~~further in Note 2,~~below, as of March 31, 2004, PG&E Corporation recorded the impact of the ~~Settlement Agreement~~settlement agreement, entered into on December 19, 2003, among PG&E Corporation, the Utility and the CPUC to resolve the Utility's Chapter 11 ~~case.~~case, or the Settlement Agreement. The Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the Utility reduced its payable to PG&E Corporation by $128 million. The transactions were recorded as a contribution of equity to the Utility by PG&E Corporation, net of taxes of $52 million, and an increase to ~~additional paid-in capital~~additional-paid-in-capital by the Utility in the first quarter of 2004.

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.

Regulatory Assets

Regulatory assets comprise the following:

	Balance At

(in millions)	March 31,		December 31,
	2005		2004


Settlement Regulatory Asset	$	1,282	$	3,188
Energy recovery bond regulatory asset		1,868		-
Utility retained generation regulatory assets		1,161		1,181
Rate reduction bond assets		676		741
Regulatory assets for deferred income tax	500		490
Unamortized loss, net of gain, on reacquired debt	340		345
Environmental compliance costs	227		192
Post-transition period contract termination costs	139		142
Regulatory assets associated with plan of reorganization	170		182
Other, net	49		65

Total regulatory assets	$	6,412	$	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 three months ended March 31, 2005, the Utility recorded amortization of the Settlement Regulatory Asset of approximately $33 million ($20 million, after-tax) and did not record any offsets for supplier settlements.

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 has been 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.

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. 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. The post-transition period contract termination costs represent amounts the Utility incurred in terminating a 30-year power purchase agreement. Regulatory assets associated with the plan of reorganization include costs incurred in financing the Utility's exit from Chapter 11 and costs to ov ersee the environmental enhancement of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the Utility's plan of reorganization. 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. Now that the remaining unamortized after-tax balance of the Settlement Regulatory Asset has been refinanced 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 the following:

(in millions)	Balance At

	March 31,		December 31,
	2005		2004


Cost of removal obligation	$	2,000	$	1,990
Asset retirement costs	678		700
Employee benefit plans	640		687
Public purpose programs	198		191
Rate reduction bonds	178		182
Other	175		285

Total regulatory liabilities	$	3,869	$	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.

Stock-Based Compensation

PG&E Corporation and the Utility apply the intrinsic-value method prescribed in Accounting Principles Board 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 months ended March 31, 2005 and 2004:

(in millions, except per share amounts)				Three Months Ended
				March 31,

			2005			2004

Net earnings:
As reported			$		218	$	3,033
	Deduct: Total stock-based employee compensation
		expense determined under the fair value based method
		for all awards, net of related tax effects			(3)		(4)

Pro forma			$		215	$	3,029




Basic earnings per common share:
As reported			$		0.55	$	7.36
Pro forma					0.55		7.35

Diluted earnings per common share:
As reported					0.54		7.15
Pro forma					0.53		7.14

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
			March 31,

		2005			2004

Net earnings:
As reported		$		219	$	3,066
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards, net of related tax effects	(2)			(2)

Pro forma		$		217	$	3,064

Restricted Stock

At March 31, 2005, a total of 2,418,760 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,598,140 shares were awarded to Utility employees. PG&E Corporation awarded 329,840 shares of restricted common stock during the three months ended March 31, 2005, of which 242,010 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 million for the three months ended March 31, 2005 and approximately $3 million for the three months ended March 31, 2004, of which approximately $2 million for the three months ended March 31, 2005 and approximately $2 million for the three months ended March 31, 2004 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the issuance of restricted shares, as reflected on PG&E Corporation's Condensed Consolidated Balance Sheets was approximately $31 million at March 31, 2005 and approximately $26 million at December 31, 2004.

Comprehensive Income (Loss)

	PG&E Corporation				Utility

(in millions)	2005		2004		2005		2004

Three months ended March 31
Net income available for common stock	$	218	$	3,033	$	219	$	3,066
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
Minimum pension liability adjustment (net of income tax benefit of $2 million in 2005)		(1)		-		(2)		-
Other		-		1		-		-

Comprehensive income	$	217	$	3,037	$	217	$	3,069

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)


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

Balance at March 31, 2004				(78)		-			(4)	1				(81)



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

Balance at March 31, 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).

Pension and Other Postretirement Benefits

PG&E Corporation and its subsidiaries provide non-contributory defined benefit pension plans 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 use a December 31 measurement date for all of its 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 ~~and the Utility's~~Condensed Consolidated Statements of Income for the ~~three~~three-month period ended March 31, 2005 and ~~nine-month periods ended September 30,~~March 31, 2004 ~~and September 30, 2003~~ are as follows:

PG&E Corporation

	Pension Benefits Three Months Ended September 30				Other Benefits Three Months Ended September 30					Pension Benefits Three Months Ended March 31,				Other Benefits Three Months Ended March 31,

(in millions)	2004		2003		2004			2003		2005		2004		2005			2004

Service cost for benefits earned	$	49	$	42	$	8	$		7	$	56	$	47	$	9	$		9
Interest cost	120		111		21		20			125		118		20		23
Expected return on plan assets	(140)		(126)		(19)		(15)			(151)		(141)		(21)		(19)
Amortization of transition obligation	1		3		6		7			-		1		6		6
Amortization of prior service cost	14		11		3		-			14		13		3		3
Amortization of recognized loss	2		11		-		-
Amortization of unrecognized loss										6		-		-		-

Net periodic benefit cost	$	46	$	52	$	19	$		19	$	50	$	38	$	17	$		22

Pension Benefits
Nine Months Ended
September 30

Other Benefits
Nine Months Ended
September 30
(in millions)
2004

2003

2004

2003
Service cost for benefits earned
$
146

$
127

$
24

$
22
Interest cost
361

335

63

59
Expected return on plan assets
(422)

(381)

(57)

(46)
Amortization of transition obligation
4

10

19

19
Amortization of prior service cost
41

32

9

1
Amortization of recognized loss
6

34

-

1
Settlement loss
1

2

-

-
Net periodic benefit cost
$
137

$
159

$
58

$
56

There was no material difference between the Utility

Pension Benefits
Three Months Ended
September 30

Other Benefits
Three Months Ended
September 30
(in millions)
2004

2003

2004

2003
Service cost for benefits earned
$
48

$
42

$
8

$
7
Interest cost
119

110

21

20
Expected return on plan assets
(140)

(126)

(19)

(15)
Amortization of transition obligation
1

3

6

7
Amortization of prior service cost
14

11

3

-
Amortization of recognized loss
2

11

-

-
Net periodic benefit cost
$
44

$
51

$
19

$
19

Pension Benefits
Nine Months Ended
September 30

Other Benefits
Nine Months Ended
September 30
(in millions)
2004

2003

2004

2003
Service cost for benefits earned
$
143

$
125

$
24

$
22
Interest cost
358

332

63

59
Expected return on plan assets
(420)

(379)

(57)

(46)
Amortization of transition obligation
4

10

19

19
Amortization of prior service cost
41

32

9

1
Amortization of recognized loss
6

34

-

1
Settlement loss
1

1

-

-
Net periodic benefit cost
$
133

$
155

$
58

$
56
and PG&E Corporation's 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.

~~In August 2004,~~PG&E Corporation and the Utility ~~contributed~~expect to contribute approximately $20 million for Pension Benefits to ~~its pension benefit plan. No further~~fund voluntary retirement program obligations and approximately $68 million for Other Benefits in 2005. These anticipated contributions are ~~expected during~~consistent with PG&E Corporation's and the ~~fiscal year 2004.~~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.

Inventory Costs

In December 2004, the FASB issued Statement No. 151, "Inventory Costs an amendment of ARB No. 43, Chapter 4", or SFAS No. 151. The guidance clarifies that the allocation of fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, handling costs and spoilage should be recognized as a current period charge. SFAS No. 151 will be effective January 1, 2006. The adoption of SFAS No. 151 is not expected to have a material effect on the financial position or results of operations of either PG&E Corporation or the Utility.

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.

NOTE 2: THE UTILITY'S EMERGENCE FROM CHAPTER 11 ~~FILING~~

~~Emergence From~~ 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 issued rate reduction bonds) and PG&E Holdings LLC (which holds stock of the Utility), were not included in the Utility's Chapter 11 proceeding.

On April 12, 2004, the ~~Utility's Plan of Reorganization under Chapter 11 of the U.S. Bankruptcy Code became effective, at which time the~~ Utility emerged from Chapter ~~11.~~11 when its plan of reorganization became effective, or the Effective Date. The ~~Plan~~plan of ~~Reorganization~~reorganization incorporated the terms of the ~~settlement agreement~~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, or Settlement Agreement.~~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~~plan of ~~Reorganization,~~reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the ~~Plan~~plan of ~~Reorganization.~~reorganization. In addition, the bankruptcy court retains jurisdiction to ~~re solve~~resolve remaining disputed claims.

In ~~anticipation~~light of ~~its emergence from Chapter 11,~~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 ~~consummated its public offering~~to recognize the regulatory assets provided under the Settlement Agreement was met as of ~~$6.7~~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 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 March 31, 2005, the Utility had accrued approximately $1.6 billion for remaining net disputed claims, consisting of approximately $2.1 billion of ~~first mortgage bonds,~~accounts payable-disputed claims primarily payable to the California Independent System Operator, or ~~First Mortgage Bonds, on March 23, 2004. Upon~~ISO, and the ~~effectiveness~~Power Exchange, or the PX, offset by an accounts receivable amount from the ISO and the PX of ~~the Plan of Reorganization, the~~approximately $0.5 billion. The Utility ~~paid all valid claims, deposited funds into~~held $1.6 billion in escrow ~~accounts~~ for the payment of the remaining disputed claims ~~upon their~~as of March 31, 2005. Upon resolution ~~reinstated certain obligations,~~of these claims and ~~paid~~under the terms of the Settlement Agreement, any refunds, claims offsets or other ~~obligations. The following table summarizes the sources and uses of funds on the effective date:~~

(in millions)
Sources
Uses
First Mortgage Bonds
$
6,700
Payments to Creditors
$
8,394
Term Loans
799
Disputed Claims Escrow
1,843
Accounts Receivable Financing Facility
350
Total Debt Financing
7,849
Cash Used to Pay Claims
2,388
Sources of Funds for Claims
10,237
Uses of Funds for Claims
10,237
Reinstated Pollution Control Bond-Related
Obligations
814
Reinstated Pollution Control Bond-Related
Obligations
814
Reinstated Preferred Stock
421
Reinstated Preferred Stock
421
Cash on Hand
225
Preferred Dividends
93
Environmental Measures
10
Transaction Costs
122
Total Sources of Funds
$
11,697
Total Uses of Funds
$
11,697

~~In connection with the Utility's emergence from Chapter 11,~~credits that the Utility ~~received investment-grade issuer credit ratings of Baa3~~receives from ~~Moody's Investors Service, or Moody's, and BBB- from Standard & Poor's, or S&P.~~

~~On July 15, 2004,~~energy suppliers will be returned to customers. With the ~~U.S. District Court for the Northern District of California, or the District Court, dismissed the appeals~~approval of the bankruptcy ~~court's~~court, the Utility has withdrawn certain amounts from the escrow in connection with settlements with certain ISO and PX sellers.

Petitions for review of the CPUC's order ~~confirming~~approving the ~~Plan~~Settlement Agreement and order denying rehearing of ~~Reorganization~~its approval order that had been filed by the two CPUC commissioners who did not vote to approve the Settlement Agreement. These two commissioners have filed a notice of appeal of the District Court's order with the U.S. Court of Appeals for the Ninth Circuit. An appeal of the confirmation order filed by the City of Palo Alto remains pending at the District Court. PG&E Corporation and the Utility believe the appeals of the confirmation order are without merit.

~~In addition, on April 15, 2004,~~ the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, ~~each filed a petition with~~are still pending at the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision.Appeal. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions.

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. After briefing is complete, the Ninth Circuit will consider arguments by the Utility and the CPUC to dismiss the appeal. 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 petitions for review of the CPUC orders and the appeal of the confirmation order are without merit and ~~should~~will be ~~denied.~~

~~Under applicable federal precedent, once the Plan of Reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed.~~rejected. If ~~notwithstanding this federal precedent,~~ the bankruptcy court's confirmation order or the Settlement Agreement is ~~subsequently~~ overturned or modified on appeal, PG&E ~~Corporation~~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.

~~Financial Summary of the Settlement Agreement~~

In light of the satisfaction of various conditions to the implementation of the Plan of Reorganization, including the consummation of the public offering of the First Mortgage Bonds, the receipt of investment grade credit ratings, and final CPUC approval of the Settlement Agreement, 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 below), 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, as summarized in the table below and discussed further in the paragraphs below:

(in millions)
Settlement
Regulatory
Asset
Utility Retained
Generation
Regulatory Assets

Total
Authorized, pre-tax, January 1, 2004
$
3,730

$
1,249

$
4,979
Amortization from January 1 to March 31, 2004
(58)

(21)

(79)
Recognition of regulatory assets, pre-tax, March 31, 2004
3,672

1,228

4,900
Deferred income taxes
(1,496)

(500)

(1,996)
Recognition of regulatory assets, after tax, March 31, 2004
2,176

728

2,904
Offsets of supplier settlements, after-tax
(8)

-

(8)
Net regulatory assets, after-tax, March 31, 2004
$
2,168

$
728

$
2,896

~~Settlement Regulatory Asset~~

The Settlement Agreement established a $2.2 billion, after-tax, regulatory asset (which is equivalent to an approximately $3.7 billion, pre-tax, regulatory asset) as a new, separate and additional part of the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004. Under this amortization methodology, annual after-tax collections of the Settlement Regulatory Asset are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012. This after-tax Settlement Regulatory Asset is subject to reduction for any refunds, claim offsets, or other credits that the Utility receives from energy suppliers relating to specified electricity procurement costs incurred during the California energy crisis, including those arising from the settlement of CPUC litigation against El Paso Natural Gas Company. The Utility recognized a one-time non-cash gain of $3.7 billion, pre-tax, for the Settlement Regulatory Asset in th e first quarter of 2004. As discussed in Note 1, as of September 30, 2004, the Utility has recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $300 million ($180 million after-tax) for supplier settlements and approximately $110 million ($65 million after-tax) for amortization of the Settlement Regulatory Asset.

The unamortized balance of the Settlement Regulatory Asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term and, after the equity component of the Utility's capital structure reaches 52%, the authorized equity component of the Settlement Regulatory Asset will be no less than 52% for the remaining term. If the Utility completes a refinancing of the Settlement Regulatory Asset supported by a dedicated rate component as discussed below, the equity and debt components of the Utility's rate of return will be replaced with the lower interest rate of the securitized debt.

~~Utility Retained Generation Regulatory Assets~~

In the Settlement Agreement, the CPUC deemed the Utility's adopted electricity generation rate base in a 2002 proceeding to be just and reasonable and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. Accordingly, the Utility recognized a one-time non-cash gain of $1.2 billion, pre-tax, for the retained generation regulatory assets in the first quarter of 2004. The individual components of the regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years. The Utility retained generation regulatory assets will earn an authorized rate of return on its equity component of 11.22% in 2004.

~~Ratemaking Matters~~

In the Settlement Agreement, the CPUC agreed to set the Utility's capital structure and authorized return on equity in its annual cost of capital proceedings in its usual manner. However, from January 1, 2004 until Moody's has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility's authorized return on equity will be no less than 11.22% per year and its authorized equity ratio for ratemaking purposes will be no less than 52%. However, for 2004 and 2005, the Utility's authorized equity ratio will be the greater of the proportion of equity approved in the Utility's 2004 and 2005 cost of capital proceedings, or 48.6%.

The CPUC also agreed to act promptly on certain of the Utility's pending ratemaking proceedings. The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility's Consolidated Balance Sheets.

~~Environmental Measures~~

·	~~In the Settlement Agreement, the Utility agreed to encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations.~~
·	The Utility has established PG&E Environmental Enhancement Corporation as a California non-profit corporation to oversee the environmental enhancements associated with these lands. The Utility has agreed to fund the corporation with $100 million in cash over 10 years. In October 2004, the Utility paid the first installment of $10 million to this corporation. As of September 30, 2004, the Utility has recorded an $84 million liability based on the discounted present value of future cash payments to this corporation. The Utility will be entitled to recover these payments in rates. Therefore, the Utility recognized an offsetting regulatory asset and the recognition of the obligation had no impact on the Utility's results of operations.
·	The Utility has also established a California non-profit corporation that is dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory. The Utility agreed to fund this corporation with $30 million payable over five years. In July 2004, the Utility made its first $2 million installment payment to this corporation. These contributions may not be recovered in rates. In the first quarter of 2004, the Utility recorded a $27 million pre-tax charge to earnings based on the discounted present value of future cash payments.

Of the approximately 140,000 acres referred to above, approximately 44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements. In the first quarter of 2004, the Utility recorded a $1 million pre-tax charge to earnings associated with the land donation obligation.

~~Fees and Expenses~~

The Settlement Agreement required the Utility to reimburse the CPUC for its professional fees and expenses incurred in connection with the Chapter 11 proceeding. These amounts will be recovered from customers over a reasonable time of up to four years. As of September 30, 2004, the Utility had a regulatory asset and associated liability of approximately $24 million relating to the CPUC reimbursable fees and expenses. Any changes to the final amount of the CPUC reimbursable fees and expenses will affect the regulatory asset and associated liability recorded by the Utility. In addition, one of the terms of the Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the Utility reduced its payable to PG&E Corporation, by $128 million. The transactions were recorded as a cont ribution of equity to the Utility by PG&E Corporation, net of taxes, and an increase to additional paid-in capital by the Utility in the first quarter 2004.

~~Refinancing Supported by a Dedicated Rate Component~~

Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the Settlement Regulatory Asset and related federal, state, and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided that certain conditions are met. In June 2004, the California Governor signed into law Senate Bill 772, which authorizes the issuance of Energy Recovery Bonds, or ERBs, to be secured by the establishment of a dedicated rate component to refinance the Settlement Regulatory Asset and related taxes. In addition to the authorizing legislation, the following other conditions must be met before a refinancing can occur:

·	~~The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the Settlement Regulatory Asset;~~
·	~~The refinancing will not adversely affect the Utility's issuer or debt credit ratings; and~~
·	The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or the IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

On June 8, 2004, the Utility filed a request for a private letter ruling with the IRS. It is expected that it will take up to six months for the IRS to conclude how it will respond to the request. Also, on July 22, 2004, the Utility filed an application with the CPUC requesting the authority to securitize the Settlement Regulatory Asset by issuing ERBs as discussed above, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart. On October 19, 2004, the CPUC issued a proposed decision authorizing the issuance of the ERBs, subject to the approval of transaction terms by a financing team comprised of CPUC staff and their outside advisors. The CPUC used a similar financing team approach to approve the terms of the Utility's bankruptcy exit financing. Comments on the draft decision are due on November 8, and the Utility expects that the CPUC will issue a final decision by November 19, 2004. Assuming the timely satisfaction of these remaining conditions, the issuance of the first series of ERBs, in the amount of the after-tax balance of the Settlement Regulatory Asset (estimated to be approximately $1.8 billion), is targeted to occur in January 2005. Upon refinancing with securitization, the equity and debt components of the Utility's rate of return will be replaced with the lower interest rate of the securitized debt. The Utility would collect from customers amounts sufficient to service the principal and interest payments on the ERBs. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.

~~Chapter 11 Claims~~

The following table summarizes the disposition of the net creditor claims made in the Utility's Chapter 11 proceeding, the amount of funds held in escrow for the resolution of disputed claims and the disputed claims accrued by the Utility at September 30, 2004:

~~(in billions)~~
~~Total filed claims in the Utility's Chapter 11 proceeding~~			$	~~51.7~~
~~ISO, PX and generator claims disallowed~~		~~(8.2)~~
~~Other claims disallowed by the bankruptcy court~~		~~(25.4)~~
~~Claims objected to by the Utility and pending before the bankruptcy court~~		~~(0.1)~~
~~Pass-through claims, including environmental, pending litigation and tort claims~~⁽¹⁾		~~(4.7)~~
~~Principal payments made prior to the effectiveness of the Plan of Reorganization~~		~~(2.3)~~
~~Claims settled with the cancellation of bonds owned by the Utility~~		~~(0.3)~~
~~Payments on claims on and after the effectiveness of the Plan of Reorganization~~⁽²⁾		~~(8.2)~~
~~Reinstated Pollution Control Bonds~~			~~(0.8)~~

~~Amount retained in escrow for remaining disputed claims - principal, at September 30, 2004~~			$	~~1.7~~
~~Disputed claims not accrued by the Utility~~				~~(0.1)~~

~~Net disputed claims accrued by the Utility at September 30, 2004~~			$	~~1.6~~






~~(1)~~	The Utility has analyzed these claims and has recorded reserves for such claims that are included in the Utility's undiscounted environmental remediation liability of approximately $342 million at September 30, 2004 and the Utility's provision for legal matters of approximately $198 million at September 30, 2004, as discussed below in Note 6.
~~(2)~~	~~The Utility also made payments of approximately $0.2 billion for interest and bank premiums upon the effectiveness of the Plan of Reorganization.~~

As of September 30, 2004, the Utility had accrued approximately $1.6 billion for remaining disputed claims, consisting of approximately $2.1 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator, or the 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. As disclosed in the table above, in connection with the implementation of the Plan of Reorganization, the Utility retained $1.7 billion in escrow for the payment of remaining disputed claims as of September 30, 2004. Although the Utility was required to retain $1.7 billion in escrow, the Utility does not believe it is probable that it will be found liable for approximately $0.1 billion of the $1.7 billion of the disputed claims and, therefore, in accordance with SFAS No. 5, "Accounting for Contingencies,~~" or SFAS No. 5, the Utili ty has not recorded a liability in its financial statements for this amount.~~

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:

Balance At
September 30,
December 31,
(in millions)
2004
2003
PG&E Corporation
   Senior secured notes, 6⅞ %, due 2008
$
600
$
600
   Convertible subordinated notes, 9.50%, due 2010
280
280
   Other long-term debt
2
3
      Total long-term debt
882
883
Utility
   First and refunding mortgage bonds:
      5.85% to 8.80% bonds, maturing 2004-2026
-
2,764
      Unamortized discount net of premium
-
(23)
      Total first and refunding mortgage bonds
-
2,741
   First mortgage bonds:
      2.30% to 6.05% bonds, maturing 2006-2034
6,700
-
      Unamortized discount, net of premium
(18)
-
      Total first mortgage bonds
6,682
-
   Pollution control loan agreements, variable rates, due 2007
614
-
   Pollution control loan agreements, 5.35%, due 2016
200
-
   Pollution control bond agreements, 3.50%, due 2023
345
-
   Pollution control bond bridge facilities, variable rates, due 2005
454
-
   Other
6
-
   Less: current portion
(457)
(310)
      Total long-term debt, net of current portion
7,844
2,431
Total consolidated long-term debt, net of current portion
$
8,726
$
3,314
Long-term debt subject to compromise:
   Senior notes, 10.75%, due 2005
$
-
$
680
   Pollution control loan agreements, variable rates, due 2026
-
614
   Pollution control loan agreements, 5.35%, due 2016
-
200
   Unsecured medium-term notes, 6.94% to 9.58%, due 2004-2014
-
287
   Deferrable interest subordinated debentures, 7.90%, due 2025
-
300
   Other
-
17
      Total long-term debt subject to compromise
$
-
$
2,098

	Balance At

(in millions)	March 31, 2005		December 31, 2004

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

		280			280

Utility
First mortgage bonds:
3.26% to 6.05% bonds, due 2006-2034	5,300		6,200
Unamortized discount, net of premium		(17)			(17)

Total first mortgage bonds		5,283			6,183
Pollution control bond loan agreements, variable rates, due 2007	614		614
Pollution control bond loan agreement, 5.35%, due 2016	200		200
Pollution control bond loan agreements, 3.50%, due 2007	345		345
Pollution control bond reimbursement obligations, variable rates, due 2005	454		454
Other	3		4
Less: current portion	(457)		(757)

	6,442		7,043

Total consolidated long-term debt, net of current portion	$	6,722		$	7,323

~~Utility~~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. On April 15, 2005, PG&E Corporation paid app roximately $6 million of pass-through dividends to 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 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 PG&E Corporation's Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets at March ~~2004, in connection with~~31, 2005. At March 31, 2005, the ~~implementation~~total estimated fair value of the ~~Plan~~dividend participation rights component, on a pre-tax basis, was approximately $92 million, of ~~Reorganization,~~which $20 million is classified as a current liability (in Current liabilities-Other) and $72 million is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in mark to market fair value for the ~~Utility issued $6.7 billion of First Mortgage Bonds, or First Mortgage Bonds,~~quarter ended March 31, 2005, was immaterial, and ~~together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. The Utility obtained an interim $400~~was approximately $32 million, ~~cash collateralized letter of credit facility, which was terminated on April 12, 2004,~~pre-tax, for the ~~effective date of the Plan of Reorganization, or the Effective Date, and the letters of credit then outstanding were transferred to the $850 million revolving credit facility.~~quarter ended March 31, 2004.

Utility

First Mortgage ~~Bonds~~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 March 31, 2005, the inter est rate on the Floating Rate First Mortgage Bonds was 3.26%. On April 3, 2005, the rate was reset to 3.82%. The next reset date is ~~January~~July 3, 2005.

~~In addition, approximately $2.5 billion of additional~~ First Mortgage Bonds in the aggregate amount of $2.5 billion also were ~~issued on the Effective Date~~used to ~~various banks and insurance companies under the following agreements (1)~~secure the Utility's ~~$620 million letters of credit backing pollution control bonds, (2) the Utility's reimbursement obligation~~obligations under an insurance policy relating to $200 million in pollution control bonds that were issued for the benefit of the Utility, (3) the Utility's $345 million loan agreements with the California Pollution Control Financing Authority, or the CPCFA, (4) the Utility's $454 million reimbursement agreements for pollution control bond bridge facilities, and (5) the Utility's $850 million working capital facility.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.

The First Mortgage Bonds ~~are~~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. ~~Subject to certain~~The lien was released on April 22, 2005, upon satisfaction of various conditions specified in the ~~Utility will be entitled to terminate the lien~~indenture, including confirmation from Moody's Investors Service, or Moody's, and eliminate all terms and conditions relating to collateral for the First Mortgage Bonds on the release date. In general, the release date will occur when the Utility provides written evidence to the trustee of the First Mortgage BondsStandard & Poor's Ratings Service, or S&P, that ~~(1) the ratings on~~ the Utility's ~~long-term~~ unsecured debt ~~obligations~~ratings following the release ~~date~~ would be at least equal the initial ratings assigned by Moody's and S&P on the First Mortgage Bonds, or (2) comparable ratings by any other nationally recognized rating agency or agencies selected by the Utility if either Moody's or S&P do not then rate the Utility's long-term unsecure d debt obligations. The First Mortgage Bonds received initial investment grade credit ratings of Baa2 from Moody's and BBB from S&P.

If On March 3, 2005, Moody's increased the ~~lien securing~~rating on the First Mortgage Bonds ~~is released, the indenture will limit the ability of~~from Baa2 to Baa1. On April 22, 2005, the Utility and ~~its significant subsidiaries~~the trustee entered into an amended and restated indenture to ~~incur secured debt and enter into sale and leaseback transactions.~~

~~Pollution Control Bonds~~

~~Variable Rate and 5.35% Pollution Control Loan Agreements~~

~~Under pollution control loan agreements,~~eliminate the ~~Utility is obligated~~provisions related to ~~reimburse~~ the ~~CPCFA for funds received by the Utility from the issuance~~lien of the ~~CPCFA's pollution control bonds for the benefit of the Utility.~~mortgage. The principal amount of these loan obligations totaled $814 million at September 30, 2004. Interest rates on $614 million of $814 million of the obligations are variable. As of September 30, 2004, the variable interest rates ranged from 1.35% to 1.38%. The interest rate on the remaining $200 million of the obligations is fixed at 5.35%.

The CPCFA pollution control bonds in the principal amount of $200 million, bearing interest at a fixed rate, are backed by bond insurance. The CPCFA pollution control bonds in the principal amount of $614 million, bearing interest at variable rates, are backed by letters of credit of $620 million. The Utility's reimbursement obligations are supported by $820 million in First Mortgage Bonds ~~that~~ have been ~~issued to the bond insurer and letter of credit banks.~~

Drawings for interest due under the loan agreements are made under these letters of credit on each scheduled interest payment date, which is the first business day of each month. On the same day, the Utility pays the amount of the draw to the letter of credit banks per terms of the reimbursement agreements. The letters of credit are then reinstated to the full amount of their initial commitments.

~~Pollution Control Bond Terms Loan Facility and 3.5% Pollution Control Bonds Loan Agreements~~

On the Effective Date, the Utility entered into a $345 million term loan facility that was used to fund the Utility's purchase, in lieu of redemption, of the CPCFA's Pollution Control Revenue Bonds, 1992 Series A and B and 1993 Series A and B, or collectively the Old Bonds.

~~On June 29, 2004, the Utility entered into four separate loan agreements, each dated~~redesignated as of June 1, 2004, with the CPCFA, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, 2004 Series A ($70 million), 2004 Series B ($90 million), 2004 Series C ($85 million) and 2004 Series D ($100 million), or collectively the New Bonds, to refund the Old Bonds held by the Utility. The funds made available from the refund of Old Bonds were used to repay the $345 million term loan facility. Principal and interest payments on the New Bonds are backed by bond insurance and the Utility's obligations under the new loan agreements are supported by $345 million of First Mortgage Bonds that are held by the trustee for the New Bonds. The New Bonds must be purchased from their holders on June 1, 2007.

~~Pollution Control Bond Bridge Facilities~~

During the Utility's Chapter 11 proceeding, approximately $454 million in aggregate principal amount of pollution control bonds, which were issued for the Utility's benefit and were credit enhanced with letters of credit were redeemed through draws on the letters of credit. On the Effective Date, the Utility executed bridge loans with new lenders who had purchased the $454 million reimbursement obligations owed by the Utility to the letter of credit issuers and entered into four separate amended and restated reimbursement agreements with the new lenders. The Utility intends to refinance the $454 million with long-term tax-exempt bonds or taxable debt. The outstanding balance of $454 million at September 30, 2004 under the amended and restated reimbursement agreements is due and payable on June 5, 2005. At the Utility's request and at the sole discretion of each lender, each amended and restated reimbursement agreement may be extended for additional periods. On the Effective Date, the Utility supported its obligations under the amended and restated reimbursement agreement with $454 million of First Mortgage Bonds.

~~Repayment Schedule~~

~~The following table details the scheduled maturities of the Utility's long-term debt outstanding at September 30, 2004:~~

(in millions)
2004

2005

2006

2007

2008

Thereafter

Total
Long-term debt:
Average fixed interest rate
7.40%
-
-
3.50%
-
5.34%
5.22%
Fixed rate obligations
$
1
$
-
$
-
$
345
$
-
$
5,282
$
5,628
Variable interest rate as of    September 30, 2004
-
2.85%
2.30%
1.35-1.38%
-
-
-
Variable rate obligations
-
454
1,600
614
-
-
2,668
Other
1
2
2
-
-
-
5
Total
$
2
$
456
$
1,602
$
959
$
-
$
5,282
$
8,301

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

The following table summarizes the Utility's outstanding credit facilities and short-term borrowings subject to compromise at December 31, 2003, which were paid and cancelled on the Effective Date. At September 30, 2004, the Utility and its consolidated subsidiaries did not have any outstanding balances on any of its credit facilities. At September 30, 2004, PG&E Corporation did not maintain any credit facilities or have any short-term borrowings. The Utility's and its consolidated subsidiaries' credit facilities and agreements consist of the following:follows:

~~(in millions)~~

~~September 30, 2004~~First Mortgage Bonds

~~December 31, 2003~~Redesignated As

Amount

3.6% First Mortgage Bonds due 2009

3.6% Senior Notes due 2009

$600 million

4.2% First Mortgage Bonds due 2011

4.2% Senior Notes due 2011

$500 million

4.8% First Mortgage Bonds due 2014

4.8% Senior Notes due 2014

$1 billion

6.05% First Mortgage Bonds due 2034

6.05% Senior Notes due 2034

$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 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 aggregating $614 million that had been issued to support certain pollution control bonds issued on behalf of the Utility. 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 from three years to five years until April 22, 2010.

Repayment Schedule

At March 31, 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


Long-term debt:
PG&E Corporation
Average fixed interest rate		-		-		-			-		-		9.50%			9.50%
Fixed rate obligations	$	-	$	-	$	-	$		-	$	-	$	280	$		280
Utility
Average fixed interest rate	-			-	3.50%		-			3.60%		5.78%		5.43%
Fixed rate obligations	$	-	$	-	$	345	$		-	$	600	$	4,683	$	5,628
Variable interest rate as of March 31, 2005		4.00%		3.26%		2.30%		-			-		-		-
Variable rate obligations	$	454	$	200	$	614	$	-		$	-	$	-	$	1,268
Other	$	2	$	1	$	-	$	-		$	-	$	-	$	3

Total consolidated long-term debt	$	456	$	201	$	959	$		-	$	600	$	4,963	$	7,179



ERBs & RRBs:
Utility
Average fixed interest rate		6.42%		6.44%	6.48%				-		-		-		6.45%
Rate reduction bonds	$	216	$	290	$	290	$		-	$	-	$	-	$	796

Average fixed interest rate		3.32%		3.55%	3.87%				3.87%		4.05%		4.35%		4.02%
Energy recovery bonds	$	140	$	221	$	230	$		239	$	248	$	810	$	1,888

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 March 31, 2005 and December 31, 2004:

(in millions)	March 31, 2005					December 31, 2004

	Revolving Credit Limit		Outstanding			Outstanding

Short-Term Borrowings:
PG&E Corporation
Senior credit facility	$	200	$	-		$	-

Total credit facilities	$	200	$	-		$	-




Utility
Accounts receivable financing	$	650	$		-	$	-
Working capital facility	850			-		300

Total credit facilities	$	1,500	$	-		$	300

Other Credit ~~facilities:~~Facilities:

Utility

~~Revolving Credit Limit~~

~~Outstanding~~

~~Outstanding~~March 31, 2005

Letters of credit⁽¹⁾:

~~Accounts receivable financing~~

~~650~~

~~Working capital facility~~

~~850~~

~~Total credit facilities~~

~~1,500~~

~~Credit facilities subject to compromise:~~

~~5-year revolving credit facility~~

~~938~~

~~Total credit facilities subject to compromise~~

~~938~~

~~Short-term borrowings subject to compromise~~

~~Bank borrowings - drawn letters of credit for~~
~~accelerated pollution control agreement~~

~~454~~

~~Floating rate notes~~

~~1,240~~

~~Commercial paper~~

~~873~~

~~Total credit facilities and short-term borrowings~~
~~subject to compromise~~

~~3,505~~

		~~September 30, 2004~~

~~Letters of Credit~~⁽¹⁾:
Pollution control ~~bonds~~bond reimbursement agreements		$	620
Working capital facility		~~163~~155

Total letters of credit		$	~~783~~775



First ~~Mortgage Bonds~~mortgage bonds issued to secure and support various debt and credit facilities⁽¹⁾:
Pollution control bond loan agreements, variable rates, due 2007		$	620
Pollution control bond loan ~~agreements,~~agreement, 5.35%, due ~~2006~~2016		200
Pollution control bond loan agreements, 3.50% variable, due ~~2023~~2007		345
Pollution control bond ~~bridge facilities,~~reimbursement obligations, variable rates, due 2005		454
Working capital facility		850

Total First Mortgage Bonds issued to secure and support various debt and credit facilities		$	2,469






(1)	Off-balance sheet commitments.

~~Accounts Receivable Financing~~PG&E Corporation

Senior Credit Facility

On ~~March 5,~~December 10, 2004, ~~the Utility~~PG&E Corporation entered into ~~certain agreements providing~~a $200 million revolving senior unsecured credit facility, or the senior credit facility, which includes a $50 million sublimit for the ~~continuous sale~~issuance of ~~a portion~~letters of the Utility's accounts receivable to PG&E Accounts Receivable Company, LLC, or PG&E ARC, a limited liability company wholly owned by the Utility. In turn, PG&E ARC sells interests in its accounts receivable to commercial paper conduits or banks. PG&E ARC may obtain up to $650 million of financing under such agreements. The borrowings under this facility bear interest at commercial paper ratescredit and a ~~fixed margin based~~$100 million sublimit for swing line loans (loans made available on a same day basis and repayable in full within thirty days). Borrowings and letters of credit under the Utility's credit ratings. Interest on the facility is payable monthly. The maximum amount available for borrowing under this facility changes based upon the amount of eligible receivables, concentration of eligible receivables and other factors. Unless extended, thesenior credit facility will ~~terminate~~be used for working capital and other corporate purposes. On April 8, 2005, PG&E Corporation entered into an amendment, which became effective on ~~March 5, 2007. The~~April 12, 2005, to 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 ca pital facility, discussed below.

At PG&E Corporation's request and at the sole discretion of each lender, the senior credit facility may be extended for additional ~~periods upon~~periods. PG&E Corporation has the ~~agreement~~right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $100 million provided certain conditions are met. At March 31, 2005, PG&E Corporation had not made any borrowings or issued any letters of ~~all parties.~~credit under the senior credit facility.

The ~~Utility began selling accounts receivables to~~fees and interest rates PG&E ~~ARC~~Corporation pays under the senior credit facility vary depending on the ~~Effective Date~~Utility's unsecured debt ratings issued by S&P and ~~used~~Moody's. A facility fee based on the ~~proceeds from the sale~~total amount of the ~~accounts receivable in connection with this~~senior credit facility ~~to pay allowed claims~~(regardless of the usage) and a utilization fee based on the ~~Effective Date. On May 7, 2004, PG&E ARC paid off this~~average daily amount outstanding under the senior credit facility ~~and on September 30, 2004, there were no amounts drawn on~~are payable quarterly in arrears. The utilization fee is payable during any quarter in which the ~~credit facility. Although PG&E ARC is a wholly owned consolidated subsidiary of~~average daily amount outstanding under the Utility, PG&E ARC is legally separate from the Utility. The assets of PG&E ARC (including the accounts receivable) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivable are not legally assets of the Utility or PG&E Corporation. For the purposes of financial reporting, thesenior credit facility is ~~accounted~~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 swing line 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 swing line loan bears interest at the applicable margin plus the base rate. The applicable margin ranges between 0.50% and 1.35% for asEurodollar 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.

In addition, PG&E Corporation pays a ~~secured financing.~~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 ~~accounts receivable~~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. The senior credit facility requires that PG&E Corporation maintain a ~~covenant from the Utility requiring it~~debt to ~~maintain,~~capitalization ratio of at most 65% as of the end of each fiscal quarter ~~ending after~~and that PG&E Corporation own, directly or indirectly, at least 80% of the ~~Effective Date,~~common stock and at least 70% of the voting securities of the Utility.

In the event of a default by PG&E Corporation under the senior credit facility, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $100 million, the lenders may terminate the commitments under the senior credit facility and declare the amounts outstanding, including all accrued interest and unpaid fees, payable immediately. The lenders may also enforce all rights and remedies created under applicable law, including set-off rights, and all rights and remedies under the senior credit facility. For events of default relating to ~~capitalization ratio of at most 0.65 to 1.00.~~insolvency, bankruptcy or receivership, the commitments are automatically terminated and the amounts outstanding become payable immediately.

Utility

Working Capital Facility

On ~~March 5, 2004,~~April 8, 2005, the Utility entered into ~~an $850 million~~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, shortly before the Utility's plan of reorganization under Chapter 11 became effective. The working capital facility ~~with~~includes a ~~syndicate~~$600 million sublimit for the issuance of ~~banks.~~letters of credit and a $100 million sublimit for swing line loans. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash ~~flows.~~flows and may also be used for bridge financing in connection with the reissuance of tax-exempt pollution control bonds. 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 $850million,in the aggregate for all such increases.

The working capital facility has a term of ~~three~~five years and all ~~outstanding~~ amounts will be due and payable on ~~March 5, 2007.~~April 8, 2010. At the Utility's request and at the sole discretion of each lender, the ~~working capital~~ facility may be extended for additional periods. OnThe Utility has the ~~Effective Date,~~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 ~~supported its obligation~~maintain a debt to capitalization ratio of at most 65% as of the end of each fiscal quarter.

In the event of a default by the Utility under the working capital facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $100 million, the lenders may terminate the commitments under the working capital facility and declare the amounts outstanding, including all accrued interest and unpaid fees, payable immediately. The lenders may also enforce all rights and remedies created under applicable law, including set-off rights, and all rights and remedies under the working capital facility. For events of default relating to insolvency, bankruptcy or receivership, the commitments are automatically terminated and the amounts outstanding become payable immediately.

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 based on the total amount of the working capital facility (regardless of the usage) and a utilization fee based on the average daily amount outstanding under the working capital facility are payable quarterly in arrears. 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 swing line 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 swing line loan bears interest at the applicable margin plus the base rate. Interest is payable quarterly in arrears, or earlier for loans with ~~First Mortgage Bonds. There~~shorter interest periods.

The facility fee, the utilization fee and the applicable margin are determined in accordance with the following table:

	Applicable Margin for

S&P/Moody's Rating	Base Rate Loans	LIBOR Loans/Letters of Credit	Facility Fee Rate	Utilization Fee Rate

A/A2 or higher	0%	0.220%	0.080%	0.100%
A-/A3	0%	0.300%	0.100%	0.100%
BBB+/Baa1	0%	0.350%	0.125%	0.125%
BBB/Baa2	0%	0.425%	0.150%	0.125%
BBB-/Baa3	0%	0.575%	0.175%	0.125%
BB+/Ba1 or lower	0%	0.675%	0.200%	0.250%

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 March 31, 2005, there were no loans outstanding under the $850 million working capital facility. The Utility repaid $300 million of loans outstanding under the $850 million working capital facility ~~at September 30 , 2004. However, the Utility had~~on February 11, 2005. At March 31, 2005, there were approximately ~~$163~~$155 million of letters of credit ~~outstanding.~~

~~The working capital facility includes covenants requiring:~~

·	~~Maintenance, as of the end of each fiscal quarter ending after the Effective Date, of a debt to capitalization ratio of at most 0.65 to 1.00; and~~
·	Until the lien securing the First Mortgage Bonds is released, a limitation on liens other than those specifically permitted by the indenture for the First Mortgage Bonds. As noted above, after the release of the lien, the First Mortgage Bonds indenture then limits the ability of the Utility and its significant subsidiaries to incur secured debt and enter into sale and leaseback transactions.

~~Cash Collateralized Letter of Credit~~

On March 2, 2004, the Utility entered into a cash collateralized $400 million letter of credit facility that was used to issue letters of credit to provide credit support in connection with the Utility's pre-existing and new natural gas procurement activities and related purchases of natural gas transportation services. As discussed above, this credit facility was terminated on the Effective Date, and the outstanding ~~balance of letters of credit was transferred to~~under the $850 million working capital facility, which were transferred to 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 millionunder 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 Utility anticipates that the draw under its working capital facility will be repaid with the proceeds of a future tax-exempt financing through the issuance of bonds for the benefit of the Utility by the California Infrastructure and Economic Development Bank. The Utility passes on to its customers inte rest cost savings attributable to the lower interest rates associated with such tax-exempt financing.

NOTE 4: ENERGY RECOVERY BONDS

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 $1.9 billion of ERBs. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as "recovery property," to be paid a specified amount from a DRC. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility's electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF.

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 $1.1 billion, will be paid by PERF to the Utility to pre-fund the Utility's recovery through rates of the tax payments that will be due as the Utility collects the DRC over the term of t he first series of ERBs to pay principal.

The total principal amount of ERBs outstanding was $1.9 billion at March 31, 2005. The scheduled principal payments on the ERBs for the years 2005 through 2009 are $140 million, $221 million, $230 million, $239 million, and $248 million, respectively.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 three months ended March 31, 2005 were as follows:

	PG&E Corporation		Utility

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


Balance at December 31, 2004	$	8,633	$	9,130
Net income	218		223
Common stock issued	120		-
PG&E Corporation common stock repurchased:	-		-
Settlement of accelerated share repurchase obligation - February 2005	(14)		-
Accelerated share repurchase - March 2005	(1,051)		-
Utility common stock repurchased	-		(960)
Common restricted stock issued	-		-
Common restricted stock cancelled	-		-
Common restricted stock amortization	3		-
Common stock dividends declared but not yet paid	(111)		(110)
Preferred stock dividends	-		(4)
Tax benefit from employee stock options	25		-
Minimum pension liability adjustment	(1)		(2)
Other	(1)		(1)

Balance at March 31, 2005	$	7,821	$	8,276

Stock Repurchases

On February 22, 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 market price 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.

On March 4, 2005, PG&E Corporation entered into a new 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 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 accelerated share repurchase arrangement, PG&E Corporation may receive from, or be required to pay to, GS&Co. a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement (approximately six months). Because the price adjustment and any a dditional payments that PG&E Corporation may be required to make can be settled at PG&E Corporation's option, in cash or in shares of its common stock, or a combination of the two, PG&E Corporation accounts for its payment obligations as equity.

Until the transaction is completed or terminated, GAAP requires PG&E Corporation to assume that it will issue shares to settle its obligations (up to a maximum of two times the number of shares repurchased or 58,978,800 shares). PG&E Corporation must calculate the number of shares that would be required to satisfy its obligations upon completion of the transaction 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. At March 31, 2005, PG&E Corporation did not have any net payment obligations to GS&Co. Accordingly, no additional shares of PG&E Corporation common stock attributable to the accelerated repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings p er share. Based upon the average price of PG&E Corporation stock from March 4, 2005 to March 31, 2005, and additional payments, GS&Co. had a net payment obligation to PG&E Corporation of approximately $1 million at March 31, 2005.

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 recognized charges 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.

Dividends

On February 16, 2005, the Board of Directors of the Utility declared a dividend of $117 million that was paid on February 17, 2005, to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that held approximately 6% of the Utility's common stock.

Also, on February 16, 2005, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.30 per share to shareholders of record on March 31, 2005. On April 15, 2005, PG&E Corporation paid this dividend totaling approximately $118 million, of which 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 ~~Notes~~Note holders of record on March 31, 2005.

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Notes that are scheduled to mature on June 30, 2010. These Convertible 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 $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, the terms of the Convertible Notes entitle the note holders to participate in anycharged dividends declared ~~and paid on PG&E Corporation's common shares based on their equity conversion value.~~

~~In accordance with SFAS No. 133, the dividend participation rights component is considered~~ to ~~be an embedded derivative instrument~~Accumulated Earnings and therefore, must be bifurcated from the Convertible Notes and marked to market on PG&E Corporation's Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets as a non-current liability (in Non-current liabilities - other). At September 30, 2004, the estimated fair value of the dividend participation rights component was approximately $70 million, an increase in value of approximately $3 million, net of taxes, from June 30, 2004, and a year-to-date increase of approximately $41 million, net of taxes, for the nine-month period ended September 30, 2004.

~~Senior Secured Notes~~

PG&E Corporation currently has outstanding $600 million of 6⅞% Senior Secured Notes due July 15, 2008, or Senior Secured Notes. The Senior Secured Notes are secured by a perfected first-priority security interest in approximately 94% of the outstanding common stock of the Utility ~~that is owned by PG&E Corporation. On October 14, 2004, PG&E Corporation notified the trustee of its decision~~charged dividends declared to redeem the Senior Secured Notes in full. On October 15, 2004, the trustee sent a notice to all holders that the Senior Secured Notes would be redeemed in full on November 15, 2004. Redemption of the Senior Secured Notes will require approximately $664.5 million of PG&E Corporation's cash, which includes a redemption premium of approximately $50.7 million and $13.8 million of interest that has accrued since the last interest payment date. As a result of the Senior Secured Note redemption, PG&E C orporation will write off $14.6 million of unamortized loan fees.Reinvested Earnings.

~~NOTE 4: DISCONTINUED OPERATIONS~~

Effective July 8, 2003 (the date NEGT filed a voluntary petition for relief under Chapter 11), NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under GAAP, consolidation is generally required for entities owning more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retained significant influence over the ongoing operations of NEG T.

Accordingly, PG&E Corporation's negative investment in NEGT of approximately $1.2 billion is reflected as a single amount, under the cost method, within the September 30, 2004 Consolidated Balance Sheets of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. Furthermore, at September 30, 2004, the Consolidated Balance Sheet includes a net deferred tax asset of approximately $432 million, a current tax liability of approximately $145 million, other net liabilities of approximately $28 million and a charge of approximately $77 million, net of tax, in accumulated other comprehensive income, related to NEGT.

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. On the effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed NEGT-related deferred income tax assets and accumulated other comprehensiveincome. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation (See Note 6, Commitments and Contingencies). A summary of the approximate effect on earnings from discontinued operations is as follows:

~~(in millions)~~
~~Investment in NEGT~~	$	~~1,211~~
~~Accumulated other comprehensive income~~	~~(120)~~
~~Cash paid pursuant to settlement of tax related litigation~~	~~(30)~~
~~Tax Effect~~	~~(381)~~

~~Gain on disposal of NEGT, net of tax~~	$	~~680~~

Subsequent to the cancellation of its equity interest, at October 29, 2004, PG&E Corporation's Consolidated Balance Sheet includes $166 million in income tax and other net liabilities related to NEGT. Beginning on the effective date of NEGT's plan of reorganization, PG&E Corporation will no longer include NEGT or its subsidiaries in its consolidated income tax returns.

~~NEGT Operating Results~~

~~Included within earnings from discontinued operations on the Consolidated Statements of Income of PG&E Corporation are NEGT's operating results, summarized below:~~

		~~188 days ended~~
~~(in millions)~~		~~July 7, 2003~~


~~Operating revenues~~⁽¹⁾		$	~~786~~
~~Loss before income taxes~~⁽¹⁾		~~(595)~~
~~Net income~~⁽¹⁾		~~(370)~~



~~(1)~~	~~Amounts shown have been adjusted for intercompany eliminations.~~

Prior to July 8, 2003, NEGT had accounted for certain of its subsidiaries as discontinued operations. The operating results shown above reflect the operating results of USGen New England, Inc. through September 30, 2003 and the other previously discontinued operations through the respective disposal dates. The pre-tax loss of NEGT and its subsidiaries for the nine months ended September 30, 2003 includes the following gains and losses on disposal of those subsidiaries: a pre-tax loss of approximately $14 million on disposal of certain Ohio generating plants, a pre-tax gain of approximately $19 million on disposal related to the sale of Mountain View Power Partners, LLC in January 2003, and an additional pre-tax loss of approximately $3 million on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003.

In 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT and its subsidiaries due to the uncertainty of their realization. Valuation allowances of approximately $24 million were recorded in discontinued operations and approximately $5 million was recorded in accumulated other comprehensive loss for the nine-month period ended September 30, 2003. No similar amounts were recorded in the three-month period ended September 30, 2003 or during 2004.

NOTE ~~5: PRICE~~6: RISK MANAGEMENT ACTIVITIES

As discussed in Note 4, NEGT financial results are no longer consolidated with those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. NEGT's financial results through July 7, 2003 are reflected in discontinued operations. Because NEGT financial results are no longer consolidated with those of PG&E Corporation, the only risk management activities currently reported by PG&E Corporation are related to Utility non-trading activities, which are executed on a non-trading basis.

Non-Trading Activities

~~At September 30, 2004, the~~The Utility ~~had cash flow hedges~~enters into non-trading activities related to procurement of electricity and contracts associated with ~~its~~the natural gas ~~commodity~~and nuclear fuel portfolio. On the Utility's Consolidated Balance Sheets, price ~~risk. These cash flow hedges~~risk management activities are presented at fair value of $17million in other current assets for March 31, 2005, and $5 million in other current assets ~~on the Utility's Consolidated Balance Sheets. At December 31, 2003, the Utility had cash flow hedges associated with natural gas commodity price risk that are presented at fair value of $4~~and $11 million in other current assets. These hedges are associated with regulated operations. Therefore, the effective and ineffective portions are recoverable through regulated rates, and are recorded on the balance sheet in regulatory accounts.

~~The Utility has certain contracts~~liabilities for the purchase of electricity, natural gas transportation and storage, and nuclear fuel that are either exempt from the SFAS No. 133 fair value requirements under the scope exceptions or are not derivative instruments and, therefore, have no mark-to-market effect on earnings. Additionally, the Utility holds derivative instruments that do not qualify for cash flow hedge accounting or the scope exceptions to SFAS No. 133. At September 30, 2004, the fair value of $9 million is recorded in other current assets and $3 million is recorded in other current liabilities.December 31, 2004. The costs of these derivatives are recovered ~~through~~in regulated rates charged to customers and the Utility records the offset to 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 $2.0 billion at ~~September 30, 2004~~March 31, 2005 and ~~approximately $2.5~~$2.2 billion at December 31, ~~2003.~~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 ~~$63~~$88 million at ~~September 30, 2004~~March 31, 2005 and ~~approximately $68~~$93 million at December 31, ~~2003~~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 ~~f rom~~from these customers is not ~~considered~~considere d likely.

The Utility manages credit risk for its ~~wholesale~~largest customers ~~and~~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 ~~wholesale~~largest customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure ~~which could include obtaining~~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 ~~the first nine months of~~ 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At ~~September 30, 2004,~~March 31, 2005, there were two counterparties that represented greater than 10% of the Utility's net ~~wholesale~~ credit exposure. ~~These two~~Both of these counterparties were investment grade ~~counterparties represented~~representing a total of approximately ~~46%~~47% 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 ~~asset~~ 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 ~~September 30, 2004~~March 31, 2005 and December 31, ~~2003.~~2004:

(in millions)	(in millions)	Gross Credit Exposure BeforeCredit Collateral⁽¹⁾		Credit Collateral		Net Credit Exposure⁽²⁾		Number of Wholesale Customers or Counterparties >10%		Net Exposure to Wholesale Customers 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%

September 30, 2004		$	108	$	13	$	95		2		$	43
December 31, 2003		165		11		154		3		68
March 31, 2005													March 31, 2005	$	209	$	14	$	195	2	$	92
December 31, 2004													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 ~~September 30, 2004~~March 31, 2005 and December 31, ~~2003:~~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⁾
September 30, 2004
March 31, 2005					March 31, 2005
Investment grade⁽³⁾	Investment grade⁽³⁾	$	92	97%	Investment grade⁽³⁾	$	192	98%
Non-investment grade	Non-investment grade	3		3%	Non-investment grade		3	2%

Total	Total	$	95	100%	Total	$	195	100%


December 31, 2003
December 31, 2004					December 31, 2004
Investment grade⁽³⁾	Investment grade⁽³⁾	$	108	70%	Investment grade⁽³⁾	$	79	81%
Non-investment grade	Non-investment grade	46		30%	Non-investment grade		19	19%

Total	Total	$	154	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 6:7: COMMITMENTS AND CONTINGENCIES

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

Commitments

PG&E Corporation

For the three months ended March 31, 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. See PG&E Corporation's and the Utility's ~~material contingencies and cancelled, new, and significantly modified commitments since the Current~~combined 2004 Annual Report ~~on Form 8-K dated June 18, 2004 (which supercedes the information included in the combined 2003 Annual Report).~~for further discussion.

~~Commitments~~

Utility

Power Purchase Agreements

~~During~~As part of the ~~nine-month period ended September 30, 2004,~~ordinary course of business, the Utility entered into various agreements to purchase ~~energy. Under these agreements,~~energy and makes payments on existing power purchase agreements. At March 31, 2005, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)

2005	$	1,844
2006		1,975
2007		2,028
2008		1,850
2009		1,638
Thereafter		11,722

Total	$	21,057

Payments made by the Utility ~~is committed~~under power purchase agreements amounted to ~~make energy payments of~~ approximately ~~$159~~$422 million for the three months ended March 31, 2005, and ~~capacity payments of approximately $6~~$464 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~~has fluctuated, generally based on market conditions.

During the period that the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. In connection with its emergence from Chapter 11, the Utility received investment grade issuer credit ratings from Moody's and S&P. As a result of these credit rating upgrades, the Utility has obtained unsecured credit lines from the majority of its gas supply counterparties.

At ~~September 30, 2004,~~March 31, 2005, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2004	$	371
2005	714		$	916
2006	26			220
2007	7			7
2008	-			-
2009				-
Thereafter	-			-

Total	$	1,118	$	1,143

~~Nuclear Fuel~~ Payments made by the Utility for natural gas purchases and gas transportation services amounted to approximately $588 million for the three months ended March 31, 2005, and $529 million for the same period in 2004.

Reliability Must Run Agreements

The Utility has purchase agreements for nuclear fuel. These agreements have terms ranging from two to eight years and are intended to ensure long-term fuel supply. Deliveries under 9 of the 11 contracts in place at the end of 2003 will be completed by 2005. New contracts for deliveries in 2005 to 2012 are under negotiation. In most cases, the Utility's nuclear fuel contracts are requirements-based. The Utility relies on large, well-established international producers of nuclear fuel in order to diversify its commitments and provide security of supply. Pricing terms also are diversified, ranging from fixed prices to market-based prices to base prices that are escalated using published indices.

~~At September 30, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:~~

(in millions)
2004
$
128
2005
28
2006
29
2007
38
2008
30
Thereafter
64
Total
$
317

~~Transmission Control Agreement~~

~~The Utility has entered into a Transmission Control Agreement, or TCA, with the~~ ISO and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several municipal utilities) under which the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA.

~~The ISO also~~ has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require ~~certain power plants,~~designated units, known as RMR ~~plants,~~units, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. AsAt March 31, 2005, as a party to ~~the~~a Transmission Control Agreement, or TCA, ~~the Utility is responsible for a share of the ISO's costs paid to power plant owners under RMR agreements within the Utility's service territory.~~

~~At September 30, 2004,~~ the Utility estimated that it could be obligated to pay the ISO approximately ~~$605~~$211 million infor costs incurred under these RMR agreements during the period ~~October~~April 1, ~~2004~~2005 to ~~September~~June 30, 2006. Of this amount, the Utility estimates ~~that~~ it would receive approximately ~~$96~~$21 million under ~~its~~these RMR agreements during the same period. These ~~costs~~payments and ~~revenues~~receipts are subject to applicable ratemaking mechanisms.

~~It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO.~~ In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision ~~in a rate case filed by~~addressing subsidiaries of Mirant ~~Corporation, or Mirant, approving~~Corporation. The decision approved rates and a ratemaking methodology that, if affirmed by the FERC, ~~would~~will require the Mirant subsidiaries ~~of Mirant~~ 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 ~~$350~~$360 million, including interest, for the availability of ~~Mirant's~~ 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 Mirant's 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 the Utility's claim throug h September 30, 2004. The settlement agreement is described below. In its order approving the settlement agreement issued April 13, 2005, the FERC terminated the Mirant RMR rate case without deciding the merits of the June 2000 initial decision. The Utility ~~is unable to predict at this time when~~will seek rehearing of only that part of the ~~FERC will issue a final decision in Mirant's c ase, what~~order terminating the FERC's decision will be, the amount of any refunds the Utility may ultimately receive, and how the resolution of this matter would be reflected in the rates. Due to this uncertainty as of September 30, 2004, the Utility had not recorded any amounts in its Consolidated Balance Sheet for any refunds receivable that may result from the FERC's final decision.RMR case.

In November 2001, after the ALJ issued the initial decision in ~~Mirant's~~the Mirant subsidiaries' rate case, ~~various~~two complaints were filed at the FERC against other RMR plant owners, including the Utility, alleging that the ratemaking methodology approved in the ALJ's initial decision should be applied to the other RMR ~~plant owners. If~~agreements. The complainants asked the FERC ~~adopts~~to take no action until after the ~~ALJ's~~FERC issues its final decision in the Mirant subsidiaries' rate ~~case~~case. If the FERC adopted the ALJ's decision and ~~applies~~applied the ratemaking methodology to the Utility's RMR plants, the Utility could behave been required to refund payments it had received from the ISO for the availability of the Utility's RMR plants. ~~The Utility has responded to~~However, on March 23, 2005, the ~~complaint asserting that the methodology~~FERC approved in the ALJ's decision should not apply to the Utility. The FERC has not yet acted on these complaints. The Utility believes the ultimate outcome of this matter will not have an adverse material effect on the Utility's results of operations or financial condition.

~~WAPA Commitments~~

~~In 1967,~~a settlement between the Utility and all the ~~Western Area Power Administration, or WAPA, entered into several long-term power contracts governing~~complainants that resulted in the ~~interconnection~~withdrawal of the Utility's and WAPA's electricity transmission systems, the use of the Utility's electricity transmission and distribution system by WAPA, and the integration of the Utility's and WAPA's customer demands and electricity resources. The contracts give the Utility access to WAPA's excess hydroelectric power and obligate the Utility to provide WAPAcomplaint with electricity when its own resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, which the Utility expects to receive.

On October 15, 2004, the Utility filed Offers of Settlement with the FERC to terminate the FERC rate schedules associated with the 1967 WAPA contracts. The Offers of Settlement were signed by the Utility and WAPA, and in one instance by the California ISO as operator of much of the Utility's transmission system. The Offers of Settlement, if acceptedno decision by the FERC ~~as filed, will terminate the rate schedules associated with the 1967 contracts~~ on January 1, 2005, and will replace them with new service contracts under which the Utility no longer will provide any electric power or transmission services but will continue to provide wholesale distribution service. The new service contracts were filed on October 21, 2004. There is no monetary component to the Offers of Settlement; their purpose is to terminate the 1967 contracts and to replace them. The Utility's cost obligations associated with the 19 67 contracts will terminate with those contracts and related FERC rate schedules and will not be replaced.its merits.

It is possible that the FERC will not accept the Offers of Settlement as filed or will materially alter them or suspend their effectiveness beyond January 1, 2005. The costs to fulfill the Utility's obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electric power that WAPA will need from the Utility in 2005 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, the Utility's estimated net costs, based upon its portfolio and after subtracting revenues received from WAPA, for electricity delivered under the contracts were approximately $57million and $161 million in the three and nine-month periods ended September 30, 2004.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, ~~software licenses,~~ the self-generation incentive program exchange ~~agreements and~~agreementsand telecommunication contracts. At ~~September 30, 2004,~~March 31, 2005, the future minimum payments related to other commitments were as follows:

(in millions)			(in millions)

2004	$	97
2005	95		$	136
2006	32		47
2007	17		17
2008	14		14
2009			6
Thereafter	5		14

Total	$	260	$	234

Payments made by the Utility for other commitments amounted to approximately $17 million for the three months ended March 31, 2005, and $23 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 ~~Utility~~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 ~~significant gain and loss contingencies, which are discussed below.~~

~~2003 General Rate Case~~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 March 31, 2005.

~~In May 2004, the CPUC issued~~PG&E Corporation also retains a ~~decision in~~guarantee of the Utility's 2003 GRC. The 2003 GRC determines the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 and certain succeeding years.

~~The decision approved the July 2003 and September 2003 settlement agreements reached among the Utility and various consumer groups to set the Utility's 2003 base revenue requirements at approximately:~~

·	~~$2.5 billion for electricity distribution operations, representing a $236 million increase over the previously authorized amount;~~
·	~~$912 million for electricity generation operations, representing a $38 million increase over the previously authorized amount; and~~
·	~~$927 million for natural gas distribution operations, representing a $52 million increase over the previously authorized amount.~~

As part of the GRC, the CPUC approved the following minimum and maximum yearly adjustments to the Utility's 2003 base revenue requirements, or attrition rate adjustments, for 2004, 2005, and 2006 based on the change in the Consumer's Price Index, or CPI:

2004

2005

2006
Electricity and Natural
Gas Distribution
Minimum
2.00%
2.25%
3.00%
Multiplier
Change in CPI
Change in CPI
Change in CPI+1%
Maximum
3.00%
3.25%
4.00%

Electricity Generation
Minimum
1.50%
1.50%
2.50%
Multiplier
Change in CPI
Change in CPI
Change in CPI+1%
Maximum
3.00%
3.00%
4.00%

In addition, under the GRC decision, if the Utility forecasts a second refueling outage at Diablo Canyon in any one year, the electricity generation revenue requirement would be increased to reflect a fixed revenue requirement of $32 million per refueling outage, adjusted for changes in the CPI in the manner described in the decision. Currently, the only forecasted second refueling outage will occur in 2004.

As a result of the approval of the 2003 GRC, during the second quarter of 2004, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. During the third quarter of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC. The net impact of the items which were recorded in the second quarter, on a pre-tax basis is as follows:

Amount Previously Recorded in 2003
Impact Related to
Net 2004 Adjustment
(in millions)
2003
2004
Electricity revenue
$
273

$
152

$
268

$
157
Natural gas revenue
52

25

-

77
Electricity attrition
-

48

-

48
Natural gas attrition
-

9

-

9
Regulatory assets, net
(17)

158

-

141
Total
$
308

$
392

$
268

$
432

Because the Utility collected revenue subject to refund for electricity distribution and generation in 2003, but not for natural gas distribution, the impact of the 2003 GRC decision on the Utility's 2004 results of operations is different for each area.

For electricity distribution and generation, the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure in 2003. The amount of electricity revenue to be refunded in 2003 incorporated the impact of the electric portion of the GRC settlement and was recorded as a regulatory liability at December 31, 2003. In 2004, the Utility recorded its electricity distribution and generation base revenue requirements under a cost of service ratemaking structure. Because the 2003 refundunderlying obligation already incorporated the impact of the GRC that related to fiscal 2003, and since the CPUC issued a final decision approving a revenue requirement increase in 2004, the Utility recorded the increase related to the six-month period ended June 30, 2004 in its 2004 results of operations of approximately $157 million.

For natural gas distribution, since the CPUC issued a final decision on the Utility's 2003 GRC in 2004, the Utility recorded both the 2003 revenue requirement increase and the 2004 revenue requirement increase related to the six-month period ended June 30, 2004 in its 2004 results of operations of approximately $77 million.

The total attrition adjustment for 2004 is approximately $127 million (consisting of $82 million for base revenue requirements, $32 million allowance for a second refueling outage in 2004 at Diablo Canyon and $13 million for public purpose program expenses) based on the minimum attrition adjustments. The CPUC approved the Utility's attrition requests in July 2004. The Utility recorded the increase related to attrition for the six-month period ended June 30, 2004, in its results of operations of approximately $57 million.

In addition, as a result of the GRC decision, the Utility has recorded various regulatory assets and liabilities associated with the recovery of retained generation assets, unfunded taxes, depreciation, and decommissioning. The net impact of these items resulted in after-tax earnings of approximately $84 million recorded in the Utility's 2004 results of operations. These assets and liabilities are reflected in the Utility's current rates and will be amortized over their respective collection periods.

Another phase of the GRC was established to address the Utility's response to the December 2002 storm and the Utility's reliability performance. In October 2004, the CPUC voted to approve certain storm response improvement initiatives as well as a reliability performance incentive mechanism for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million each year depending on the extent to which the Utility exceeds the reliability performance improvement targets, but could be required to pay ~~a penalty~~workers' compensation claims. As of ~~up to $24 million a year depending on~~March 31, 2005, the ~~extent to which it fails to meet the targets. The decision does not provide the~~ actuarially determined workers' compensation liability was approximately $226.7 million.

Utility with additional revenues to meet the reliability standards, but does include a wide margin of error around the targets in order to mitigate potential penalties. PG&E Corporation and the Utility are unable to predict whether or not the Utility will incur a reward or penalty related to the performance incentive mechanism.

PX Block-Forward ~~Contract~~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. The block-forward contracts had an estimated unrealized gain of up to $243 million at the time the state of California seized them. 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 and valuations. The estimated value of the seized contracts has been fully reserved in the Utility's financial statements. This state court litigation is pending.

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 a proceeding pending 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 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 FERC ALJ issued an initial decision in the Refund Proceeding 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 the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In March, 2005 FERC extended the time for review of gas allowance claims by four months. The FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts. The ISO has indicated that it plans to make its compliance filing during the fourth quarter of 2005 with the PX to follow but these filings may be delayed until later in 2005 by an extension granted by FERC for submission of gas allowance claims. In October 2003, the FERC affirmed its March 2003 d ecision and various parties appealed to 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 before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals 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 it is uncertain how it will be applied by the FERC.

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 ISO, 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 by the amount of any additional fuel cost allowance for suppliers.

The Utility has entered into settlements with various power suppliers resolving the Utility's claims against these power suppliers. With the approval of the bankruptcy court, the Utility has withdrawn the amounts resulting from those settlements from the escrow established on the Effective Date for payment of ISO and PX amounts. As of March 31, 2005, the Utility has recorded offsets to the Settlement Regulatory Asset of approximately $309 million, pre-tax ($183 million, after-tax) in connection with these settlements. The final net after-tax amount of any amounts received by the Utility under future settlements with energy suppliers will be credited to customers, either as a reduction to the principal 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 balancing account that tracks recovery of the c ustomer costs and benefits related to the ERBs.

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.

The first part of the two-part settlement is between Mirant and several California parties, including the California Attorney General's Office, the California Department of Water Resources, or DWR, the CPUC, Southern California Edison, San Diego Gas & Electric Company, and the Utility, or the California Parties, resolving market manipulation claims, including 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 Mirant's bankruptcy proceeding. Of these amounts, the Utility will receive approximately $130 million in cash equivalents and $40 million in allowed claims. The final cash value of the allowed claims will not be known until the completion of Mirant's bankruptcy proc eeding.

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 power plant Mirant started to build, but never completed. The Utility plans to file an application with the CPUC to seek authorization to complete and operate Contra Costa Unit 8 under a cost-of-service ratemaking structure. If the Utility and Mirant do not complete the necessary transfer agreement or if the Utility does 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 the Utility the right from 2006 through 2012 to dispatch power from certain RMR units owned by Mirant subsidiaries when the facilities are not needed by the ISO to meet local reliability needs. In addition, 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 Contra Costa and Pittsburg power plants.

The settlement agreement became effective on April 15, 2005, after all regulatory and other approvals required by the settlement agreement were obtained.

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 ~~premiums~~premium of up to $42.5 ~~million.~~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 is no policy coverage limitations for an act caused by foreign terrorists because NEIL would be entitled to receive substantial ~~proceeds from reinsurance coverage for an act caused~~reimbursement by ~~foreign terrorism.~~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 ~~(secondary financial protection)~~ 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 million per incident until the Utility has fully paid its share of the ~~liability.~~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 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.

~~Workers' Compensation Security~~

The Utility is self-insured for workers' compensation. To maintain its status as a self-insurer for workers' compensation, the Utility must either deposit collateral with the California Department of Industrial Relations, or the DIR, or participate in the Alternative Security Deposit program, or the ASP, which is administered by the Self-Insurer's Security Fund, or the SISF. The ASP is a program that allows the SISF to arrange a composite deposit for participating self-insurers on a portfolio basis, rather than individual self-insurers arranging their deposits individually. The SISF arranges portfolio security to be delivered to the DIR for the aggregate self-insured workers' compensation liabilities for participating self-insurers. The SISF composite deposit for participating self-insurers, including the Utility, was established on July 1, 2004, and resulted in the release of the $348 million collateral ($305 mi llion in surety bonds and $43 million in cash) that existed at June 30, 2004. As a result, PG&E Corporation's guarantee of the Utility's reimbursement obligation associated with these surety bonds was also released on July 1, 2004.

PG&E Corporation's guarantee of the Utility's underlying obligation to pay workers' compensation claims remains in place. As of September 30, 2004, the actuarially determined workers' compensation liability was approximately $225 million (discounted).

~~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 from January 2000 to June 2001 through a proceeding pending at the FERC. This FERC 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 FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding 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 the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by the first quarter of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in the Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule being developed by the Ninth Circuit, the parties are required to submit briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds.

The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which appellate review is expected. 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.

As noted above, the FERC asserted in the Refund Proceeding that it does not have the power to direct the power suppliers to make comprehensive market-wide refunds to ratepayers for the period before October 2, 2000. However, 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 addition, in September 2004, acting in a separate case from the Refund Proceeding and the FERC's investigative proceedings, 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 Ninth Circuit remanded the case to the FERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of this Ninth Circuit decision, the FERC has not yet acted on the September 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the FERC.

The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. 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 ISO, 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 recalculation of market prices according to the revised methodology adopted by the FERC in its March 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.

The Utility has entered into various settlements with power suppliers resolving the Utility's claims against these power suppliers. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements will result in a reduction to the Utility's Settlement Regulatory Asset. In its ERB application filed with the CPUC, the Utility has proposed a methodology whereby ratepayers will receive the benefits of any settlements that occur after the Settlement Regulatory Asset has been refinanced by the issuance of the ERBs.

~~El Paso Settlement~~

In June 2003, the Utility, along with SCE the state of California and a number of other parties, entered into a settlement agreement with El Paso Natural Gas Company, or El Paso, which resolves all potential and alleged causes of action against El Paso for its part in alleged manipulation of natural gas and electricity commodity and transportation markets during the California energy crisis. In October 2003, the CPUC approved an allocation of these settlement proceeds. The Utility's natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $215 million of the settlement proceeds over the next 15 to 20 years. In December 2003, the Utility recorded a receivable and corresponding regulatory liability of approximately $200 million for the discounted present value of the future payments. The El Paso settlement became effective in June 2004, at which tim e El Paso made upfront payments totaling approximately $568 million to all parties to the settlement agreement. The Utility's share of El Paso's $568 million upfront payment was approximately $25 million for its natural gas customers and approximately $70 million for its electricity customers. The remaining payments will be made in equal semi-annual installments over the next 15 to 20 years.

The Utility refunded the natural gas payment received from El Paso to core procurement customers in the third quarter of 2004. The portion of the El Paso payment related to core aggregation customers will be refunded beginning January 2005. In accordance with the terms of the Utility's Chapter 11 Settlement Agreement with the CPUC, the Utility recorded the net after-tax amount of the electricity payments received, or approximately $42 million, as an offset to the outstanding balance of the Settlement Regulatory Asset in June 2004.

~~Enron Settlement~~

On December 23, 2003, the Utility entered into a settlement agreement with five subsidiaries of Enron Corp., or Enron, settling certain claims between the Utility and Enron, or the Enron Settlement. The Enron Settlement became effective April 20, 2004. On April 23, 2004, the Utility paid Enron cash of $309 million, plus interest of approximately $41 million. These payments have been reflected in the sources and uses of funds table in Note 2 of the Notes to the Consolidated Financial Statements. As a result of the Enron Settlement, the Utility recorded an after-tax credit of approximately $129 million that reduced the Settlement Regulatory Asset during the quarter ended June 30, 2004.

~~Williams Settlement~~

On February 24, 2004, the Utility and SCE entered into a settlement agreement with The Williams Companies, or the Williams settlement, settling certain pre-petition claims in the Utility's Chapter 11 proceeding. The settlement was approved by the FERC on July 2, 2004 and by the Bankruptcy Court on August 26, 2004. On August 31, 2004, FERC announced that it will rehear its July 2, 2004 order that approved the settlement. Under the Williams settlement, the Utility expects to receive an after-tax credit of approximately $40 million that will reduce the Settlement Regulatory Asset. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

~~Dynegy Settlement~~

In April 2004, the Utility, along with SCE, San Diego Gas & Electric Company, the People of the State of California, and a number of other parties, entered into a settlement agreement with Dynegy Inc., or Dynegy, which resolves alleged overcharge and market manipulation claims from the sale of electricity by Dynegy into the California market during the California energy crisis. A definitive agreement to implement the settlement was filed with the FERC on June 28, 2004 and FERC approved the settlement on October 26, 2004. In terms of the settlement, the Utility estimates it could receive an after-tax credit of approximately $50 million that will reduce the Settlement Regulatory Asset. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

~~Duke Settlement~~

In July 2004, the Utility, along with SCE, San Diego Gas & Electric Company, the People of the State of California through the Attorney General, and other parties, entered into a settlement agreement with Duke Energy Corporation, or Duke, which resolves alleged overcharge and market manipulation claims from the sale of electricity by Duke into the California market during the California energy crisis. In order for this settlement to become effective, it must first be approved by the FERC. The Utility filed a definitive agreement to implement the settlement with the FERC on October 1, 2004. If the Duke settlement is approved, the Utility estimates it will receive an after-tax credit of approximately $50 million that will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

~~DWR Contracts~~

~~The~~ California Department of Water Resources orContracts

Electricity from the DWR allocated contracts provided approximately ~~24%~~28% of the electricity delivered to the Utility's customers for the ~~nine-month~~three-month period ended ~~September 30, 2004.~~March 31, 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 ~~the~~its electricity procurement contracts.

The current DWR contracts 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 ~~facility~~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 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 ~~electricity provided under~~ 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.

The Utility acts as a billing and collection agent for the DWR's sales of its electricity to retail customers and, as a result, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. Because of this pass-through nature of amounts collected on behalf of the DWR, and because the Utility is on cost of service ratemaking, changes in the DWR's revenue requirements are not expected to have a material impact on the Utility's results of operations.

~~PG&E Corporation~~

On August 27, 2004, PG&E Corporation and NEGT, various NEGT subsidiaries, and the official committee of unsecured creditors, or the OCC, in NEGT's Chapter 11 proceeding pending before the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division, or the Bankruptcy Court,reached a settlement resolving certain tax-related litigation, pending in the U.S. District Court for the District of Maryland, or the District Court. In the litigation, NEGT and its creditors asserted that they were entitled to be paid approximately $414 million of the $533 million that PG&E Corporation received from the IRS for an overpayment of 2002 estimated federal income taxes (approximately $361.5 million achieved by the incorporation of losses and deductions related to NEGT or its subsidiaries and approximately $53 million achieved by the incorporation of certain tax credits related to one of NEGT's subsidiaries). In addition to at least $414 million in damages, the plaintiffs sought punitive damages against PG&E Corporation and two former NEGT directors for breach of fiduciary duty and sought punitive damages against PG&E Corporation for deceit as well as interest, costs of suit, and reasonable attorney fees.

~~Pursuant to the settlement agreement, on August 30, 2004, PG&E Corporation deposited $30 million in escrow to be paid to NEGT when~~ ~~the settlement became final and non-appealable. At September 30, 2004,~~the $30 million escrow payment was treated by PG&E Corporation as restricted cash and included as part of the $361.5 million previously reported by PG&E Corporation as restricted cash, while the dispute was pending.

On September 23, 2004, the Bankruptcy Court entered an order approving the settlement agreement and authorized NEGT and its debtor affiliates to execute and deliver the releases and other agreements required to implement the settlement.This order became final and non-appealable on October 4, 2004. On October 12, 2004, the parties (including the creditor committee appointed to represent the interests of NEGT's senior noteholders, which is not a party to the settlement agreement) filed a stipulation dismissing the litigation with the District Court, which the District Court then entered as an order. On October 14, 2004, the settlement agreement became effective. On this date, the $30 million deposited into escrow was paid to NEGT and PG&E Corporation waived certain intercompany claims against NEGT and its debtor subsidiaries. In addition, with certain limited excepti ons, the parties have executed various mutual general releases of substantially all claims between them. In addition, PG&E Corporation and NEGT have entered into a separate agreement under which they have agreed to take certain actions and cooperate with each other with respect to certain tax matters, including future tax returns and audits. As of the settlement's effective date, October 14, 2004, PG&E Corporation no longer treats the remaining amount of $331.5 million as restricted cash.

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 ~~$342~~$408 million at ~~September 30, 2004,~~March 31, 2005, and approximately ~~$314~~$327 million at December 31, ~~2003.~~2004. During the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005, the liability increased by approximately ~~$28~~$81 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately ~~$342~~$408 million accrued at ~~September 30, 2004,~~March 31, 2005, includes approximately ~~$103~~$101 million related to the pre-closing remediation liability associated with divested generation facilities and approximately ~~$239~~$307 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 ~~f ormer manufactured~~former manuf actured gas plant sites. Of the approximately ~~$342~~$408 million environmental remediation liability, approximately ~~$145~~$143 million has been included in prior rate setting proceedings and the Utility expects that approximately ~~$152~~$198 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 ~~ratepayers.~~customers.

The Utility's undiscounted future costs could increase to as much as ~~$464~~$571 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 ~~$464~~$571 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 ~~California Attorney General,~~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' Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on ~~behalf~~its financial position or results of ~~various state environmental agencies, filed claims~~operations.

In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million relating to the 1999 and 2000 audit. The IRS completed its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns during the third quarter of 2004. As a result of the completion of this audit, PG&E Corporation received a refund from the IRS of $14 million in January of 2005.

The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. They have indicated that they plan to complete their audit and issue a Revenue Agent Report in the ~~Utility's Chapter 11 proceeding~~second or third quarter of 2005. During their examination, the IRS has issued several proposed adjustments that PG&E Corporation is currently disputing. The IRS adjustments include disallowance of synthetic fuel credits claimed on these tax returns. In addition, the IRS has proposed to disallow a number of deductions, the largest of which is abandonment losses/worthless deductions claimed on the 2002 tax return related to certain NEGT assets. These assets were ultimately transferred to NEGT lenders in the third quarter of 2004. If the IRS includes all of its proposed adjustments in the final Revenue Agent Report, the alleged tax deficiency would approximate $400 million. Of this deficiency, approximately $104 mil lion relates to the synthetic fuel credits. The remaining $296 million is timing in nature and would reverse in future periods, generally in tax years 2003-2004. PG&E Corporation believes that it properly reported these transactions in its tax returns and will contest any IRS assessment.

PG&E Corporation has accrued $52 million associated with NEGT related tax liabilities. In addition, PG&E Corporation has accrued a $49 million liability to cover potential tax obligations relating to non-NEGT issues on outstanding tax audits. The Utility has accrued $63 million to cover potential tax obligations for ~~environmental remediation at numerous sites totaling approximately $770 million. For most~~outstanding tax audits. Considering these reserves, PG&E Corporation does not expect the resolution of these ~~sites, remediation is ongoing in the ordinary course~~matters to have a material impact on its financial position or results of ~~business or the Utility is in the process~~operations.

In addition, based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $86 million of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the clean-up. Other sites identified in the California Attorney General's claims may not, in fact, require remediation or clean-up actions. Environmental claims in the ordinary course of business were not discharged in the Utility's Chapter 11 proceeding and have passedfederal income taxes on NEGT activities through the ~~Chapter 11 proceeding unimpaired.~~effective date of NEGT's plan of reorganization.

All IRS audits of PG&E Corporation's federal income tax returns prior to 1997 have been closed.

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. On the ~~effective date of the Plan of Reorganization,~~Effective Date, the automatic stay of pending litigation was lifted, so that any state court lawsuits pending before the Utility's Chapter 11 filing that had not yet received relief from the stay can proceed.

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. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals filed proofs of claims in the Utility's Chapter 11 case, most of whom also are plaintiffs in the chromium litigation cases. Approximately 1,035 of these claimants filed claims requesting an approximate aggregate amount of $580 million and approximately another 225 claimants filed claims for an "unknown amount." Pursuant to the ~~Plan~~Utility's plan of ~~Reorganization,~~reorganization, these claims have ~~passed thro ugh~~p assed through the Utility's Chapter 11 proceeding unimpaired.

The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. The Utility will pursue 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 challenging the test trial plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries. The ~~court~~Superior Court for the County of Los Angeles, or Superior Court, began hearing argument on two of ~~the~~these motions in February ~~2004,~~2004. In February 2005, the Superior Court denied these two motions for summary judgment. The Utility has filed motions for reconsideration of these orders with the Superior Court and also filed a request with the appellate court seeking to overturn or modify the orders because they are incon sistent with recent California appellate decisions concerning the admissibility of expert testimony and the requirements for proving medical causation. After the motions for reconsideration and the request were filed, the California Supreme Court granted review of one of these recent appellate decisions. On April 26, 2005, the Superior Court heard argument on the motions for reconsideration, but ~~no rulings have been issued. Although the trial date previously had been scheduled to begin in March 2004, the court vacated the trial date and no new trial date~~ has ~~been set.~~not yet issued a decision.

The Utility has recorded a $160 million reserve in its financial statements with respect to the chromium litigation. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at ~~September 30, 2004,~~March 31, 2005, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations.

Recorded Liability for Legal Matters

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

The ~~provision~~liability for legal matters is included in PG&E Corporation's and the Utility's other noncurrent liabilities in the Consolidated Balance Sheets, and totaled approximately $198 million ~~(which includes the $160 million reserve discussed above)~~ at ~~September 30, 2004,~~March 31, 2005 and ~~$205~~$200 million at December 31, ~~2003.~~2004. Based on current information, PG&E Corporation and the Utility do not believe that ~~after taking into account the liability recorded at September 30, 2004, the outcome of these~~it is probable that losses associated with legal matters that exceed amounts already recognized will ~~not have a~~be incurred in amounts that would be material ~~adverse impact on~~to PG&E Corporation's or the Utility's financial ~~condition~~position or ~~future~~ results of operations.

NOTE 8: SUBSEQUENT EVENTS

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 approximately $120 million aggregate par value. Both issues will be 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 will be entitled to receive an amount equal to all accumulated and unpaid dividends on such shares to and including May 31, 2005.

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

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility 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. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

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 Report on Form 10-K, or 2004 Annual Report, filed with the Securities and Exchange Commission, or SEC.

The Utility served approximately ~~4.9~~5.0 million electricity distribution customers and approximately 4.1 million natural gas distribution customers at ~~September 30, 2004.~~March 31, 2005. The Utility had approximately $34.1 billion in assets at ~~September 30, 2004~~March 31, 2005 and generated revenues of approximately ~~$8.1~~$2.7 billion in the ~~nine~~three months ended ~~September 30, 2004. The Utility's~~March 31, 2005. Its revenues are generated mainly through the sale and delivery of electricity and natural ~~gas.~~gas at regulated rates. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

~~On April 12, 2004,~~During the ~~Utility's plan of reorganization under Chapter 11 of the U.S Bankruptcy Code, or Plan of Reorganization, became effective. Upon the effective date,~~first quarter 2005, the Utility ~~paid all valid claims, deposited funds into escrow accounts for~~continued to build momentum to implement its strategy to achieve cost and operating efficiencies and operational excellence. The Utility is in the ~~payment~~process of ~~disputed claims upon resolution, reinstated certain obligations,~~identifying specific initiatives to provide better, faster and ~~paid other obligations. In March 2004,~~more cost-effective service to its customers and invest the savings in ~~anticipation~~the business.

Factors Affecting First Quarter 2005 Results of ~~its emergence from Chapter 11,~~Operation and Financial Condition

During the Utility issued $6.7 billion in First Mortgage Bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, obtained $2.9 billion in credit facilities, in order to finance the Plan of Reorganization.

Appeals of the bankruptcy court's December 22, 2003 order confirming the Plan of Reorganization remain pending. Petitions seeking review of (1) the CPUC's December 18, 2003 order approving the December 19, 2003 settlement agreement reached amongfirst quarter 2005, several factors had a significant impact on PG&E Corporation, the Utility and the CPUC to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement and (2) the CPUC's March 19, 2004 order denying rehearing of its earlier order, also remain pending. PG&E Corporation and the Utility believe these appeals and petitions are without merit. Under applicable federal precedent, once the Plan of Reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E CorporationCorporation's and the Utility's ~~fi nancial condition and~~ results of ~~operations could be materially adversely affected. See Note 2~~operation and financial condition, including:

·	The issuance of approximately $1.9 billion of Energy Recovery Bonds, or ERBs, as described below;
·	Achievement of a 52% equity ratio on which the Utility is entitled to earn its authorized return;
·	The reinstatement of quarterly dividends, repayment of debt, and the repurchase of common stock; and
·	Upgraded credit ratings.

Issuance of ~~the Notes to the Condensed Consolidated Financial Statements for more information about the Utility's Chapter 11 proceedings.~~Energy Recovery Bonds

PG&E Corporation also owned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engages in electricity generation and natural gas transportation in the United States, or the U.S.~~As described below, PG&E Corporation considers~~ ~~its investment in NEGT to be an abandoned asset and~~ accounted for NEGT as discontinued operations in accordance with Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT and its subsidiaries through July 7, 2003 and for all prior periods are reported as discontinued operations in the Consolidated Statements of Operations.~~Effective July 8, 2003 , PG&E Corporation accounted for NEGT using the cost method and NEGT is no longer consolidated by PG&E Corporation for financial reporting purposes~~.

~~On October 29, 2004 NEGT's~~The Utility's plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, ~~became effective. In accordance with~~incorporated the ~~plan~~terms of ~~reorganization, PG&E Corporation's equity ownership in NEGT was cancelled. The accounting impacts of this~~the Settlement Agreement approved by the CPUC on December 18, 2003, and entered into among the ~~effect of a settlement agreement resolving certain tax litigation between~~CPUC, the Utility, and PG&E Corporation ~~and NEGT, among others, is discussed below.~~

~~PG&E Corporation's and~~on December 19, 2003, to resolve the Utility's ~~results of operations and financial condition since implementation of the Utility's Plan of Reorganization have been, and will continue to be, affected by the following factors, among others:~~

·	~~The financial impacts of the Settlement Agreement and the financial impacts of the refinancing of the $2.2 billion, after-tax, regulatory asset provided under the Settlement Agreement;~~
·	~~The return to cost of service ratemaking; and~~
·	~~The financial and ratemaking impacts of various regulatory decisions, including those that implement settlements reached with various constituencies.~~

In addition to these factors, future results of operations and financial condition will be affected by the terms under which the Utility and the other California investor-owned utilities will be required to invest in long-term electricity resources, transmission and distribution facilities, and the extent to which the Utility will be provided an opportunity to earn a return on such investments.

~~As discussed below, PG&E Corporation's fourth quarter 2004 results also will be affected by the cancellation of PG&E Corporation's equity interest in NEGT in connection with NEGT's~~ Chapter 11 ~~plan of reorganization.~~

As discussed below in "Liquidity and Financial Resource Matters," PG&E Corporation has adopted an initial annual cash dividend target of $1.20 per share ($0.30 quarterly) for 2005, subject to actual declaration by the Board of Directors. PG&E Corporation anticipates distributing up to $1.75 billion to shareholders by the end of 2005 through dividends and stock repurchases.

~~Other factors are discussed below under "Forward Looking Statements and Risk Factors."~~

~~Regulatory Assets Provided Under Settlement Agreement~~

~~The Settlement Agreement authorized the Utility to establish a $2.2 billion, after-tax, regulatory asset ($3.7 billion, pre-tax),~~proceeding, or the Settlement Regulatory Asset, to be amortized on a "mortgage-style" basis over nine years beginning January 1, 2004. The Settlement Agreement also permitted the Utility to establish a $0.7 billion, after-tax, regulatory asset ($1.2 billion, pre-tax), for the Utility's retained generation assets.Agreement. In the first quarter of 2004, the Utility recorded approximately $4.9 billion for these regulatory assets and a related after-tax gain on recognition of these regulatory assets of approximately $2.9 billion.

The after-tax amount of the Settlement Regulatory Asset is subject to reduction for any refunds, claim offsets or other credits the Utility receives from energy suppliers relating to specified electricity procurement costs incurred during the California energy crisis. As of September 30, 2004, the Utility has recorded after-tax offsets to the Settlement Regulatory Asset totaling approximately $180 million from supplier settlements.

The Settlement Agreement provides that the unamortized balance of the Settlement Regulatory Asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term and, after the equity component of the Utility's capital structure reaches 52%, the authorized equity component of the Settlement Regulatory Asset will be no less than 52% for the remaining term. The Utility's retained generation regulatory assets will earn an authorized rate of return on its equity component of 11.22% in 2004 (See note 2 of the Notes to the Consolidated Financial Statements for further information).

~~Refinancing Supported by a Dedicated Rate Component~~

~~Under~~connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the $2.2 billion, after-tax ($3.7 billion, pre-tax) regulatory asset provided under the Settlement Agreement, or the Settlement Regulatory Asset, and related federal income and state ~~and~~ franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component provided that certain conditions are met. In June 2004, the California Governor signed into law Senate Bill 772, which authorizes the issuance of Energy Recovery Bonds, or ERBs, to be secured by the establishment of a dedicated rate component to refinance the Settlement Regulatory Asset and related taxes. In addition to the authorizing legislation, the following other conditions must be met before a refinancing can occur:

·	~~The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the Settlement Regulatory Asset;~~
·	~~The refinancing will not adversely affect the Utility's issuer or debt credit ratings; and~~
·	The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or the IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

On ~~October 19, 2004,~~February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company that is wholly owned and consolidated by the ~~CPUC~~Utility (but legally separate from the Utility), issued ~~a proposed decision authorizing~~approximately $1.9 billion of ERBs. The Utility, as servicer, collects and remits DRC charges to PERF to enable PERF to pay the ~~issuance~~principal and interest on the ERBs. The proceeds of the ERBs ~~subject to the approval of transaction terms~~were used by a financing team comprised of CPUC staff and their outside advisors. The CPUC used a similar financing team approach to approve the terms of the Utility's bankruptcy exit financing. Comments on the draft decision are due on November 8, and the Utility ~~expects that~~to refinance the ~~CPUC will issue a final decision by Nove mber 19, 2004. Assuming the timely satisfaction of these~~ remaining ~~conditions, the issuance of the first series of ERBs, in the amount of the~~unamortized after-tax balance of the Settlement Regulatory Asset ~~(estimated~~as follows:

·	The repayment of $300 million borrowed by the Utility in December 2004, in anticipation of the receipt of ERB proceeds, under the Utility's $850 million working capital facility to partially redeem Floating Rate First Mortgage Bonds on January 3, 2005 in the aggregate principal amount of $300 million;
·	The defeasance of $600 million of Floating Rate First Mortgage Bonds on February 24, 2005 followed by a redemption of the defeased bonds on April 3, 2005; and
·	The repurchase of 22,023,283 shares of the Utility's common stock at $43.59 per share from PG&E Corporation for an aggregate purchase price of $960 million.

Under the Settlement Agreement, the Utility is authorized to ~~be approximately $1.8 billion), is targeted to occur in January 2005.~~

~~After~~earn a rate of return on equity, or ROE, of no less than 11.22% per year on the ~~first series~~equity component of ~~ERBs are issued, the after-tax balance of~~its rate base, including the Settlement Regulatory Asset. The Settlement Regulatory Asset ~~would~~was eliminated from rate base when it was refinanced with the proceeds of the issuance of the ERBs. Therefore the Utility no longer ~~be a component of rate base and the Utility's revenue and earnings would be reduced accordingly. The Utility would no longer earn the~~earns an 11.22% ~~return on equity~~ROE on the Settlement Regulatory Asset.~~The Utility would recover the principal and interest related to the ERBs from ratepayers through the dedicated rate component.~~ As a result, the Utility's first quarter 2005 net income was reduced by approximately $18 million, compared to the same period in 2004, when the Utility earned the 11.22% ROE on the Settlement Regulatory Asset. Net income for 2005 is estimated to be reduced by approximately $100 million, compared to 2004, due to the elimination of the ~~expected lower financing costs,~~11.22% ROE on the ~~first series of ERBs are expected to create cumulative nominal savings for ratepayers of approximately $700 million.~~Settlement Regulatory Asset.

~~After the Utility reaches its target capital structure of 52%, it is anticipated that it would use surplus cash including~~The proceeds of the securitization to pay dividends to, or repurchase common stock from, PG&E Corporation, which PG&E Corporation would use in turn to pay dividends to, or repurchase stock from, its shareholders. If the securitization occurs in January 2005, it is expected that the Utility would almost immediately achieve its 52% equity ratio target, thereby enabling PG&E Corporation to pay dividends and repurchase stock in the first half of 2005, as discussed below under "Liquidity and Financial Resources."

~~The~~ second series of ERBs, ~~would~~anticipated to be issued in November 2005 in an aggregate amount of up to ~~refinance~~$1.1 billion, will be paid by PERF to the Utility to pre-fund the Utility's recovery through rates of the tax payments ~~associated with~~that will be due as the ~~principal payments on~~Utility collects the DRC over the term of the first series of ~~ERBs. After~~ERBs to pay principal. Until taxes are fully paid, the Utility will compensate customers, computed at the Utility's authorized rate of return on rate base, for the use of the proceeds. It is estimated that this carrying cost credit associated with the second series of ERBs would be approximately $60 million (based on an approximate aggregate amount of $1 billion) for the first full year that the second series of ERBs is ~~issued,~~outstanding. The actual amount will depend on the principal amount of the second series of ERBs. 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.

Achievement of 52% Equity Ratio

The Settlement Agreement provides that the CPUC will set the Utility's ~~revenue~~capital structure and ~~earnings would~~authorized ROE in the Utility's annual cost of capital proceedings in its usual manner; provided that, the authorized ROE shall not be ~~reduced through a reduction in revenue requirements creating cumulative nominal savings~~less than 11.22% per year and the authorized equity ratio for ~~ratepayers of approximately $300 million. These savings compensate ratepayers for~~ratemaking purposes shall not be less than 52%. In January 2005, the ~~time value of money between the time~~equity component of the Utility's ~~receipt~~capital structure grew to 52%, as compared to about 48% during the first quarter of ~~bond proceeds and when taxes are actually paid, net of interest charges. This credit would decline each year as taxes are paid.~~

~~Transition from Frozen Rates to Cost of Service Ratemaking~~

Beginning January 1, 1998, electricity rates were frozen as required by the California electric industry restructuring law. In response to the California energy crisis, the CPUC increased frozen rates through the imposition of surcharges. Although changes in the Utility's authorized revenue requirements did not impact the revenues received by the Utility under this frozen rate structure, the revenue requirements of the California Department of Water Resources, or DWR, to meet its obligations under its long-term electricity procurement contracts did reduce the Utility's revenues. In January 2004, the CPUC determined that the rate freeze ended on January 18, 2001 and in February 2004 the CPUC approved a rate design settlement to implement an annual electricity rate reduction of approximately $799 million to begin on January 1, 2004.

As a result, the Utility's equity earnings in the three months ended March 31, 2005, increased by approximately $14 million compared to the same period in 2004.

Under the Settlement Agreement, the Utility is entitled to earn a ROE of 11.22% on an authorized 52% equity ratio until the Utility's long-term issuer credit ratings are at least A- from Standard & Poor's Ratings Services (S&P) or A3 from Moody's Investors Service (Moody's). As described below, on February 16, 2005, S&P announced that it had upgraded its corporate credit rating on the Utility to BBB from BBB- and on March 3, 2005, Moody's announced that it had upgraded the Utility's issuer credit rating to Baa1 from Baa3.

The currently authorized ROE of 11.22% will be in effect until the Utility's 2006 cost of capital application is approved by the CPUC. The Utility plans to file its 2006 cost of capital application with the CPUC on May 9, 2005 for its electric utility generation and distribution operations and gas distribution operations.

Stock Repurchases and Dividends

With the achievement of a 52% equity ratio, the Utility reinstated the payment of a regular quarterly dividend. In addition, during the three months ended March 31, 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 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.

On March 4, 2005, PG&E Corporation entered into a new accelerated share repurchase arrangement with Goldman Sachs & Co., or GS&Co, under which PG&E Corporation repurchased 29,489,400 shares of its common stock for an aggregate amount of approximately $1.05 billion, subject to a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement. The repurchase of common stock under this agreement, increased both basic and diluted earnings per share by approximately $0.01 for the three months ended March 31, 2005 and partially offset the negative earnings impact of the refinancing of the Settlement ~~Agreement~~Regulatory Asset as described above.

Weighted average shares outstanding for basic and ~~these CPUC decisions,~~diluted earnings per share for the three months ended March 31, 2005 reflect the March 4, 2005 retirement of shares repurchased under the accelerated share repurchase arrangement. At March 31, 2005, PG&E Corporation does not have any obligation to GS&Co. related to the price adjustment or any additional payments. Accordingly, no additional shares attributable to the accelerated share repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings per share (see "Liquidity and Financial Resources" below).

Credit Rating Upgrades

On February 16, 2005, S&P announced that it had upgraded the Utility's rates are now determined based on its costs of service. Electric rates reflect the sum of individual revenue requirement components, including base revenue requirements set by the 2003 General Rate Case, or GRC, described below, revenue requirements for the regulatory assets (including an 11.22% return), provided under the Settlement Agreement, electricity procurement costs, and the DWR's requirement, among others. Changes in any individual revenue requirement will change customers' electricity rates andcorporate credit rating to BBB from BBB-. On March 3, 2005, Moody's announced that it had upgraded the Utility's ~~revenues.~~issuer credit rating to Baa1 from Baa3 and upgraded its rating on the Utility's outstanding preferred stock to Baa3 from Ba2. Moody's also assigned a Baa3 issuer rating to PG&E Corporation and a rating of Baa3 to PG&E Corporation's $200 million unsecured bank revolving credit facility.

On ~~October 15, 2004,~~April 22, 2005, the ~~Utility filed its first annual electric true-up advice letter with~~lien of the CPUC to provide the CPUC information about expected electric rate changes to occur on January 1, 2005. On or before December 31, 2004, the Utility expects to file a supplemental advice letter to reflect November 30, 2004 account balances and any rate changes resulting from proceedings and advice letters that have then been resolved. It is expected that these rate changes would result in an increase in 2005 electric revenues of approximately $315 million.

~~Approval of 2003 General Rate Case~~

~~On May 27, 2004, the CPUC issued a decision in~~mortgage securing the Utility's ~~2003 GRC to determine~~First Mortgage Bonds was released after satisfaction of several conditions, and following confirmation from S&P and Moody's that the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 and certain succeeding years. The decision approves the July 2003 and September 2003 settlement agreements reached among the Utility and various consumer groups, including the minimum and maximum yearly increases in revenue requirements, known as attrition adjustments, as discussed below under "Regulatory Matters."

As a result of the GRC decision, during the second quarter the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of unfunded taxes, depreciation, and decommissioning. The net impact of the items recorded in the second quarter, on a pre-tax basis, was approximately $432 million. During the third quarter of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC.

~~Electricity Procurement Costs and Long-Term Electricity Resource Plan~~

On July 9, 2004, the Utility submitted its long-term integrated energy resource plan, or LTP, for the 2005 through 2014 period to the CPUC in compliance with CPUC decisions and orders regarding electric resource planning. The LTP sets forth the policy framework, strategies and implementation steps for meeting customer electricity demand, or load for the next 10 years to ensure that adequate, reliable, and reasonably priced electrical power and natural gas are provided in a cost-effective and environmentally sound manner. The Utility's target over the 10-year planning horizon is to own 50% of the new generation resources to be developed, with the remaining 50% of such resources to be purchased under long-term contracts. Since there is great uncertainty regarding the extent to which the Utility's residential and small commercial customers, or core customers, and its large commercial and industrial customers, or non-core customers, may be authorized in the future to procure electricity from non-utility load serving entities (such as local publicly owned electric utilities, community choice aggregators or energy service providers, collectivelyFirst Mortgage Bonds (now referred to as ~~LSE's),~~Senior Notes) would have unsecured long-term debt ratings of BBB by S&P and Baa1 by Moody's after the Utility has requested that the CPUC take certain steps to minimize the risk that the Utility will be unable to recover the investment in long-term resource commitments that it expects it will be required to make. The Utility has requested that the CPUC approve its LTP by December 2004 and authorize the Utility to enter into long-term resource commitments in the second quarter of 2005. The LTP is discussed further under "Electricity Resources" in the Regulatory Matters discussion below.lien was released.

Forward-Looking Statements ~~and Risk Factors~~

This combined Quarterly Report on Form 10-Q, including ~~this~~the Management's Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, contains forward-looking statements ~~including statements about targeted levels of dividends and stock repurchases,~~ that are necessarily subject to various risks and ~~uncertainties.~~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 ~~which management believes are reasonable~~regarding these events and ~~on information currently available to management.~~management's knowledge of facts at the time the statements were made. These forward-looking statements are identified by words such as ~~"estimates,~~"assume," ~~"expects,~~"expect," ~~"anticipates,~~"intend," ~~"plans,~~"plan," ~~"believes,~~"project," ~~"could,~~"believe," "estimate," "predict," "anticipate," "may," "might," "will," "should," "would," ~~"may,~~"could," "goal," "potential" and ~~other~~ similar expressions. ~~Actual results could differ materially from those contemplated by the forward-looking statements.~~

Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of ~~the~~th e factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

~~Whether the Implementation~~Appeals of the Utility's Plan of Reorganization ~~Is Disrupted~~and Settlement Agreement

·	The timing and resolution of the petitions for review that were filed in the California Court of Appeal for the First Appellate District, seeking review of the CPUC's ~~December 18, 2003 decision approving~~approval of the Settlement ~~Agreement and the CPUC's March 16, 2004 denial of applications for rehearing of the December 18, 2003 decision;~~Agreement; and
·	The timing and resolution of the pending appeals of the ~~bankruptcy court's order confirming the Plan of Reorganization.~~confirmation order.

Operating Environment

·	Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility's ability to earn its authorized rate of return;
·	The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility's ability to manage and respond to the levels and volatility successfully and the extent to which the Utility is able to timely recover increased costs related to such volatility;
·	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;~~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 the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive ~~sources;~~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 and Regulatory Environment and Pending Litigation

·	The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;
·	Whether the ~~conditions~~assumptions and forecasts underlying the Utility's CPUC-approved long-term electricity procurement plan prove to ~~securitizing~~be accurate, the ~~$2.2 billion after-tax regulatory asset established under the Settlement Agreement are met~~terms and ~~if so, the timing and amount~~conditions of the ~~securitization;~~
·	~~The~~generation or procurement commitments the Utility enters into in connection with its plan, the extent to which the Utility is able to recover ~~its~~the costs ~~incurred~~it incurs in ~~meeting its obligation~~connection with these commitments and the extent to ~~supply electricity~~which a failure to ~~customers, whether costs are incurred~~perform by any of the counterparties to ~~meet or manage the Utility's residual net open position (~~~~i.e~~~~., that portion of~~ the Utility's electricity ~~customers' demand not satisfied by electricity that~~purchase contracts or the ~~Utility generates~~California Department of Water Resources, or ~~has under contract, or by electricity provided under the~~ DWR, ~~electricity~~ contracts allocated to the Utility's ~~customers)~~customers affects the Utility's ability to meet its obligations or to ~~ensure adequate resources as required by the CPUC;~~
·	Whether the CPUC approves the Utility's long-term electricity resource plan and adopts the Utility's related ratemaking proposals, whether the assumptions and forecasts underlying the long-term resource plan prove to be accurate, and the terms and conditions of the long-term resource commitments the Utility enters into in connection withrecover its ~~long-term resource plan;~~costs;
·	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;
·	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 ~~in particular~~ the extent to which the ~~conditions adopted by the CPUC, such as those contained in the CPUC's general financing authorization decision issued on October 28, 2004 (under which the Utility is authorized to issue debt~~terms and ~~preferred stock in the future within certain amounts and for specific purposes)~~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;
·	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; and
·	The outcome of pending litigation.

Competition and Bypass

Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or ~~services~~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 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.

~~NEGT~~

~~Effective July 8, 2003 (the date NEGT filed a voluntary petition~~ See the section entitled "Risk Factors" in PG&E Corporation's and the Utility's combined 2004 Annual Report for relief under Chapter 11), NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under accounting principles generally accepted in the United States of America, or GAAP, consolidation is generally required for entities owning more than 50%further discussion of the ~~outstanding voting stock~~more significant risks that could affect the outcome of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corpor ation no longer retained significant influence over the ongoing operations of NEGT.

Accordingly, PG&E Corporation's negative investment in NEGT of approximately $1.2 billion is reflected as a single amount, under the cost method, within the September 30, 2004 Consolidated Balance Sheets of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. Furthermore, at September 30, 2004 the Consolidated Balance Sheet includes a net deferred tax asset of approximately $432 million, a current tax liability of approximately $145 million, other net liabilities of approximately $28 million and a charge of approximately $77 million, net of tax, in accumulated other comprehensive income, related to NEGT.

~~On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11~~these forward-looking statements and PG&E Corporation's ~~equity ownership in NEGT was cancelled. On~~and the ~~effective date, PG&E Corporation reversed its negative investment in NEGT~~Utility's future results of operations and also reversed NEGT-related deferred income tax assets and accumulated other comprehensiveincome. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation (See Note 6 of the Notes to the Consolidated Financial Statements). A summary of the approximate effect on earnings from discontinued operations is as follows:

~~(in millions)~~
~~Investment in NEGT~~	$	~~1,211~~
~~Accumulated other comprehensive income~~	~~(120)~~
~~Cash paid pursuant to settlement of tax related litigation~~	~~(30)~~
~~Tax Effect~~	~~(381)~~

~~Gain on disposal of NEGT, net of tax~~	$	~~680~~

financial condition.

Subsequent to the cancellation of its equity interest, at October 29, 2004, PG&E Corporation's Consolidated Balance Sheet includes $166 million in income tax and other net liabilities related to NEGT. Beginning on the effective date of NEGT's plan of reorganization, PG&E Corporation no longer will include NEGT or its subsidiaries in its consolidated income tax returns.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Consolidated Statements of ~~Operations~~Income for the ~~three~~three-month period ended March 31, 2005 and ~~nine-month periods ended September 30, 2004, and 2003.~~

2004.

													Three Months Ended
		Three Months Ended September 30,				Nine Months Ended September 30,							March 31,

(in millions)	(in millions)	2004			2003		2004			2003	(in millions)		2005		2004


Utility	Utility										Utility
Electric operating revenues	Electric operating revenues	$	2,042	$	2,509	$	5,902	$		5,921	Electric operating revenues		$	1,660	$	1,791
Natural gas operating revenues	Natural gas operating revenues		581		553		2,198		2,040		Natural gas operating revenues			1,009	931

Total operating revenues											Total operating revenues			2,669	2,722
Cost of electricity	Cost of electricity		792		661		2,003		1,823		Cost of electricity			396	561
Cost of natural gas	Cost of natural gas		239		234		1,096		1,040		Cost of natural gas			620	578
Operating and maintenance	Operating and maintenance		671		657		2,271		2,098		Operating and maintenance			773	808
Recognition of regulatory assets	Recognition of regulatory assets		-		-		(4,900)		-		Recognition of regulatory assets			-	(4,900)
Depreciation, amortization and decommissioning	Depreciation, amortization and decommissioning		405		311		1,054		916		Depreciation, amortization and decommissioning			385	311
Reorganization professional fees and expenses	Reorganization professional fees and expenses		-		16		6		116		Reorganization professional fees and expenses			-	2

Total operating (gain) expenses											Total operating (gain) expenses			2,174	(2,640)

Operating income	Operating income		516		1,183		6,570		1,968		Operating income			495	5,362
Interest income			11		11		44		42
Interest income⁽¹⁾											Interest income⁽¹⁾			20	11
Interest expense	Interest expense		(141)		(237)		(512)		(681)		Interest expense			(154)	(213)
Other income, net⁽¹⁾			10		9		26		23
Other income, net⁽²⁾											Other income, net⁽²⁾			-	5

Income before income taxes	Income before income taxes		396		966		6,128		1,352		Income before income taxes			361	5,165
Income tax provision	Income tax provision		152		383		2,410		508		Income tax provision			142	2,099

Income before cumulative effect of a change in accounting principle			244		583		3,718		844
Cumulative effect of a change in accounting principle			-		-		-		(1)

Income available for common stock	Income available for common stock	$	244	$	583	$	3,718		$	843	Income available for common stock		$	219	$	3,066

PG&E Corporation, Eliminations and Other⁽²⁾⁽³⁾

PG&E Corporation, Eliminations and Other⁽³⁾											PG&E Corporation, Eliminations and Other⁽³⁾
Operating revenues	Operating revenues	$	-	$	-	$	-		$	(3)	Operating revenues		$	-	$	-
Operating expenses	Operating expenses		7		22		28		(30)		Operating expenses			(6)	9

Operating income			(7)		(22)		(28)		27
Operating income (loss)											Operating income (loss)			6	(9)
Interest income	Interest income		4		4		10		7		Interest income			1	3
Interest expense	Interest expense		(18)		(105)		(53)		(176)		Interest expense			(7)	(18)
Other income (expense), net⁽¹⁾			(6)		(2)		(72)		(2)
Other income (expense), net⁽²⁾											Other income (expense), net⁽²⁾			(1)	(32)

Loss before income taxes			(27)		(125)		(143)		(144)
Income tax provision (benefit)			(11)		(50)		(58)		(54)

Loss from continuing operations			(16)		(75)		(85)		(90)
Discontinued operations			-		2		-			(365)
Cumulative effect of changes in accounting principles			-		-		-			(5)
Income (loss) before income taxes											Income (loss) before income taxes			(1)	(56)
Income tax benefit											Income tax benefit			-	(23)

Net loss	Net loss	$	(16)	$	(73)	$	(85)		$	(460)	Net loss		$	(1)	$	(33)

Consolidated Total⁽³⁾

Consolidated Total											Consolidated Total
Operating revenues	Operating revenues	$	2,623	$	3,062	$	8,100		$	7,958	Operating revenues		$	2,669	$	2,722
Operating expenses (gain)			2,114		1,901		1,558		5,963
Operating (gain) expenses											Operating (gain) expenses			2,168	(2,631)

Operating income	Operating income		509		1,161		6,542		1,995		Operating income			501	5,353
Interest income			15		15		54		49
Interest income⁽¹⁾											Interest income⁽¹⁾			21	14
Interest expense	Interest expense		(159)		(342)		(565)		(857)		Interest expense			(161)	(231)
Other income (expenses), net⁽¹⁾			4		7		(46)		21
Other expenses, net⁽²⁾											Other expenses, net⁽²⁾			(1)	(27)

Income before income taxes	Income before income taxes		369		841		5,985		1,208		Income before income taxes			360	5,109
Income tax provision	Income tax provision		141		333		2,352		454		Income tax provision			142	2,076

Income from continuing operations			228		508		3,633		754
Discontinued operations			-		2		-			(365)
Cumulative effect of changes in accounting principles			-		-		-			(6)

Net income (loss)		$	228	$	510	$	3,633		$	383
Net income											Net income		$	218	$	3,033

(2)


(1)	Includes preferred dividend requirement as other expense.										Includes reorganization interest income.
(2)	PG&E Corporation eliminates all intersegment transactions in consolidation.										(2)	Includes preferred dividend requirement as other expense.
(3)	Operating results of NEGT have been reclassified as discontinued operations. See Note 4 of the Notes to the Consolidated Financial Statements.										PG&E Corporation eliminates all intercompany transactions in consolidation.

Utility

~~As discussed above under "Overview," as~~Under cost of ~~January 1, 2004, the Utility no longer collects frozen electricity rates. Instead~~service ratemaking, the Utility's ~~electric~~ rates are ~~designed to fully recover the Utility's~~determined based on its costs of service ~~including electricity procurement costs.~~

~~California legislation has been enacted which allows the Utility~~and are adjusted periodically to recover all its prospective wholesale electricity procurement costs and requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs. Accordingly, with the implementation of new CPUC-approved electricity balancing accounts in 2004, electricity procurement costs and items such asreflect changes in sales ~~volumes~~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. 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 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 Management's Discussion and Analysis). 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 ~~expected to have the same impact on~~included in the Utility's ~~results~~Consolidated Statements of ~~operations that they had during the California energy crisis when rates were frozen. The level of~~Operations, reflecting the Utility's ~~electricity procurement costs will continue~~role as a billing and collection agent for the DWR's sales to ~~have an impact on cash flows. In addition, a significant outage at any of~~ the Utility's ~~operating facilities may have a material impact on the Utility's results of operations.~~

The following presents the Utility's operating results for the three and nine-month periods ended September 30, 2004 and 2003. Net income for the first quarter of 2004 reflects a one-time non-cash gain of approximately $2.9 billion, after-tax, due to the recognition of regulatory assets provided under the Settlement Agreement.customers.

Electric Operating Revenues

The ~~following table shows a breakdown of the Utility's electric revenue by customer class:~~

Three Months Ended
September 30,
Nine Months Ended
September 30,
(in millions)
2004

2003

2004

2003
Electric revenues
$
2,909

$
2,771

$
7,218

$
7,134
DWR pass-through revenue
(560)

(291)

(1,479)

(1,642)
Subtotal
2,349

2,480

5,739

5,492
Miscellaneous
(307)

29

163

429
Total electric operating revenues
$
2,042

$
2,509

$
5,902

$
5,921

~~As a result of the return to cost-of-service ratemaking in 2004, the~~ Utility records its electric distribution and generation revenues under cost-of-service revenue requirements approved by the CPUC in the Utility's 2003 General Rate Case, or GRC. Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts ~~which is~~and are reflected in ~~Miscellaneous~~miscellaneous revenues ~~above.~~in the table below.

~~For~~The Utility is required to dispatch, or schedule, all of the ~~three months ended September 30, 2004,~~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 a breakdown of the Utility's electric operating revenues.

		Three Months Ended
		March 31,

(in millions)		2005		2004


Electric revenues		$	2,084	$	2,169
DWR pass-through revenue		(446)		(470)

Subtotal		1,638		1,699
Miscellaneous		22		92

Total electric operating revenues		$	1,660	$	1,791



Total electricity sales (in Gwh)⁽¹⁾			19,034		18,870




(1)	Includes DWR electricity sales.

The Utility's electric operating revenues decreased during the three months ended March 31, 2005, by approximately ~~$467~~$131 million, or ~~19%~~7%, compared to the same period in ~~2003 mainly due to~~2004, primarily as a result of the following factors:

Electric revenues decreased approximately $175 million during the three months ended March 31, 2005, as ~~a result of~~compared to the ~~collection of surcharge revenues~~same period in ~~the third quarter of 2003. Prior~~2004 due to 2004, the Utility's electric rates were frozen as required by the California electric industry restructuring law. In the third quarter of 2003, the Utility collected approximately $834 million of surcharge revenues under the frozen rate structure, including amountslower electricity procurement and transmission costs which are passed through to ~~DWR for power purchased by DWR on behalf of the Utility's customers. Starting in January 2004, the Utility's rates are determined based on its cost of service;~~customers; and

Electric operating revenues decreased $76 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:

·	The Utility is authorized to collect and remit a DRC from its electricity customers to repay the ERBs until they are fully retired. This ~~decrease was partially offset by~~DRC charge resulted in an approximately $23 million electric operating revenue increase in ~~electric revenues of approximately $100 million due to~~ the three months ended March 31, 2005, with no similar amount in the same period in 2004; and
·	The approval of the Utility's 2003 GRC in ~~2004. The 2003 GRC determines~~May 2004 and the ~~amount~~final decision in the ~~Utility can collect from its customers, or base revenue requirements (see the "Regulatory Matters" section~~2005 cost of ~~this MD&A);~~
·	~~The Settlement Agreement established a $2.2 billion, after-tax, regulatory asset (which is equivalent to~~capital proceeding in December 2004 resulted in an increase of approximately $3.7 billion, pre-tax, regulatory asset) as a new, separate and additional part of the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004 (see further discussion$105 million in ~~Note 2 of the Notes to the Consolidated Financial Statements). As a result of the revenue requirement associated with the Settlement Agreement, the Utility's~~ electric operating revenues ~~increased by approximately $120 million for~~in the three months ended ~~September 30, 2004~~March 31, 2005, as compared to the same period in ~~2003; and~~
·	The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement, transmission, and miscellaneous other electric revenues.2004.

For the nine months ended September 30, 2004, the Utility's electric operating revenues decreased approximately $19 million, or less than 1%, compared to the same period in 2003 due to the following factors:

·	Electric revenues decreased as a result of the collection of surcharge revenues in the nine-month period ended September 30, 2004. Prior to 2004, the Utility's electric rates were frozen as required by the California electric industry restructuring law. During the nine-month period ended September 30, 2003, the Utility collected approximately $1.1 billion of surcharge revenues under the frozen rate structure, including amounts passed through to the DWR for power purchased by the DWR on behalf of the Utility's customers. Starting in January 2004, the Utility's rates are determined based on its cost of service;
·	In addition, the Utility's electric revenues increased by approximately $305 million due to the approval of the Utility's 2003 GRC in 2004. The 2003 GRC determines the amount the Utility can collect from its customers, or base revenue requirements (see the "Regulatory Matters" section of this MD&A);
·	As previously discussed, the Settlement Agreement established a $2.2 billion, after-tax, regulatory asset as a new, separate and additional part of the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004 (see further discussion in Note 2 of the Notes to the Consolidated Financial Statements). As a result of the revenue requirement associated with the Settlement Agreement, the Utility's electric operating revenues increased by approximately $370 million for the nine months ended September 30, 2004 as compared to the same period in 2003; and
·	The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement, transmission, and miscellaneous other electric revenues.

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 it excludes costs to operate its owned generation ~~facilities.~~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 a breakdown 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
September 30,

Nine Months Ended
September 30,
(in millions)
2004

2003

2004

2003
Cost of purchased power
$
787

$
692

$
2,027

$
1,944
Proceeds from surplus sales allocated to the Utility
(35)

(63)

(133)

(197)
Fuel used in own generation
40

32

109

76
Total cost of electricity
$
792

$
661

$
2,003

$
1,823
Average cost of purchased power per kilowatt-hour
$
0.085
$
0.069
$
0.079
$
0.077
Total purchased power (gigawatt-hours)
9,310

9,983

25,589

25,220

	Three Months Ended
	March 31,

(in millions)	2005		2004


Cost of purchased power	$	452	$	582
Proceeds from surplus sales allocated to the Utility	(100)		(64)
Fuel used in own generation	44		43

Total net cost of electricity	$	396	$	561



Average cost of purchased power per kWh	$	0.065	$	0.083

Total purchased power (GWh)	6,985		6,997

~~The~~During the three months ended March 31, 2005, the Utility's cost of electricity ~~increased~~decreased approximately ~~$131~~$165 million, or ~~20%~~29%, ~~for the three months ended September 30, 2004, and approximately $180 million, or 10%, for the nine months ended September 30, 2004,~~ compared to ~~the same periods in 2003. Increases in the cost of electricity for both periods were~~2004, mainly due to ~~an increase in~~ the ~~total cost per kilowatt-hour, or kWh, of electricity purchased in 2004.~~following factors:

·	The decrease in the average cost of purchased power of $0.018 per kWh in 2005 as compared to 2004 resulted in a decrease of approximately $130 million in the cost of purchased power; and
·	The increase in proceeds from surplus sales allocated to the Utility of $36 million in the three months ended March 31, 2005, as compared to the same period in 2004 resulted in a corresponding decrease in the cost of electricity.

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 customers. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. The Utility provides natural gas delivery services to all core and noncore 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 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 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 a breakdown of the Utility's natural gas operating revenues:

Three Months Ended
September 30,

Nine Months Ended
September 30,
(in millions)
2004

2003

2004

2003
Bundled gas revenues
$
524

$
477

$
2,006

$
1,831
Transportation service-only revenues
57

76

192

209
Total natural gas operating revenues
$
581

$
553

$
2,198

$
2,040
Average bundled price of natural gas sold per Mcf
$
13.48
$
11.97
$
9.92
$
8.84
Total bundled gas sales (in millions Mcf)
39
40
202
207

	Three Months Ended
	March 31,

(in millions)	2005		2004


Bundled natural gas revenues	$	944	$	867
Transportation service-only revenues	65		64

Total natural gas operating revenues	$	1,009	$	931



Average bundled revenue per Mcf of natural gas sold	$	8.77	$	7.74

Total bundled natural gas sales (in millions of Mcf)		108		112

The Utility's natural gas operating revenues increased approximately ~~$28~~$78 million, or 5%8%, ~~for~~during the three months ended ~~September 30, 2004 and approximately $158 million, or 8%, for the nine months ended September 30, 2004,~~March 31, 2005, compared to the same ~~periods~~period in ~~2003. Increases~~2004. The increase in natural gas operating revenues ~~for both periods were~~was primarily ~~a result of the approval of the Utility's 2003 GRC in May 2004.~~

The approval of the GRC resulted in an increase in natural gas revenues of approximately $17 million and $104 million (consisting of a 2004 portion of $52 million and a 2003 portion of $52 million) for the three and nine-month periods ended September 30, 2004, respectively, as compareddue to the ~~same periods in 2003 (see the "Regulatory Matters" section of this MD&A).~~following factors:

Excluding the effect of the GRC decision discussed above, the average bundled price of natural gas sold increased $1.03 per thousand cubic feet, or Mcf, or 9%, for the three months ended September 30, 2004 and $0.58 per Mcf, or 7%, for the nine months ended September 30, 2004, in comparison to the same periods in 2003. The Utility is permitted by the CPUC to pass increases in the average

Bundled natural gas revenues (excluding the effects of the 2003 GRC decision discussed below) increased by approximately $57 million, or 7%, in the three months ended March 31, 2005, as compared to the same period in 2004, mainly resulting from a higher cost of natural gas which the Utility is permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per thousand cubic feet, or Mcf, of natural gas sold in 2005 (excluding the effects of the GRC decision) increased by approximately $0.85, or 11%, as compared to 2004; and

The approval of the 2003 GRC resulted in an increase to natural gas revenues of approximately $20 million in the three months ended March 31, 2005, as compared to the same period in 2004.

Cost of Natural Gas

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

Three Months Ended
September 30,

Nine Months Ended
September 30,
(in millions)
2004

2003

2004

2003
Cost of natural gas sold
$
209

$
205

$
999

$
942
Cost of gas transportation
30

29

97

98
Total Cost of Natural Gas
$
239

$
234

$
1,096

$
1,040
Average price of natural gas purchased per Mcf
$
5.36
$
5.13
$
4.95
$
4.55
Total natural gas purchased (in millions Mcf)
39
40
202
207

	Three Months Ended
	March 31,

(in millions)	2005		2004


Cost of natural gas sold	$	584	$	542
Cost of natural gas transportation	36		36

Total cost of natural gas	$	620	$	578



Average cost per Mcf of natural gas sold	$	5.41	$	4.84

Total natural gas sold (in millions of Mcf)		108		112

~~The increase in~~In the three months ended March 31, 2005, the Utility's total cost of natural gas ofincreased approximately $5$42 million, or 2%7%, ~~and $56 million, or 5%, for~~compared to the ~~three and nine-month periods ended September 30,~~same period in 2004 ~~was~~ primarily due to an increase in the average market price of natural gas ~~purchased.~~

~~The increase in the average market price of natural gas~~ purchased of ~~$0.23~~approximately $0.57 per Mcf, or 4%, in the three months ended September 30, 2004, resulted in a $9 million increase in the total cost of natural gas. This increase was offset by a decrease in sales volume of 1 million Mcf, or 3%, resulting in a $4 million decrease in the total cost of natural gas.Mcf.

The increase in the average market price of natural gas purchased of $0.40 per Mcf, or 9%, in the nine months ended September 30, 2004, resulted in a $80 million increase in the total cost of natural gas. This increase was offset by a decrease in sales volume of 5 million Mcf, or 2%, resulting in a $24 million decrease in the total cost of natural gas.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility's costs to operate and maintain its electricity and natural gas facilities, ~~maintenance expenses,~~ customer accounts and service expenses, public purpose program expenses, and administrative and general expenses.

During the three months ended ~~September 30, 2004,~~March 31, 2005, the Utility's operating and maintenance expenses ~~increased $14~~decreased by approximately $35 million, or 2%4%, 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 the first quarter of 2004 with no similar amounts for the same period in 2005;
·	Operating and maintenance expenses decreased approximately $10 million at Diablo Canyon in the three months ended March 31, 2005, as compared to the same period in 2004 reflecting the scheduled refueling outage in the first quarter of 2004 with no similar refueling outage in the same period in 2005;
·	Employee benefit plan-related expenses decreased approximately $20 million in the three months ended March 31, 2005, as compared to the same period in 2004, due to lower interest cost, higher than expected returns on trust assets and the impact of Diablo Canyon reapplying SFAS No. 71 in April 2004. Prior to the reapplication of SFAS No. 71, Diablo Canyon's expenses impacted net income; there was no similar impact in the three months ended March 31, 2005.
·	These decreases were partially offset by an increase of approximately $30 million in the three months ended March 31, 2005, as compared to the same period in 2004, for environmental matters resulting from reassessments of the estimated liability for various sites.

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 March 31, 2005, the Utility's depreciation, amortization and decommissioning expenses increased by approximately $74 million, or 24%, compared to the same period in 2004, primarily as a result of the amortization of the Settlement Regulatory Asset and Energy Recovery Bond Regulatory Asset and an increase in the Utility's plant assets.

Interest Income

In the three months ended March 31, 2005, interest income, including reorganization interest income, increased by approximately $9 million, or 82%, compared to the same period in 2004, primarily due to interest earned on the $1.7 billion disputed escrow cash account in the three months ended March 31, 2005, and higher average interest rates on the Utility's short-term investments in the three months ended March 31, 2005, compared to the same period in 2004. The Utility discontinued reporting in accordance with SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004. Prior to that date, the Utility reported reorganization interest income separately on its Consolidated Statements of Income. Reorganization interest 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 March 31, 2005, the Utility's interest expense decreased by approximately $59 million, or 28%, compared to the same period in 2004, mainly due to a lower average amount of outstanding debt and a lower weighted average interest rate during the three months ended March 31, 2005, as compared to the same period in 2003. This increase is primarily a result of increased expenses associated with customer incentive programs (which have associated increases in revenues), the recorded liability for legal matters, and the Utility's core gas firm storage charges. These increases were partially offset by a wage adjustment in the third quarter of 2003, with no similar amount in 2004.

During the nine months ended September 30, 2004, the Utility's operating and maintenance expenses increased $173 million, or 8%, as compared to the same period in 2003. This increase is primarily due to an increase in expenses related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and donation of land, expenses associated with customers incentive programs (which have associated increases in revenues), and the Utility's core gas firm storage charges. This increase is also a result of reductions to the estimated liability for environmental matters for the nine months ended September 30, 2003, with no similar reductions in 2004.

~~Interest Expense~~

The Utility's interest expense decreased approximately $96 million, or 41%, for the three months ended September 30, 2004, and approximately $169 million, or 25%, for the nine months ended September 30, 2004, compared to the same periods in 2003 due to a lower average amount of unpaid debt accruing interest and a lower weighted average interest rate on debt outstanding during 2004.

Income Tax Expense

~~The~~In thethree months ended March 31, 2005, the Utility's tax expense decreased approximately ~~$231 million,~~$2.0 billion, or ~~60%~~93%, ~~for the three months ended September 30, 2004~~ compared to the same period ~~in 2003,~~2004, mainly due to a decrease in pre-tax income of ~~approximately $570 million in 2004.~~

~~The Utility's tax expense increased approximately $1.9 billion, or 374%, as compared to the same period in 2003, mainly due to an increase in pre-tax income of~~ $4.8 billion for the ~~nine~~three months ended ~~September 30, 2004 as a~~March 31, 2005. This decrease is primarily the result of the recognition of regulatory assets associated with the Settlement Agreement asfor the first quarter of 2004, with no similar amount recognized in the same period in 2005. The effective tax rate for thethree months ended March 31, 2005, decreased by 1.7 percentage points compared to the same period in ~~2003.~~2004. This ~~increase was partially offset by~~decrease is due mainly to the ~~recognition~~effect of ~~tax~~ regulatory ~~assets established upon receipt~~treatment of ~~the Utility's 2003 GRC decision.~~

depreciation differences and state income taxes.

PG&E Corporation, Eliminations and Others

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 affiliates. These allocations are made without mark-up. Operating expenses allocated to affiliates are eliminated in consolidation.

In the three-month period ended September 30, 2004. PG&E Corporation's operating expenses decreased by approximately $15 million for the three-month and increased by approximately $58 million for the nine-month periods ending September 30, 2004, compared to the same periods in 2003. The decrease in operating expenses ~~for the three-month period~~of approximately $15 million was primarily due to ~~lower external~~the receipt of insurance proceeds for legal ~~fees~~costs and ~~other~~a reduction in general and administrative expenses ~~related to NEGT's Chapter 11 proceeding. The increase~~retained at PG&E Corporation in ~~operating expenses for~~ the ~~nine-month period was primarily due to increased external legal fees and other expenses related~~first quarter 2005, compared to the ~~NEGT's and Utility's Chapter 11 proceedings, and other administrative expenses~~same period in 2004.

Interest Expense

PG&E Corporation's interest expense is not allocated to its affiliates. In the ~~three-month period~~three months ended ~~September 30, 2004,~~March 31, 2005, PG&E Corporation's interest expense decreased by approximately ~~$87~~$11 million, or ~~83%~~61%, compared to the same period in ~~2003. For~~2004, due to a reduction in the ~~nine-month period ended September 30,~~amount of outstanding debt. During the first quarter 2004, PG&E Corporation incurred $11 million in interest expense related to its $600 million of 6⅞% Senior Secured Notes due 2008, which were redeemed on November 15, 2004. Interest expense in the first quarter 2005 was primarily due to PG&E Corporation's ~~interest~~$280 million of 9.50% Convertible Subordinated Notes due 2010, or Convertible Subordinated Notes.

Other Income (Expense)

PG&E Corporation's other expense decreased by approximately ~~$123~~$31 million, or ~~70%~~97%, in the three months ended March 31, 2005, compared to the same period in ~~2003. The decreases during these periods compared to the same periods in 2003 were~~2004, primarily due to a reduction in ~~principal debt amount outstanding, lower interest rate, and a write-off of approximately $89 million of unamortized loan fees, loan discount, and prepayment fees associated with~~ the ~~repayment in July 2003 of approximately $735 million of principal under PG&E Corporation's existing credit agreement in 2003 with no similar charge in 2004.~~

~~Other Expense~~

PG&E Corporation's other expense increased by approximately $4 million and approximately $70 million for the three and nine-month periods ended September 30, 2004, compared to the same periods in 2003. These increases during both periods were primarily due to a pre-tax charge to earnings, ~~of approximately $5 million in the third quarter and approximately $70 million year-to-date,~~ related to the $32 million change in market value of non-cumulative dividend participation rights included within PG&E Corporation's ~~$280 million of 9.50%~~ Convertible Subordinated ~~Notes.~~Notes in the first quarter of 2004. The change in market value in 2005 was immaterial.

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 three months ended March 31, 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 liquidity.

At ~~September 30, 2004,~~March 31, 2005, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately ~~$1.9~~$1.4 billion, and restricted cash of approximately ~~$2.4~~$1.9 billion. PG&E Corporation and the Utility maintain separate bank accounts. At ~~September 30, 2004,~~March 31, 2005, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $0.9 billion and restricted cash of approximately $361 million, which included $30 million related to a settlement agreement with NEGT and certain of its creditors resolving tax-related issues. On October 14, 2004, when the settlement agreement became effective, $30 million was released from escrow and paid to NEGT.$319 million. At ~~September 30, 2004,~~March 31, 2005, the Utility had cash and cash equivalents of approximately ~~$980 million,~~$1.1 billion, and restricted cash of approximately ~~$2.0 billion, which pertains to~~$1.9 billion. The Utility's restricted cash includes amounts deposited in escrow ~~pending resolution of~~related to the remaining disputed ~~claims mad e in the~~ Chapter 11 ~~case.~~ claims, collateral required by the ISO and deposits under certain 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

~~During~~ seeks to maintain or strengthen its ~~Chapter 11 proceeding,~~credit ratings to provide efficient access to financial and trade credit and to ensure adequate liquidity. On February 16, 2005, S&P, upgraded its corporate credit rating on the Utility ~~did~~to BBB from BBB- and affirmed its BBB senior secured rating on the Utility's First Mortgage Bonds. S&P has not ~~have access~~assigned a rating to ~~the capital markets and met all~~PG&E Corporation.

On March 3, 2005, Moody's announced that it had upgraded its ~~ongoing cash requirements, including its capital expenditure requirements, with cash generated by its operations. In addition,~~corporate credit rating on the Utility ~~paid interest on certain pre-petition liabilities~~to Baa1 from Baa3 and ~~repaid the principal of maturing mortgage bonds with bankruptcy court approval.~~

~~In March 2004, in anticipation of~~upgraded the Utility's ~~emergence from Chapter 11, the Utility issued $6.7 billion~~other debt ratings as follows:

·	First Mortgage Bonds, secured pollution control bonds, and secured bank loan agreement to Baa1 from Baa2;
·	Preferred stock to Baa3 from Ba2;
·	Shelf registration for the issuance of First Mortgage Bonds to (P)Baa1 from (P)Baa2; and
·	The issuance of senior unsecured debt to (P)Baa1 from (P)Baa3.

Moody's also assigned a rating of ~~First Mortgage Bonds and~~Baa3 to PG&E Corporation's $200 million unsecured bank revolving credit facility. Moody's stated that its rating outlook is stable for the Utility and ~~its consolidated subsidiaries entered into $2.9 billion of credit facilities. The Utility also obtained an interim $400 million cash collateralized letter of credit facility, which was terminated~~PG&E Corporation.

As discussed in Note 3 in the Notes to the Condensed Consolidated Financial Statements, on April ~~12, 2004,~~22, 2005, the ~~effective date~~lien of the ~~Utility's Plan of Reorganization, or the Effective Date, and the letters of credit outstanding were transferred to the Utility's $850 million working capital facility. Proceeds from the sale of~~indenture securing the First Mortgage Bonds ~~borrowings~~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.

PG&E Corporation and the Utility have taken advantage of recent favorable market conditions by completing the following post-March 31 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 aggregating $614 million that had been issued to support certain pollution control bonds 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; and
·	On April 8, 2005, PG&E Corporation's unsecured $200 million credit facility was amended to include an extended 5-year term and to conform the provisions regarding covenants, representations and events of default to those contained in the Utility's $1 billion working capital facility.

Currently, PG&E Corporation and the Utility have available credit facilities totaling $200 million and $1.65 billion, respectively.

Dividends

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

Stock Repurchases

On March 4, 2005, PG&E Corporation entered into a new 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 of approximately ~~$1.1 billion, and approximately $2.4 billion of~~$1.05 billion). The repurchase was funded from available cash on hand and the repurchased shares were ~~used~~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 accelerated share repurchase arrangement, PG&E Corporation may receive from, or be required to pay to, GS&Co. a price adjustment based on the ~~Effective Date~~daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement (approximately six months). Because the price adjustment and any ad ditional payments that PG&E Corporation may be required to ~~pay allowed creditor claims~~make can be settled at PG&E Corporation's option, in cash or ~~deposited into escrow~~in shares of its common stock, or a combination of the two, PG&E Corporation accounts for its payment obligations as equity.

Until the transaction is completed or terminated, GAAP requires PG&E Corporation to ~~pay disputed claims when resolved. See~~assume that it will issue shares to settle its obligations (up to a maximum of two times the number of shares repurchased or 58,978,800 shares). PG&E Corporation must calculate the number of shares that would be required to satisfy its obligations upon completion of the transaction 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. At March 31, 2005, PG&E Corporation did not have any net payment obligations to GS&Co. Accordingly, no additional shares of PG&E Corporation common stock attributable to the accelerated share repurchase arrangement were treated as outstanding for purposes of calculating diluted earni ngs per share. Based upon the average price of PG&E Corporation stock from March 4, 2005 to March 31, 2005, and additional payments, GS&Co. had a net payment obligation to PG&E Corporation of approximately $1 million at March 31, 2005.

On March 8, 2005, the Utility used proceeds from the issuance of ERBs (discussed in Note 34 of the Notes to the Condensed Consolidated Financial ~~Statements for further discussion of the First Mortgage Bonds~~Statements) to repay debt and ~~the Utility's new credit facilities.~~

~~On June 29, 2004, the Utility entered into four separate loan agreements with the California Pollution Control Financing Authority, which issued $345 million aggregate principal amount~~to repurchase 22,023,283 shares of its Pollution Control Refunding Revenue Bonds 2004 Series A, B, C, and D to redeem the Pollution Control Revenue Bonds 1992 Series A and B and the 1993 Series A and B totaling $345 million held by the Utility. The funds received by the Utility were used to repay the $345 million term loan facility.

~~On October 3, 2004, the Utility partially redeemed Floating Rate Mortgage Bonds due in 2006 in the~~common stock from PG&E Corporation for an aggregate ~~principal amount~~purchase price of ~~$500~~approximately $960 million. The ~~$500~~Utility recognized charges of approximately $141 million ~~principal amount~~to Additional Paid-in Capital, approximately $110 million to Common Stock, and approximately $709 million to Reinvested Earnings within Shareholders' Equity in respect of ~~Floating Rate First Mortgage Bonds due in 2006 was selected from all Floating Rate First Mortgage Bonds due in 2006 in accordance with the procedures of The Depository Trust Company.~~this transaction.

~~The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the nine months ended September 30, 2004 and 2003.~~

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 ~~nine~~three months ended ~~September 30,~~March 31, 2005 and 2004 ~~and 2003~~ were as follows:

					Three Months Ended
	Nine Months Ended September 30,				March 31,

(in millions)	2004		2003		2005			2004

Net income	$	3,735	$	861	$	223		$	3,074
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	1,054		916		385		311
Recognition of regulatory assets, net of tax	(2,904)		-
Change in accounts payable	77		350
Change in income taxes payable	87		437
Change in other working capital	285		77
Gain on establishment of regulatory asset, net					-		(2,904)
Change in accounts receivable					169		353
Change in accrued taxes					220		98
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(1,022)		(83)		-		(20)
Other changes in operating assets and liabilities	96		(19)		38		97


Net cash provided by operating activities	$	1,408	$	2,539	$	1,035		$	1,009

Net cash provided by operating activities ~~decreased~~increased by approximately ~~$1.1 billion~~$26 million during the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005 compared to the same period in ~~2003. This decrease was~~2004, mainly due to anthe increase in ~~payments authorized by~~net income of approximately $53 million, excluding the ~~bankruptcy court on amounts classified as liabilities subject to compromise~~one-time non-cash gain, after tax, of ~~$939 million during the nine months ended September 30, 2004, compared~~approximately $2.9 billion related to the ~~same period in 2003. This increase was a result~~recognition of the ~~payment~~regulatory assets established under the Settlement Agreement in the first quarter of ~~all allowed creditor claims on the Effective Date.~~2004.

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 ~~for~~during the ~~nine months~~three month periods ended ~~September 30,~~March 31, 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 ~~nine months~~three month periods ended ~~September 30,~~March 31, 2005 and 2004 ~~and 2003~~ were as follows:

Nine Months Ended
September 30,
(in millions)
2004
2003
Capital expenditures
$
(1,110)
$
(1,182)
Proceeds from sale of assets
28
14
Increase in restricted cash
(1,751)
-
Other investing activities
(50)
(25)
Net cash used by investing activities
$
(2,883)
$
(1,193)

	Three Months Ended
	March 31,

(in millions)	2005		2004


Capital expenditures	$	(349)	$	(342)
Net proceeds from sale of assets	11		18
Decrease (increase) in restricted cash	26		(6,917)
Other investing activities, net	26		(65)

Net cash used in investing activities	$	(286)	$	(7,306)

Net cash used by investing activities ~~increased~~decreased by approximately ~~$1.7~~$7.0 billion ~~during the nine months ended September 30, 2004, compared to the same period in 2003. This increase was~~primarily due to an increase in restricted cash of approximately ~~$1.8~~$7.0 billion ~~during~~for the ~~nine~~three months ended ~~September 30,~~March 31, 2004 ~~compared to~~with no similar change for the same period in ~~2003, mainly due to funds~~2005. In March 2004, the Utility consummated a public offering of $6.7 billion of first mortgage bonds. Proceeds from this offering and redemption premiums and interest of $217 million were deposited into escrow ~~to pay disputed~~for payment of claims ~~when resolved. Other investing activities increased mostly due to an increase in nuclear fuel inventory that~~upon emergence from Chapter 11. On April 12, 2004, the effective date of the Utility's plan or reorganization, this cash was ~~partially offset by a decrease in nuclear decommissioning funding.~~paid out of the escrow account.

Financing Activities

~~Prior to~~In 2005, the ~~implementation~~Utility used the $1.9 billion proceeds of the ~~Plan of Reorganization and during its Chapter 11 proceeding,~~ERBs to refinance the ~~Utility's financing activities were limited to~~Settlement Regulatory Asset through the repayment of ~~secured~~ debt ~~obligations as authorized by the bankruptcy court. During this period, the Utility did not have access to the capital markets. As a result~~and repurchase of its emergence from Chapter 11, the Utility has issued significant amounts of debt in connection with the implementation of the Plan of Reorganization and established a working capital facility and an accounts receivable financing facility for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit.equity.

The Utility's cash flows from financing activities for the ~~nine months~~three month period ended ~~September 30,~~March 31, 2005 and 2004 ~~and 2003~~ were as follows:

					Three Months Ended
	Nine Months Ended September 30,				March 31,

(in millions)	2004		2003		2005		2004

Net proceeds from issuance of long-term debt	$	7,346	$	-
Long-term debt issued, matured, redeemed or repurchased		(7,552)		(280)
Net proceeds from long-term debt issued					$	-	$	6,547
Net proceeds from energy recovery bonds issued						1,874		-
Net repayments under credit facilities and short-term borrowings						(300)		-
Rate reduction bonds matured	(213)		(213)			(74)		(74)
Long-term debt, matured, redeemed or repurchased						(900)		(310)
Common stock dividends paid					(110)
Preferred dividends paid	(88)		-		(4)		-
Preferred stock with mandatory redemption provisions redeemed	(15)		-		(2)		-
Other financing activities	(2)		(1)
Common stock repurchased					(960)		-

Net cash used by financing activities	$	(524)	$	(494)
Net cash provided by (used in) financing activities					$	(476)	$	6,163

For the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005, net cash used byin financing activities ~~increased~~decreased by approximately ~~$30 million~~$6.6 billion compared to the same period in ~~2003. This increase was mainly~~2004, due to the following factors:

·	In March 2004, in connection with the ~~implementation~~Utility's plan of ~~the Utility's Plan of Reorganization,~~reorganization, the Utility ~~consummated a public offering~~issued approximately $6.5 billion, net of ~~$6.7 billion~~issuance costs, in ~~First Mortgage Bonds. On the Effective Date, the Utility entered into pollution control bond bridge loans~~long-term debt with no comparable amount in the amount of $454 million (see Note 3 of the Notes to the Consolidated Financial Statements). In June 2004, the Utility entered into four separate loan agreements with the California Pollution Control Financing Authority, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds (see Note 3 of the Notes to the Consolidated Financial Statements). Partially offsetting these proceeds are issuance costs of approximately $153 million associated with the $6.7 billion in First Mortgage Bonds;three months ended March 31, 2005;
·	In ~~April~~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);
·	During the quarter, the Utility repaid $300 million it borrowed under its $850 million working capital facility;
·	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 ~~net~~ERBs proceeds to defease $600 million of ~~approximately $6.5 billion from~~Floating Rate First Mortgage Bonds. During the ~~offering, together with available cash~~first quarter 2004, repayments on ~~hand to pay creditor claims, including approximately $7.5 billion of~~ long-term debt totaled $310 million. As a result, repayments on long-term debt increased approximately $590 million in the three months ended March 31, 2005, as compared to the same period in 2004;
·	In February 2005, the Utility paid $110 million in common stock dividends to PG&E Corporation and ~~deposit funds in escrow for~~$7 million to PG&E Holdings LLC, a wholly owned subsidiary of the ~~payment of disputed claims;~~Utility;
·	Approximately ~~$213 million of rate reduction bonds matured during the nine months ended September 30, 2004;~~
·	~~Approximately $88~~$4 million of preferred stock dividends were paid during the ~~nine~~three months ended ~~September 30, 2004;~~March 31, 2005; and
·	~~Approximately $15~~In March 2005, the Utility used proceeds from the issuance of ERBs to repurchase $960 million of ~~preferred~~its common stock ~~with mandatory redemption provisions was redeemed during the nine months ended September 30, 2004.~~from PG&E Corporation.

PG&E Corporation

~~At September 30, 2004,~~ As of March 31, 2005, PG&E Corporation had stand-alone cash and cash equivalents of approximately ~~$0.9 billion and restricted cash of approximately $361~~$319 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 $117 million to PG&E Corporation and PG&E Holdings LLC on February 17, 2005. The Utility did not pay any dividends to, nor repurchase shares from, PG&E Corporation during ~~the first nine months of 2004 or 2003.~~2004.

On August 27, 2004, PG&E Corporation reached a settlement with NEGT and certain of its creditors resolving certain tax-related issues and waiving certain inter-company claims. Pursuant to the settlement agreement, PG&E Corporation deposited $30 million in escrow to be paid to NEGT when the settlement became final and non-appealable. At September 30, 2004, this $30 million was treated by PG&E Corporation as restricted cash. Subsequently, on October 14, 2004, the $30 million was released from escrow and paid to NEGT and the remaining $331 million that PG&E Corporation had previously treated as restricted cash, while the dispute was pending, is no longer considered restricted.

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 interest costs are not passed on to its affiliates nor are the benefits or detriments of the consolidated tax return. The benefits of the consolidated tax return have created cash flow from operating activities for PG&E Corporation during the nine months ended September 30, 2004 and 2003. NEGT's tax dispute with PG&E Corporation is discussed above.

PG&E Corporation's consolidated cash flows from operating activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2005 and 2004 ~~and 2003~~ were as follows:

					Three Months Ended
	Nine Months Ended September 30,				March 31,

(in millions)	2004		2003		2005		2004

Net income	$	3,633	$	383	$	218	$	3,033
Loss from discontinued operations	-		365
Cumulative effect of changes in accounting principles	-		6

Net income from continuing operations	3,633		754
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	1,056		910		385		312
Deferred income taxes and tax credits, net					(63)		(70)
Recognition of regulatory asset, net of tax	(2,904)		-		-		(2,904)
Deferred income taxes and tax credits, net	364		339
Other deferred charges and noncurrent liabilities	(183)		636		(45)		237
Loss from retirement of long-term debt	(18)		89
Tax benefit from employee stock plans					25		-
Other changes in operating assets and liabilities	(458)		188		528		279

Net cash provided by operating activities	$	1,490	$	2,916	$	1,048	$	887

Net cash provided by operating activities ~~decreased~~increased by ~~$1.4 billion~~$161 million during the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005, compared to the same period in ~~2003.~~2004. This ~~decrease~~increase was primarily related to ~~decreases~~the recognition of tax benefits on the exercise of employee stock options during the three months ended March 31, 2005, with no similar amount in ~~other deferred charges and noncurrent liabilities~~2004 and the ~~Utility's decrease~~payment of approximately $84 million to participating individuals in ~~net cash provided from operating activities as discussed above, partially offset by increases~~the senior executive retention program in ~~deferred income taxes and tax credits, net.~~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 induring the ~~nine~~three months ended ~~September 30, 2004~~March 31, 2005 or ~~2003.~~the same period in 2004.

Financing Activities

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

PG&E Corporation's consolidated cash flows from financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2005 and 2004 ~~and 2003~~ were as follows:

					Three Months Ended
	Nine Months Ended September 30,				March 31,

(in millions)	2004		2003		2005		2004

Net repayments under credit facilities and short-term borrowings					$	(300)	$	-
Net proceeds from issuance of energy recovery bonds					1,874		-
Net proceeds from issuance of long-term debt	$	7,346	$	582	-		6,547
Long-term debt matured, redeemed or repurchased	(7,553)		(1,067)		(901)		(310)
Rate reduction bonds matured	(213)		(213)		(74)		(74)
Preferred stock with mandatory redemption provisions redeemed	(15)		-		(2)		-
Common stock issued					120		58
Common stock repurchased					(1,065)		-
Preferred dividends paid	(88)		-		(4)		-
Common stock issued	121		120
Other, net	(2)		(2)		(1)		-

Net cash used by financing activities	$	(404)	$	(580)
Net cash (used in) provided by financing activities					$	(353)	$	6,221

PG&E Corporation's ~~consolidated~~ net cash used by financing activities decreased by ~~$176million~~$6.6 billion for the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005, compared to the same period in ~~2003. This~~2004. The decrease was primarily related to the Utility's financing activities as discussed ~~above.~~

~~Future Liquidity~~

As a result of its emergence from Chapter 11 on April 12, 2004, the Utility expects to fund its operating expenses and capital expenditures substantially from internally generated funds although it may issue debt for these purposes in the future. In addition, the Utility expects to use the amount remaining under its $850 million working capital facility for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit. In addition, the Utility has entered into a $650 million accounts receivable financing. At September 30, 2004, the Utility did not have any borrowings under either facility. Under the $850 million facility, $163 million was outstanding to support letters of credit at September 30, 2004.

On October 3, 2004, the Utility redeemed $500 million aggregate principal amount of Floating Rate First Mortgage Bonds and expects that its cash on hand, together with cash from operating activities and available amounts under the facilities described above, ~~will provide for seasonal fluctuations in cash requirements and will be sufficient to fund its operations and its capital expenditures for the foreseeable future.~~

~~On October 15, 2004, the trustee under the indenture for~~ PG&E Corporation's~~6⅞%~~ Senior Secured Notes due July 15, 2008, or Senior Secured Notes, notified the holders of the Senior Secured Notes that these will be redeemed in full on November 15, 2004. Redemption of the Senior Secured Notes will require approximately $664.5 million of PG&E Corporation's cash, which includes a redemption premium repurchase of approximately ~~$50.7~~29.5 million ~~and $13.8 million~~shares of interest that has accrued since the last interest payment date. PG&E Corporation's ability to meet its debt obligations, pay dividends and make stock repurchases are based upon dividends received from, and stock repurchases made by, the Utility as discussed below.

~~Dividends and Share Repurchases~~

PG&E Corporation did not declare or pay a dividend during the Utility's Chapter 11 proceeding. Further, until the Senior Secured Notes issued by PG&E Corporation are redeemed or rated Baa3 or better by Moody's Investors Service, or Moody's, and BBB- or better by Standards & Poor's, or S&P, PG&E Corporation is prohibited from declaring or paying dividends or repurchasing its common stock ~~unless certain financial criteria are met. Notwithstanding this restrictive covenant, PG&E Corporation may (1) pay regular quarterly dividends funded~~under an accelerated share repurchase agreement in March 2005 at an initial purchase price of $1.05 billion, and increased proceeds from ~~proceeds of cash distributions to PG&E Corporation from the Utility, (2) repurchase~~ common stock ~~with proceeds of sales of PG&E Corporation equity, including~~issuances due to increased employee stock option exercises and (3) make certain other limited repurchases of common stock. PG&E Corporation can redeem the Senior Secured Notes at any time at its option at a premium. As dis cussed above, the Senior Secured Notes will be redeemed in ~~full on November 15, 2004.~~

While in Chapter 11, the Utility was prohibited from paying any common or preferred stock dividends without bankruptcy court approval. The Utility resumed the payment of preferred stock dividends on May 15, 2004. On July 20, 2004, the Utility declared dividends on all the outstanding 11 series of its preferred stock for the three months ~~ending July~~ended March 31, ~~2004. The dividends were paid on August 15, 2004,~~2005, compared to the ~~shareholders of record on July 30,~~same period in 2004.

On October 20, 2004, the Board of Directors of PG&E Corporation and the Board of Directors of the Utility each approved a common stock dividend policy and a target dividend payout ratio range (the proportion of earnings paid out as dividends) of 50-70%. Although the Boards of Directors deferred the actual declaration of a common stock dividend at least until after the Utility achieves the target equity ratio As discussed ~~below, the Board of Directors of PG&E Corporation adopted an initial annual cash dividend target of $1.20 per share ($0.30 quarterly).~~

~~Each dividend policy was designed to meet the following three objectives:~~

·	~~Comparability: Pay a dividend competitive with the securities of comparable companies based on payout ratio and, with respect to PG&E Corporation, yield (i.e., dividend divided by share price);~~
·	Flexibility: Allow sufficient cash to pay a dividend and to fund investments while avoiding the necessity to issue new equity unless PG&E Corporation's or the Utility's capital expenditure requirements are growing rapidly and PG&E Corporation or the Utility can issue equity at reasonable cost and terms; and
·	~~Sustainability: Avoid reduction or suspension of the dividend despite fluctuations in financial performance except in extreme and unforeseen circumstances.~~

~~The target dividend payout ratio range was based on an analysis of dividend payout ratios of comparable companies. The initial dividend target was chosen in recognition of~~above, the Utility's current credit rating and the potential capital investments that the Utility may make in the future to provide electricity resource adequacy in compliance with future regulatory requirements and an approved long-term electricity resources plan.

~~After the Utility reaches~~repurchase of its target equity ratio of 52% as provided in the Settlement Agreement, and ERBs in the approximate amount of $1.8 billion are issued in January 2005 to refinance the Settlement Regulatory Asset, it is anticipated that the Utility would use surplus cash to pay dividends to, or repurchase common stock from PG&E Corporation ~~which~~totaling $960 million in March 2005 was eliminated in consolidation.

CONTRACTUAL COMMITMENTS

PG&E Corporation would use in turn to pay dividends to, or repurchase stock from, its shareholders. Assuming the issuance of ERBs in January 2005 in the approximate amount of $1.8 billion, PG&E Corporation estimates that it would have up to $1.75 billion to distribute to its shareholders through the end of 2005 through dividends and stock repurchases. PG&E Corporation estimates that an additional approximately $950 million will be available through the end of 2006 to distribute to shareholders through dividends and stock repurchases or for capital i nvestments beyond the level of capital expenditures already assumed.

~~The initial annual cash dividend target of $1.20 per share is based on many assumptions, including that:~~

·	~~The Utility remains under cost-of-service regulation by the CPUC and, with respect to electric transmission, the FERC;~~
·	~~The CPUC and the FERC authorize sufficient revenues for the Utility to recover its energy procurement and base expenses;~~
·	~~The Utility's authorized return on equity for all operations remains at least at 11.22%;~~
·	~~The first series of ERBs in the approximate amount of $1.8 billion is issued in early 2005 and the second series is issued in early 2006;~~
·	Annual Utility capital expenditures average $1.9 billion in 2005 and 2006 (these forecasted capital expenditures do not include amounts for new generation development or implementation of an advanced metering system);
·	~~Total gas and electric rate base, including retained generation facilities and the Settlement Regulatory Asset, of approximately $15.3 billion for 2005 and $16.0 billion for 2006; and~~
·	The Utility manages its operating expenses and capital expenditures to earn the full authorized rate of return within revenues authorized under the CPUC's decision in the Utility's 2003 GRC and subsequent adjustments for inflation through 2006.

Each 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 dividends are payable until after the respective Board of Directors declares a dividend. In order to declare a dividend, each Board of Directors must determine that the applicable requirements of California law and the ~~CPUC have been satisfied.~~

~~CAPITAL EXPENDITURES AND COMMITMENTS~~

~~Capital Expenditures~~

~~The Utility's distribution, generation~~Utility enter into contractual obligations and transmission operating assets generally consist of long-lived assets with significant construction and maintenance costs. The Utility's annual capital expenditures are expected to average approximately $1.9 billion annually over the next two years, excluding costs associated with potential new generation development or implementation of advanced metering systems. This is expected to result in an average annual rate base of approximately $15.3 billion in 2005 and approximately $16.0 billion in 2006 (excluding the Settlement Regulatory Asset). It is anticipated that the Utility will be required to make substantial capital expenditurescommitments in connection with business activities. These obligations need to be funded in the ~~implementation~~future and primarily relate to financing arrangements (such as long-term debt, preferred stock and certain forms of ~~its long-term~~regulatory financing), purchases of transportation capacity, natural gas and electricity ~~resource plan as described below.~~to support customer demand and the purchase of fuel and transportation to support the Utility's generation activities. Refer to Note 7 in the Notes to the Condensed Consolidated Financial Statements and PG&E Corporation's and the Utility's combined 2004 Annual Report for further discussion.

~~Contractual Commitments~~

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. ~~In connection~~

Capital Expenditures

The Utility's investment in plant and equipment is necessary to replace aging and obsolete equipment and accommodate anticipated electricity and natural gas load growth. It is estimated that the Utility's base capital expenditures will approximate $1.9 billion in each of 2005 and 2006 (excluding potential investments in an advanced metering infrastructure, as discussed below).

Advanced Metering Infrastructure

The CPUC is assessing the viability of implementing an advanced metering infrastructure 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. If the CPUC determines that it would be cost effective to install advance d metering on a large scale and authorizes the Utility to proceed with large scale development of advanced metering for residential and small commercial customers, the Utility expects that it would incur substantial costs to convert its meters, build the meter reading network, and build the data storage and processing facilities to bill its customers. On March 15, 2005, the Utility filed an application with the ~~implementation~~CPUC to spend up to $49 million on pre-deployment activities for advanced metering. This application has not yet been approved. The Utility expects to file an application for deployment of the ~~Plan~~full advanced metering project in the summer of ~~Reorganization,~~2005. The Utility would expect to recover through rates the capital investments and any ongoing operating costs net of operating savings associated with implementing the advanced metering project. The total deployment of an advanced metering infrastructure to all of the Utility's electricity and natural gas customers using equipment and technology currently avai lable may cost more than $1.0 billion, based on a five-year installation schedule starting in 2006.

Off-Balance Sheet Arrangements

For financing and other business purposes, PG&E Corporation and the Utility ~~issued $6.7 billion~~utilize certain arrangements that are not reflected in ~~First Mortgage Bonds, entered into $2.9 billion~~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 ~~credit facilities, and obtained a $400 million cash collateralized~~these arrangements. For further information related to letter of credit ~~facility. On~~agreements, the ~~Effective Date, the $400 million letter~~credit facilities, aspects of ~~credit facility was cancelled~~PG&E Corporation's accelerated share repurchase program, and PG&E Corporation's guarantee related to certain NEGT indemnity obligations and the ~~outstanding letter~~Utility's workers' compensation obligations, see Notes 3, 5, and 7 of ~~credit balance was transferred~~the Notes to the ~~Utility's $850 million revolving credit facility. In addition,~~Condensed Consolidated Financial Statements.

Contingencies

PG&E Corporation and the Utility ~~paid approximately $8.4 billion~~have significant contingencies that are discussed below. Also, refer to Note 7 in ~~cash~~the Notes to ~~holders of allowed claims and deposited approximately $1.8 billion into escrow accounts~~the Condensed Consolidated Financial Statements for ~~the paym ent of disputed claims.~~further discussion.

~~Utility~~Regulatory Matters

~~Power Purchase Agreements~~

During the nine-month period ended September 30, 2004, the Utility entered into various agreements to purchase energy. Under these agreements, the Utility is committed to make energy payments of approximately $159 million and capacity payments of approximately $6 million 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~~This section of the ~~Utility's portfolio of natural gas procurement contracts have fluctuated generally based on market conditions.~~

~~During~~MD&A discusses significant regulatory issues pending before the ~~period that~~CPUC, the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. In connection with its emergence from Chapter 11, the Utility received investment grade issuer credit ratings from Moody's and S&P. As a result of these credit rating upgrades, the Utility has obtained unsecured credit lines from the majority of its gas supply counterparties.

~~At September 30, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:~~

(in millions)
2004
$
371
2005
714
2006
26
2007
7
2008
-
Thereafter
-
Total
$
1,118

~~Nuclear Fuel Agreements~~

~~At September 30, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:~~

(in millions)
2004
$
128
2005
28
2006
29
2007
38
2008
30
Thereafter
64
Total
$
317

~~Transmission Control Agreement~~

~~The Utility has entered into a Transmission Control Agreement, or TCA, with the California Independent System Operator,~~FERC, or the ISO, and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several municipal utilities) under which the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA.

The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require certain power plants, known as RMR plants, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. As a party to the TCA, the Utility is responsible for a share of the ISO's costs paid to power plant owners under RMR agreements within the Utility's service territory.

At September 30, 2004, the Utility estimated that it could be obligated to pay the ISO approximately $605 million in costs incurred under these RMR agreements during the period October 1, 2004 to September 30, 2006. Of this amount, the Utility estimates that it would receive approximately $96 million under its RMR agreements during the same period. These costs and revenues are subject to applicable ratemaking mechanisms.

It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision in a rate case filed by subsidiaries of Mirant Corporation, or Mirant, approving rates and a ratemaking methodology that, if affirmed by the FERC, would require the subsidiaries of Mirant 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 $350 million, including interest, for availability of Mirant's RMR plants under these agreements. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant's Chapter 11 proceeding including a claim for an RMR refund. The Utility is unable to predict at this time when the FERC will issue a final decision in Mirant's c ase, what the FERC's decision will be, the amount of any refunds the Utility may ultimately receive, and howNRC, the resolution of this matter would be reflected in the rates. Due to this uncertainty as of September 30, 2004, the Utility had not recorded any amounts in its Consolidated Balance Sheet for any refunds receivable thatwhich may ~~result from the FERC's final decision.~~

In November 2001, after the ALJ issued the initial decision in Mirant's rate case, various complaints were filed at the FERC against other RMR plant owners, including the Utility, alleging that the ratemaking methodology approved in the ALJ's initial decision should be applied to the other RMR plant owners. If the FERC adopts the ALJ's decision in the Mirant rate case and applies the ratemaking methodology toaffect the Utility's RMR plants, the Utility could be required to refund payments it received from the ISO for the availability of the Utility's RMR plants. The Utility has responded to the complaint asserting that the methodology approved in the ALJ's decision should not apply to the Utility. The FERC has not yet acted on these complaints. The Utility believes the ultimate outcome of this matter will not have an adverse material effect on the Utility'sand PG&E Corporation's results of operations or financial condition. The information presented below should be read in conjunction with PG&E Corporation's and the Utility's combined 2004 Annual Report.

~~WAPA Commitments~~Electricity Generation Resources

Procurement Cost Balancing Account and Mandatory Rate Adjustments

~~In 1967,~~California law allows the Utility to recover its reasonably incurred wholesale electricity procurement costs. The Utility has established a balancing account, the Energy Resource Recovery Account, or ERRA, to track the difference between the authorized revenue requirement and the ~~Western Area Power Administration,~~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 ~~WAPA, entered into several long-term power contracts governing~~order refunds, as appropriate, when the ~~interconnection~~forecast aggregate over-collections or under-collections exceed 5% of the Utility's ~~and WAPA's~~prior year electricity ~~transmission systems,~~procurement revenues, excluding amounts collected for the ~~use~~DWR. For 2005, 5% of the Utility's 2004 electricity ~~transmission~~procurement revenues, excluding amounts collected for the DWR, is approximat ely $164.4 million. As of March 31, 2005, the ERRA had an over-collected balance of approximately $82 million, below the amount that would trigger the mandatory adjustment of rates. The CPUC approved an ERRA revenue requirement of $2.14 billion for 2005 based on forecast costs and distribution system by WAPA, and the integration of the Utility's and WAPA's customer demands and electricity resources. The contracts give the Utility access to WAPA's excess hydroelectric power and obligatehas authorized the Utility to ~~provide WAPA~~amortize routine over- and under-collections in the ERRA annually to coincide with ~~electricity when~~January 1 rate changes.

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 ~~own resources are not sufficient~~approved procurement plans. The cost of procurement activities related to ~~meet its requirements. The~~the DWR's allocated contracts ~~are scheduled~~could be disallowed up to ~~terminate on December 31, 2004, but termination is subject to FERC approval, which~~a maximum of two times the ~~Utility expects to receive.~~

~~On October 15, 2004, the Utility filed Offers of Settlement with the FERC to terminate the FERC rate schedules~~Utility's administration costs associated with the 1967 WAPA contracts. The Offers of Settlement were signed by the Utility and WAPA, and in one instance by the California ISO as operator of much of the Utility's transmission system. The Offers of Settlement, if accepted by the FERC as filed, will terminate the rate schedules associated with the 1967 contracts on January 1,procurement each year. For 2005, and will replace them with new service contracts under which the Utility no longer will provide any electric power or transmission services but will continue to provide wholesale distribution service. The new service contracts were filed on Octoberthis amount is $36 million. On April 21, 2004. There is no monetary component to the Offers of Settlement; their purpose is to terminate the 1967 contracts and to replace them. The Utility's cost obligations associated with the 19 67 contracts will terminate with those contracts and related FERC rate schedules and will not be replaced.

It is possible that the FERC will not accept the Offers of Settlement as filed or will materially alter them or suspend their effectiveness beyond January 1, 2005. The costs to fulfill the Utility's obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electric power that WAPA will need from the Utility in 2005, are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, the Utility's estimated net costs, based upon its portfolio and after subtracting revenues received from WAPA, for electricity delivered under the contracts were approximately $57million and $161 million in the three and nine-month periods ended September 30, 2004.

~~Other Commitments~~

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, software licenses, the self-generation incentive program exchange agreements and telecommunication contracts. At September 30, 2004, the future minimum payments related to other commitments were as follows:

(in millions)
2004
$
97
2005
95
2006
32
2007
17
2008
14
Thereafter
5
Total
$
260

~~REGULATORY MATTERS~~

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction to, among other things, set the rates, terms and conditions of service for the Utility's electricity generation, procurement and distribution, natural gas distribution, and natural gas transportation and storage services in California. The FERC is an independent agency within the U.S. Department of Energy, or DOE, that, among other things, regulates the transmission of electricity and the sale for resale of electricity in interstate commerce.

The Utility's rates are determined based on its costs of service. As discussed above under "Overview," as of January 1, 2004, the Utility's electric rates reflect the sum of individual revenue requirement components. Changes in any individual revenue requirement will change customers' electricity rates and the Utility's revenues. On October 15, 2004, the Utility filed its first annual electric true-up advice letter with the CPUC to provide the CPUC information about expected electric rate changes to occur on January 1, 2005 to reflect amortization of balancing account balances authorized for recovery in 2005, update the Settlement Regulatory Asset revenue requirement for 2005, consolidate rate changes expected to result from resolution of various pending proceedings or approval of various advice filings before December 31, 2004, and provide information on FERC-jurisdictional rate changes to be implemented on Janua ry 1, 2005. On or before December 31, 2004, the Utility expects to file a supplemental advice letter to reflect November 30, 2004 account balances and any rate changes resulting from proceedings and advice letters that have then been resolved. It is expected that these rate changes would result in an increase in 2005 electric revenues of approximately $315 million.

~~2003 General Rate Case~~

In May 2004, the CPUC issued a decision in the Utility's 2003 GRC. The 2003 GRC determines the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 and certain succeeding years.

·	~~$2.5 billion for electricity distribution operations, representing a $236 million increase over the previously authorized amount;~~
·	~~$912 million for electricity generation operations, representing a $38 million increase over the previously authorized amount; and~~
·	~~$927 million for natural gas distribution operations, representing a $52 million increase over the previously authorized amount.~~

~~As part of the GRC,~~ the CPUC approved the ~~following minimum and maximum yearly adjustments~~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 ~~base revenue requirements, or attrition rate adjustments, for 2004, 2005, and 2006 based~~updated procurement plan. The Utility expects to receive a draft decision on the ~~change in the Consumer's Price Index, or CPI:~~

~~As a result~~remainder of the ~~approval of the~~record period (i.e., June 1, 2003 ~~GRC, during~~to December 31, 200 3) in the second quarter of ~~2004,~~2005. On February 15, 2005, the Utility ~~recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. During~~filed an ERRA compliance review application for the ~~third quarter of~~January 1 - December 31, 2004 ~~the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC. The impact of the 2003 GRC~~record period. Final action on the ~~third quarter~~2004 record period application is expected before the end of ~~2004 is discussed in the Results of Operations section above. The net impact of the items which were recorded in the second quarter, on a pre-tax basis is as follows:~~

For electricity distribution and generation, the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure in 2003. The amount of electricity revenue to be refunded in 2003 incorporated the impact of the electric portion of the GRC settlement and was recorded as a regulatory liability at December 31, 2003. In 2004, the Utility recorded its electricity distribution and generation base revenue requirements under a cost of service ratemaking structure. Because the 2003 refund obligation already incorporated the impact of the GRC that related to fiscal 2003, and since the CPUC issued a final decision approving a revenue requirement increase in 2004, the Utility recorded the increase related to the six-month period ended June 30, 2004 in its 2004 results of operations of approximately $157 million.

Another phase of the GRC was established to address the Utility's response to the December 2002 storm and the Utility's reliability performance. In October 2004, the CPUC approved certain storm response improvement initiatives as well as a reliability performance incentive mechanism for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million each year depending on the extent to which the Utility exceeds the reliability performance improvement targets, but could be required to pay a penalty of up to $24 million a year depending on the extent to which it fails to meet the targets. The decision does not provide the Utility with additional revenues to meet the reliability standards, but does include a wide margin of error around the targets in order to mitigate potential penalties.2005. PG&E Corporation and the Utility are unable to predict whether a disallowance will result or ~~not~~ the ~~Utility~~size of any potential disallowance. In addition, it is uncertain whether the CPUC will ~~incur a reward~~modify or ~~penalty related to~~eliminate the ~~performance incentive mechanism.~~maximum disallowance for future years.

~~Cost of Capital Proceedings~~New Long-Term Generation Resource Commitments

The CPUC last authorized a cost of capital for the Utility in 2003, setting the return on equity at 11.22% and its cost of debt at 7.57%. The Utility's last authorized capital structure was 48.00% common equity, 46.20% long-term debt and 5.80% preferred equity.

The Settlement Agreement provides that from January 1, 2004 until Moody's has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-,In accordance with the Utility's authorized return on equity will be no less than 11.22% per year and its authorized equity ratio will be no less than 52%. However, for 2004 and 2005, the Utility's authorized equity ratio will equal the greater of the proportion of equity approved in the Utility's 2004 and 2005 cost of capital proceedings, or 48.6%.

On May 12, 2004, the Utility filed a cost of capital application with the CPUC to recover in rates (1) its actual cost of capital (long-term debt and preferred stock) from January 1, 2004 through April 11, 2004, (2) its new cost of capital resulting from its Chapter 11 exit financing that became effective on April 12, 2004, and (3) costs associated with interest rate hedges for its Chapter 11 exit financing. For itsCPUC-approved long-term electricity ~~and natural gas distribution operations, natural gas transmission and storage, and electricity generation operations,~~procurement plan, the Utility has requested offers from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under utility-owned projects or turnkey developments, or buyouts, or under 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.

Initial bids were submitted in late April 2005. It is anticipated that contracts for the winning bidders will be submitted to the CPUC ~~authorize the following cost of capital~~ for ~~2004 and 2005:~~

2004

2005

Cost

Capital
Structure

Weighted
Cost

Cost

Capital
Structure

Weighted
Cost
Long-term debt

5.82%
48.2%
2.81%

5.94%
45.5%
2.70%
Preferred stock

6.76%
2.8%
0.19%

6.42%
2.5%
0.16%
Common equity

11.22%
49.0%
5.50%

11.60%
52.0%
6.03%
Return on rate base

8.49%

8.90%

The Utility's annual revenue requirement for 2004 would decrease by approximately $109 million compared to the currently authorized revenue requirement. As of September 30, 2004, the Utility recorded a $71 million reserve against operating revenues for the difference between its currently authorized rate of return on rate base and the lower rate of return on rate base requested in its cost of capital application.

For 2005, the requested capital structure reflects an assumption that ERBs are sold on January 1, 2005 to refinance the Settlement Regulatory Asset, and that the proceeds of the issuance are used to rebalance the Utility's capital structure in order to attain the target capital structure of 52% equity ratio as providedapproval in the ~~Settlement Agreement and to fund infrastructure capital expenditures. Due to energy supplier refunds which are expected to be offset against the Settlement Regulatory Asset, the projected amount~~second half of ERBs targeted for issuance in January 2005 is approximately $1.8 billion. After the issuance of ERBs, the Utility would not collect the 11.22% return on equity on the Settlement Regulatory Asset. Instead, the Utility would recover the principal and interest related to the ERBs from customers through the dedicated rate component.2005.

DWR Allocated Contracts

The Utility ~~has proposed to include any electric~~acts as a billing agent for the collection of the DWR's revenue ~~requirement change authorized in this proceeding in rates effective January 1, 2005.~~requirements from the Utility's customers. The ~~Utility also has proposed to include any gas~~DWR's revenue ~~requirement changes authorized in this proceeding in the next gas transportation rate change, annual true-up or the biennial cost allocation proceeding.~~

~~The Utility expects the CPUC will issue~~requirements consist of a ~~final decision on the cost of capital proceeding in December 2004.~~

~~DWR Revenue Requirements~~

~~In September 2003, the DWR filed a proposed $4.5 billion 2004~~ power charge ~~revenue requirement and a proposed 2004 bond charge revenue requirement of approximately $873 million with~~to pay for the ~~CPUC for its~~DWR's costs of purchasing electricity ~~on behalf of~~under its contracts and a bond charge to pay for the ~~Utility's customers.~~DWR's costs associated with its $11.3 billion bond offering completed in November 2002. In ~~January~~December 2004, the CPUC ~~adopted an interim~~issued a decision on the permanent cost allocation ofmethodology for the DWR's ~~proposed~~power charge revenue requirements in 2004 ~~revenue requirements~~and subsequent years, among the three California investor-owned electric ~~utilities' customers. The Utility's customers' share~~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 charge revenue requirement is approximately $1.8 billion after consideration of a DWR 2001-2002 adjustment approved in a CPUC decision in January 2004. The January 2004 decision allocated the bond charge revenue requirement among the three California investor-owned electric utilities' customers on an equal cents per kWh basis, which resulted in approximately $369 million being allocated to the Utility's customers.

In April 2004, the DWR submitted a supplemental determination of its 2004 revenue requirement to the CPUC reducing the amount of power charge revenues the DWR will recover from electric customers statewide in 2004 by $245 million. The reduction is primarily driven by higher than projected power charge revenues received by the DWR in 2003, and an increased forecast of revenues from the sale of surplus power in 2004.

In August 2004, the CPUC approved allocation of the 2004 DWR supplemental revenue requirements using the interim allocation methodology adopted in its January 2004 decision, retroactive to January 1, 2004.

In September 2004, the DWR filed a proposed $3.9 billion 2005 power charge revenue requirement and a proposed 2005 bond charge revenue requirement of approximately $886 million with the CPUC. The CPUC is considering several proposed decisions for the permanent allocation of the DWR revenue requirement for 2004 and beyond among the three utilities' customers.contracts. A final decision on aDWR permanent cost allocation ~~methodology~~ is expected in the ~~fourth~~second quarter of ~~2004.~~2005. The Utility cannot predict the final outcome of this ~~matter.~~

matte r. As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, isshould not ~~expected to materially~~ affect the Utility's results of operations.

~~Electricity Resources~~

Effective January 1, 2003, under California law (Assembly Bill 57, or AB 57), the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC ~~must review the revenues~~is also considering reallocation of certain DWR contracts for operation and costs associated with an investor-owned utility's electricity procurement plan 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. The Utility's ERRA trigger threshold for 2004 is $191 million. These mandatory adjustments will continue until January 1, 2006.dispatch purposes. The Utility has requested that the CPUC extend these mandatory adjustments through at least the 10-year period covered by the Utility's proposed long-term electricity procurement plan, or LTP, that was filed with the CPUC in July 2004 (see further discussion below). The CPUC's review of the Utility's procurement activities examines the Utility's least-cost dispatch of its resource portfolio, including the DWR allocated contracts, fuel expenses for the Utility's electricity generation facilities, contract administration (including administration of the DWR allocated contracts), and the Utility's electricity procurement contracts. As a result of this review, some of the Utility's procurement costs could be disallowed up to a maximum of two times the Utility's administration costs associated with procurement. At September 30, 2004, the ERRA had an under-collected balance of approximately $85 million, which is below the 5% trigger for mandatory adjustment of rates. This balance reflec ts the decision issued by the CPUC on June 9, 2004, adopting an interim ERRA revenue requirement of $2.189 billion for 2004. The rate changes associated with the approved interim revenue requirement were effective as of September 1, 2004. The Utility's ERRA and related account balances for 2004 are subject to further true-up based on the final decision on the Utility's 2004 ERRA revenue requirement, which is expected during the fourth quarter of 2004. In addition, in the Utility's 2005 ERRA application filed in June 2004, the Utility requested authority to amortize routine over and under-collections in the ERRA annually to coincide with January 1 rate changes. A final decision on the 2005 ERRA application, in which the Utility requested a revenue requirement of $2.140 billion, is expected by the end of 2004.

Although the CPUC has no authority to review the reasonableness of procurement costs in the DWR's contracts, it may review the Utility's administration of the DWR allocated contracts. The Utility is required to dispatch its electricity resources, including the DWR allocated contracts, on a least-cost basis. The CPUC has established a maximum annual procurement disallowance for the Utility's administration of the DWR allocated contracts and least-cost dispatch of its electricity resources of two times the Utility's administration costs of managing procurement activities, or $36 million for 2004. Activities excluded from the maximum annual disallowance include fuel expenses for the Utility's electricity generation resources and contract administration costs associated with electricity procurement contracts, qualifying facility contracts and certain electricity generation expenses. It is uncertain whether the CPUC w ill modify or eliminate the maximum annual disallowance for future years. In the LTP, the Utility has requested that the CPUC clarify that the disallowance cap applies to both the allocated DWR contracts and administrative and dispatch costs related to utility-owned generation and other power purchase agreements.

The Utility and the CPUC's Office of Ratepayer Advocates, or the ORA, have agreed that there should be no disallowances in the Utility's ERRA proceeding reviewing procurement activities during the period from January 1, 2003 through December 31, 2003 and have jointly recommended that the CPUC close the record period. The Utility cannot predict whether a disallowance will result based on information reviewed or audited by the ORA in future ERRA filings or the size of any potential disallowance. In October 2004, the CPUC issued a draft resolution on the Utility's 2003 quarterly short-term procurement transaction compliance filings concluding that the Utility's procurement transactions are in compliance with its CPUC approved 2003 Short-Term Procurement Plan.

In addition, the CPUC may require the Utility or the Utility may elect to satisfy all or a part of its residual net open position by developing or acquiring additional generation facilities. This could result in significant additional capital expenditures or other costs and may require the Utility to issue additional debt, which the Utility may not be able to issue on reasonable terms, or at all. In addition, if the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility's LTP assumes that power plants currently providing 2,000 megawatts, or MW, of generation to the Utility will retire within the next five or six years. The Utility has requested that the CPUC approve the Utility's solicitation of offers for utility-owned generation development and for generation to be provided under long-term contracts for approximately 1,200 MW of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010. The Utility released drafts of these two requests for offers, or RFOs, for comment in October 2004 and will issue the RFOs in November 2004. The Utility has requested that the CPUC issue a decision on its LTP by the end of 2004 and that the CPUC act to approve the proposed winning bidders from the RFOs no later than June 2005. The Utility also has requested that, at the time the CPUC approves an award for the turnkey development of a new utility-owned generation facility, the CPUC also authorize a reasonable cost for the facility to be placed into rate base. After consideration of new customer energy efficiency programs, an increase in purchase of renewable energy (as further discussed below), and a portfolio of short and medium term power purchase contracts, the Utility's target over the 10-year planning horizon is to own 50% of the new generation resources to be developed, with the remaining 50% of such resources to be purchased under long-term contracts of 5 to 20 years duration.

In the LTP filing, the Utility has requested that the CPUC adopt a policy that recognizes and addresses the fact that credit rating agencies will consider obligations under long-term power purchase contracts to have debt-like characteristics that will adversely affect the Utility's credit ratios which may, in turn, adversely affect the resulting credit ratings. The Utility has proposed that the CPUC evaluate the "debt equivalence" impacts when the Utility and the CPUC evaluate the bids for various long-term commitments and that the CPUC mitigate the resulting debt equivalence impacts in subsequent cost of capital proceedings through adjustments to the Utility's authorized capital structure.

In addition, to minimize the uncertainties regarding the level of future retail load the Utility will serve, the Utility has requested that the CPUC establish five-year resource adequacy requirements for all non-utility load serving entities, or LSEs, that will ensure that these entities secure reliable electricity supplies for all of their customers far enough in advance to avoid a statewide shortage of power. Also, to assure recovery of the Utility's costs of new long-term electricity resource commitments, the Utility has requested the CPUC adopt a non-bypassable charge to be collected from all customers on whose behalf the Utility makes these new commitments, including those who subsequently receive generation from LSEs.

~~The Utility also has proposed:~~

New customer energy efficiency, or CEE, programs to reduce load with total potential expenditures of approximately $1 billion over the 10-year planning horizon. To achieve the assumed load reductions, the Utility has requested that the CPUC approve an incremental revenue requirement increase of $245 million for three additional years (2006 through 2008) of CEE programs based on the targets as proposed in the LTP. The Utility also has requested that the CPUC approve a CEE incentive mechanism to encourage program success in achieving the proposed CEE targets.

~~The development of demand response programs in conjunction with the ISO that will result in certain, predictable load reductions.~~

In the LTP filing the Utility has assumed, under a medium load scenario, that by 2014, its procurement responsibility would be reduced by approximately 4,000 MW through a combination of (1) the continuation of current direct access levels, (2) a core/non-core program to be implemented through future legislation authorizing larger customers to participate in direct access on a phased-in basis starting as early as 2007, and (3) robust participation among smaller customers in community choice aggregation starting as early as 2006.

~~The CPUC has issued a schedule indicating that a decision on the Utility's LTP should be issued by the end of 2004. The Utility cannot predict the ultimate outcome of this matter.~~

On October 28, 2004, the CPUC voted to accelerate the electricity planning reserve requirement it established in January 2004. Under the accelerated schedule, California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. The previous deadline was January 1, 2008. This accelerated phase-in will increase the amount of the electric resource commitments that the Utility would be required to make.

The California Governor has suggested that the requirement for each California investor-owned electric utility 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 so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017, be amended to reach the 20% goal by 2010 instead. The California Senate has introduced a bill reaffirming the proposed accelerated requirement. In the LTP, the Utility estimates that it will achieve the proposed requirement of purchasing 20% of its retail sales from renewable resources by 2010 under the medium load scenario. Since the Utility is currently on target to meet these proposed recommendations, if this Senate bill is ultimately passed and approved by the CPUC, the Utility does not expect that the recommendations will have a material impact on the Utility's future 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 from January 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the markets operated by the ISO and the California Power Exchange, or the PX. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2 , 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding 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 the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed), to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by the first quarter of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the variou s FERC orders in the Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule being developed by the Ninth Circuit, the parties are required to submit briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds.

The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which appellate review is expected. 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.

~~El Paso Settlement~~

In June 2003, the Utility, along with SCE, the state of California and a number of other parties, entered into a settlement agreement with El Paso Natural Gas Company, or El Paso, which resolves all potential and alleged causes of action against El Paso for its part in alleged manipulation of natural gas and electricity commodity and transportation markets during the California energy crisis. In October 2003, the CPUC approved an allocation of these settlement proceeds. The Utility's natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $215 million of the settlement proceeds over the next 15 to 20 years. In December 2003, the Utility recorded a receivable and corresponding regulatory liability of approximately $200 million for the discounted present value of the future payments. The El Paso settlement became effective in June 2004, at which ti me El Paso made upfront payments totaling approximately $568 million to all parties to the settlement agreement. The Utility's share of El Paso's $568 million upfront payment was approximately $25 million for its natural gas customers and approximately $70 million for its electricity customers. The remaining payments will be made in equal semi-annual installments over the next 15 to 20 years.

~~Enron Settlement~~

~~Williams Settlement~~

~~Dynegy Settlement~~

~~Duke Settlement~~

~~Natural Gas Supply and Transportation~~

On August 27, 2004, the Utility and all other active parties in the Utility's gas transmission and storage 2005 rate case, including The Utility Reform Network, or TURN, and the ORA filed a joint motion with the CPUC seeking approval of a proposed comprehensive settlement agreement, or the Gas Accord III Settlement. If approved by the CPUC, the proposed settlement will, among other things, set the Utility's gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005. The proposed settlement agreement would maintain the current Gas Accord market structure and service options.

The proposed settlement agreement provides a gas transmission and storage revenue requirement of approximately $428.5 million for 2005 and a two percent per year increase for the following two years. For the year 2006, the revenue requirement would be approximately $436.6 million, and for the year 2007, the revenue requirement would be approximately $444.9 million. The proposed settlement agreement also provides that the Utility should file its next gas transmission and storage rate case application no later than February 9, 2007, for rates to be in effect by January 1, 2008.

~~No comments were received by the CPUC in opposition to the settlement. A final decision is expected before the end of the year. PG&E Corporation and the Utility are~~ unable to predict the ~~ultimate~~ outcome of this ~~proceeding.~~

~~FERC Transmission Rate Cases~~

~~In January and October 2003,~~proceeding, nor the Utility filed applications with the FERC requesting authority to recover its annual electricity transmission retail revenue requirements for 2003 and 2004. During the third quarter of 2004, the FERC issued final orders on these applications, which did not have a material impact on the Utility's 2004 results of operations. The current approved rates will remain in effect until the Utility's next rate application.potential financial impact.

~~Electric Restructuring Costs Account Application~~

On April 16, 2004, the Utility filed an updated Electric Restructuring Costs Account application for recovery of distribution related electric industry restructuring related revenue requirements totaling $117 million for the period 1999 through 2002. Revenue requirements associated with these ongoing activities in 2003 and afterwards are included in the 2003 GRC, discussed above. The Settlement Agreement requires timely resolution of this proceeding by the CPUC.

~~The Utility has requested that the $117 million revenue requirement increase become effective January 1, 2005 and be recovered through the Distribution Revenue Adjustment Mechanism.~~

A proposed settlement agreement to resolve issues in this proceeding was reached between the Utility, ORA, Aglet Consumer Alliance, and TURN and submitted to the CPUC for approval on August 13, 2004. Under the proposed settlement agreement, the Utility would be authorized to collect $80 million in revenue requirements to recover the distribution related electric industry restructuring costs through rates charged to certain of the Utility's customers beginning January 1, 2005. Additionally, beginning January 1, 2007, the Utility would remove from rate base all remaining net plant in service associated with the Utility's capital plant at issue in this application, projected to be approximately $30 million at the end of 2006. If the CPUC approves the proposed settlement, the Utility would record a net pre-tax regulatory asset of approximately $50 million, resulting in an increase of approximately $30 million in after - -tax net income. The Utility has not recorded a regulatory asset for the costs it has incurred as of September 30, 2004 since these costs did not meet the applicable accounting probability standard under SFAS No. 71. A final decision is expected before the end of the year. PG&E Corporation and the Utility are unable to predict the ultimate outcome of this proceeding.

Diablo Canyon Steam Generator Replacement Projects

~~In connection with~~

On February 24, 2005 the ~~Utility's efforts to replace turbines and steam generators and other equipment at the two nuclear operating units at~~CPUC issued an interim decision on the Utility's Diablo Canyon ~~nuclear power plant,~~Steam Generator Replacement Project, or ~~Diablo Canyon, in 2003,~~SGRP, application. The interim decision concluded that the SGRP is cost-effective and $706 million, as adjusted for actual inflation and cost of capital, is a reasonable estimate of the SGRP cost. The interim decision also concluded that an after-the-fact reasonableness review of the SGRP cost is not required, but not precluded either. It adopts a maximum allowable SGRP cost cap of $815 million as adjusted for actual inflation and cost of capital, and the Utility ~~established~~will not be allowed to recover SGRP costs in excess of this amount. The Utility will file an advice letter to request authority to implement a ~~steam generator replacement project~~rate increase, subject to refund, for each ~~unit. These projects~~unit at the time each unit begins commercial operations. After installation is complete, and both units are operational, the Utility wi ll be required to file an application to include the procurement of replacement steam generators, the work to remove and replace the steam generators during planned refueling outages, and the project management and support for the approximately five year effort. The procurement of replacement steam generators has a long lead time, requiring about 40 months for delivery to Diablo Canyon. Therefore, the Utility entered into contracts with Westinghouse Electric Company LLC, or Westinghouse, in August 2004, for the design, fabrication and delivery of eight steam generators. The Utility plans to replace Unit 2's steam generators in 2008 and to replace Unit 1's steam generators in 2009. Under the contracts the Utility must pay for all work done and pro-rated profit up to the time the contracts are completed or cancelled. The contracts require progress payments in line with actual expenditures for materials and work completed over the life of the contracts. These payments are included in the projects' overall cash flow shown below.

~~In January 2004, the Utility filed an application with the CPUC seeking approval of the projects and authorization to recover the projected $706 million capital expenditures~~costs permanently in rates. The ~~CPUC has indicated that it will issue an~~ interim ~~opinion on~~decision does not approve or disapprove the ~~cost benefits~~SGRP, guarantee or approve the recovery of any expenditures related thereto, or dictate the ~~projects in the first quarter of 2005 to support proceeding with the initial investments required to maintain a 2008/2009 implementation schedule, and a final decision, including incorporation~~outcome of the environmental ~~impact~~ review ~~for~~of the ~~projects~~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. In order to maintain the 2008 and 2009 steam generator replacement schedule required to coordinate Diablo Canyon's steam generator replacement outages with similar replacements being performed at San Onofre, the other large nuclear generating station serving California, initialAs of March 31, 2005, expenditures on the ~~contracts discussed above~~project of approximately ~~$25~~$26.7 million have been incurred. These expenditures are expected to ~~be incurred prior~~increase to ~~receiving~~approximately $65 million by September 2005 when the CPUC's ~~interim opinion.~~final decision approving the project is expected. If the CPUC approves the project, the Utility estimates it would spend an additional $14.5 million in the last quarter of 2005. If the CPUC does not approve the projects, then the Utility will terminate the contracts and seek ~~recovery of~~to recover the project costs that it incurred project-costs. These costs would include: costs of design and procurement at cancellation, costs of engineering and project management up to cancellation, and all costs associated with the CPUC application process. The Utility would seek recovery of these costsbefore termination from customers through the ~~abandoned~~a bandoned project process. ~~The cash flow for the project is shown below.~~

(in millions)
2004
$
25
2005
74
2006
124
2007
144
2008
204
Thereafter
135
Total
$
706

~~Spent Nuclear Fuel Storage Proceedings~~

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities. Under the Utility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018. 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 approximately 2007. Therefore, the Utility applied to the NRC for authorization to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. After conducting hearings on the request, the NRC granted authorization o n March 22, 2004. However, several intervenors in that proceeding filed an appeal of the NRC's decision in the Ninth Circuit. Oral arguments on that appeal are expected in the last quarter of 2004 with a decision anticipated in the first half of 2005. Under the California Coastal Act, the Utility is also required to obtain authorization to build the on-site dry cask storage facility from the county where the facility would be located. On April 20, 2004, San Luis Obispo County issued a permit to the Utility that contained a number of conditions. The Utility, along with several other interested parties, has filed appeals of the permit with the California Coastal Commission. Those appeals are expected to be decided by the end of 2004. As a contingency, the Utility will file in November 2004 to pursue NRC approval of another storage option to install a temporary storage rack in each unit that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. This temporary option would not require local or California Coastal permission permits to be implemented. During this additional period of time, if the dry cask storage has not yet been built, the Utility also could pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2024 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and 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.

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

~~In May 2004, 2003, 2002, 2001, and 2000,~~On April 4, 2005, the Utility filed ~~its annual applications~~a motion with the CPUC ~~claiming~~seeking approval of a settlement agreement entered into on April 4, 2005 between the Utility and the CPUC's Office of Ratepayer Advocates, or the ORA. The settlement agreement proposes the resolution of the Utility's claims that have been pending for several years for shareholder incentives ~~totaling approximately $113 million~~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 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 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 ~~efficiency program activities. These applications remain subject~~savings anticipated in the Utility's shareholder incentive claims are being realized. The parties have proposed that the Utility receive shareholder incentives of approximately $186 million to ~~verification~~resolve the Utility's claims in the pending and ~~approval~~future AEAPs. The parties have proposed that approximately $160 million be collected from electric customers and approximately $26 million be collected from gas customers, in proportion to the relative allocations of the original claims.

PG&E Corporation and 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 the quarter in which the settlement agreement is approved by the CPUC. ~~The~~

Pending CPUC Investigations

On March 17, 2005, the CPUC issued an order that institutes an 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 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.The CPUC's order notes that the CPUC has ~~authorized~~authority to impose penalties in the amount of $500 to $20,000 per day per offense for violations 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 and power outage that originated at the Mission Street substation on March 26, 2005, that affected approximately 23,500 of the Utility's customers.

The CPUC's Consumer Protection and Safety Division, or CPSD, will make a penalty recommendation in July 2005. A final decision on the investigation is expected during the fourth quarter of 2005. PG&E Corporation and the Utility ~~to recognize only an insignificant amount of these incentives in its results of operations. There~~ are ~~also a number of forward-looking proceedings regarding program administration and potential new incentive mechanisms for energy efficiency. The Utility considers that it is too early~~unable to predict whether the outcome of this matter will have a material adverse effect on their results of operation or financial condition.

The CPUC ~~will allow it to continue administering energy efficiency programs~~also is conducting an investigation into the Utility's billing and ~~earning incentives based~~collection practices that has been opened at the request of The Utility Reform Network, or TURN. Although a definitive schedule has not yet been set, on March 22, 2005, the CPUC administrative law judge presiding over the investigation considered a schedule that contemplated the following:

September 22, 2005		Reports due from the CPSD, TURN, and other parties
December 20, 2005		Utility's response to reports due
Late January - early February 2006		Parties file reply comments to the Utility's response
April - May 2006		Hearings

If the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules, the CPUC may impose penalties on the ~~performance~~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 ~~programs.~~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 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,~~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 ~~derivative instr uments,~~instruments, including forward contracts, futures, swaps, options, and other instruments and ~~agreements.~~

~~The Utility uses~~agreements, most of which are accounted for as derivative ~~instruments only~~instruments. Some contracts are accounted for ~~non-trading purposes (~~~~i.e.~~, risk mitigation) and not for speculative purposes. The Utility uses derivative instruments to manage the risks associated with ownership of assets, liabilities, committed transactions or probable forecasted transactions, or for complying with and managing risks associated with regulatory programs. The Utility enters into derivative instruments in accordance with approved risk management policies adopted by a risk oversight committee composed of senior officers and only after the risk oversight committee approves appropriate risk limits. The organizational unit proposing the activity must successfully demonstrate that the derivative instrument satisfies a business need and that the attendant risks will be adequately measured, monitored and controlled.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, ~~the terms~~holders of the Convertible Subordinated Notes ~~entitle~~are entitled to receive pass-through dividends at the ~~note holders to participate in any dividends declared and paid on~~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. On April 15, 2005, PG&E ~~Corporation's common shares based~~Corporation paid approximate ly $6 million of pass-through dividends to 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 ~~their equity conversion value.~~June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including liquidated damages and pass-through dividends, if any).

In accordance with 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 PG&E Corporation's Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance ~~Sheets as a non-current liability (in Non-Current Liabilities - Other).~~Sheet at March 31, 2005. At ~~September 30, 2004,~~March 31, 2005, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately ~~$70~~$92 million ~~an increase~~of which $20 million is classified as a current liability (in Current liabilities-Other) and $72 million is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in mark to market fair value ~~of approximately $3 million, net of taxes, from June 30, 2004, and a year-to-date increase of approximately $41 million, net of taxes,~~ for the ~~nine-month period~~quarter ended ~~September 30,~~March 31, 2005, wa s immaterial, and approximately $32 million, pre-tax, for the quarter ended March 31, 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 electricity needed to meet the demands of customers, plus applicable 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 electricity purchase contracts, or entering into new electricity 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;
·	Planning reserve and operating requirements;
·	The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and
·	The acquisition, retirement or ~~other~~ closure of ~~the Utility's~~Utility generation facilities.

In addition, unexpected outages at the Utility's generation 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. The Utility expects to satisfy at least some of the residual net open position through new contracts. In ~~July~~December 2004, the ~~Utility submitted its~~CPUC approved, with certain modifications, the Utility's long-term ~~integrated energy resource~~electricity procurement plan, or ~~LTP,~~LTPP, for the 2005 through 2014 ~~period to~~period. The LTPP is detailed in the ~~CPUC. In this LTP, to meet its net open position,~~"Regulatory Matters" section of the ~~Utility proposes:~~

·	Entry into short- and mid-term power purchase agreements over the next four years with existing market resources to ensure adequate supply of electricity in the period before new generation facilities are assumed to become operational. The Utility has requested immediate authority from the CPUC to execute short and mid- term contracts under its existing short-term procurement plan.
·	The development of new utility-owned generation and generation to be purchased under long-term contracts particularly for the period of 2008 to 2010 when it is assumed that there will first be a need for additional generation facilities.
·	An increase in the percentage of renewable energy resources in the Utility's generation portfolio in accordance with the objective adopted in Senate Bill 1078. The LTP medium load scenario forecasts that by 2010, 20% of the Utility's retail load will be met by a combination of purchases from renewable energy providers and the re-powering of existing wind projects.

MD&A in PG&E Corporation's and the Utility's combined 2004 Annual 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 ~~CP UC~~CPUC may in the future disallow transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.

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 ~~for its long-term nuclear fuel agreements~~ in order to diversify its commitments and ~~ensure~~provide security of supply.

Nuclear fuel purchases are subject to tariffs of up to 8% on imports from certain countries. ~~The~~In the past, the Utility's long-term nuclear fuel ~~costs have~~contracts were not ~~increased based on the imposed tariffs because the terms of the Utility's existing long-term contracts do not include~~subject to these ~~costs.~~tariffs. However, these contracts ~~begin to expire in~~expired at the end of 2004, and prices under ~~new~~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 compared with the domestic supply, uranium prices ~~are~~have been trending higher in ~~2004.~~2005. During the quarter ended March 31, 2005, the Utility did not enter into any nuclear fuel purchase agreements.

As the Utility replaces ~~existing~~ contracts ~~ending in~~that expired at the end of 2004 with new higher priced uranium contracts, ~~will raise~~ nuclear fuel ~~costs.~~costs will rise. The Utility is expected to partially offset these higher prices ~~with reduced costs~~by executing a portfolio of near- and long-term contracts for ~~other~~ nuclear fuel components. 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

The Utility generally enters into physical and financial natural gas commodity contracts ~~of up~~from one to ~~one and one-half years~~30 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 ~~of natural~~and gas ~~purchased for its core customers.~~storage costs.

Under the Core Procurement Incentive Mechanism, or CPIM, the Utility's purchase costs for a ~~twelve month~~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 ~~are~~ar e 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 will be at least as large as the reported value-at-risk. The Utility's value-at-risk calculated under this methodology was approximately $35 million at March 31, 2005. The Utility's high, low, and average value-at-risk during the three months ended March 31, 2005 were approximately $43 million, $34 million and $38 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 and not capturing the in tra-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 ~~change~~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 ~~if prices moved against current positions, the change in~~ the value of the portfolio resulting from a one-day price movement would not ~~exceed~~decline by more than $5 million.~~The~~ 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. It is also a way to measure the effectiveness of hedge strategies on a portfolio.

The Utility's value-at-risk for its transportation and storage portfolio calculated under the methodology used prior to January 1, 2005 was approximately ~~$4.2~~$2 million at ~~September 30, 2004~~March 31, 2005 and approximately ~~$6.0~~$3 million at ~~September 30, 2003.~~March 31, 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 ~~first nine~~three months ofended March 31, 2005 were approximately $4 million, $2 million and $2 million, respectively. The Utility's high, low and average transportation and storage value-at-risk during the three months ended March 31, 2004 were approximately ~~$6.4~~$6 million, ~~$1.9~~$3 million and ~~$3.5~~$4 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 ~~September 30, 2004,~~March 31, 2005, if interest rates changed by 1% for all current variable rate debt ~~held~~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 $2.0 billion at ~~September 30, 2004~~March 31, 2005 and approximately ~~$2.5~~$2.2 billion at December 31, ~~2003.~~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 ~~$63~~$88 million at ~~September 30, 2004~~March 31, 2005 and approximately ~~$68~~$93 million at December 31, ~~2003~~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~~the se customers is not considered 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 ~~which could include obtaining~~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 ~~first nine~~three months ~~of 2004,~~ended March 31, 2005, the Utility recognized no material losses due to contract defaults or bankruptcies. At ~~September 30, 2004,~~March 31, 2005, there were two counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. ~~These two~~Both of these counterparties were investment grade, ~~counterparties represented~~representing a total of approximately ~~46%~~47% of the Utility's net wholesale credit exposure.

CRITICAL ACCOUNTING POLICIES

The preparation of Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are 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," 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. During the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations.

Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged 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, ~~ALJ~~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 ~~accounts,~~a ccounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to ~~reco rd~~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 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 ~~September 30, 2004,~~March 31, 2005, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately ~~$7.5~~$7.4 billion and regulatory liabilities (including current balancing accounts payable) of approximately ~~$4.4~~$4.5 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. ~~As a result of CPUC decisions approving the Settlement Agreement and implementing various ratemaking mechanisms,~~At March 31, 2005, the Utility ~~no longer records frozen electric rates and surcharges directly to earnings as it~~ had ~~in 2003. Instead, the Utility collects cost-of-service based electric rates that are the sum of specific revenue requirements. As a result, changes~~recorded approximately $500 million in unbilled ~~revenues no longer have a material impact on the Utility's results of operations.~~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 ~~September 30, 2004,~~March 31, 2005, the Utility's accrual for undiscounted environmental liability was approximately ~~$342~~$408 million. The Utility's undiscounted future costs could increase to as much as ~~$464~~$571 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 March 31, 2005, the Utility's estimated cost of retiring these assets was approximately $1.3 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 complexity 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.

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 ~~$77~~$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' Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on its financial position or results of operations.

In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million relating to the 1999 and 2000 audit. The IRS ~~has~~ completed its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns during the third quarter of ~~2004 and has assessed additional taxes. Since~~2004. As a result of the completion of this audit, PG&E Corporation ~~made an advance payment to~~received a refund from the IRS of ~~$75~~$14 million in ~~the fourth quarter~~January of ~~2003, no additional tax payment is due to the IRS. Settlement of this audit does not have a material impact on PG&E Corporation's financial position or result of operations.~~2005.

The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. ~~In September 2004,~~They have indicated that they plan to complete their audit and issue a Revenue Agent Report in the second or third quarter of 2005. During their examination, the IRS has issued ~~notices of~~several proposed adjustments that ~~propose to disallow $104 million~~PG&E Corporation is currently disputing. The IRS adjustments include disallowance of synthetic fuel credits claimed on these tax returns. In addition, the IRS has proposed to disallow a number of deductions, the largest of which is abandonment ~~losses deducted~~losses/worthless deductions claimed on the 2002 tax return related to certain NEGT assets. These assets were ultimately transferred to NEGT lenders in the third quarter of 2004. ~~In addition,~~If the IRS ~~has challenged other deductions related~~includes all of its proposed adjustments in the final Revenue Agent Report, the alleged tax deficiency would approximate $400 million. Of this deficiency, approximately $104 mil lion relates to ~~NEGT prior to its Chapter 11 filing.~~the synthetic fuel credits. The remaining $296 million is timing in nature and would reverse in future periods, generally in tax years 2003-2004. PG&E Corporation ~~is disputing the IRS's proposed adjustments~~believes that it properly reported these transactions in its tax returns and will contest ~~these disallowances if the~~any IRS ~~continues to assert its current position.~~assessment.

PG&E Corporation has accrued $52 million associated with NEGT related tax liabilities. In addition, PG&E Corporation has accrued a $49 million liability to cover potential tax obligations relating to non-NEGT issues on outstanding tax audits. The Utility has accrued $63 million to cover potential tax obligations for outstanding tax audits. Considering ~~this reserve,~~these reserves, PG&E Corporation does not expect the resolution of these matters to have a ~~materia l~~material impact on its financial position or ~~result~~results of operations.

In addition, based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $86 million of federal income taxes on NEGT activities through the effective date of NEGT's plan of reorganization.

All IRS audits of PG&E Corporation's federal income tax returns prior to 1997 have been closed. ~~In addition, certain other state tax authorities are currently auditing various state tax returns.~~

Prior to July 8, 2003, the date that NEGT filed for bankruptcy protection, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, PG&E Corporation has not recognized additional income tax benefits for financial reporting purposes with respect to the losses of NEGT and its subsidiaries even though it must continue to include NEGT and its subsidiaries in its consolidated income tax returns. After its equity ownership in NEGT is cancelled on the effective date of NEGT's plan of reorganization, PG&E Corporation will no longer include NEGT or its subsidiaries in its consolidated income tax returns. In addition, any remaining deferred tax assets related to NEGT or its subsidiaries, will be reversed in discontinued operations in the Consolidated Statements of Operations at the time PG&E Corporation's equity interest in NEGT is cancelled. On October 29, 2004, NEGT's plan of reorganization under Chapter 11 became effective, at which time NEGT emerged from Chapter 11. PG&E Corporation's equity ownership in NEGT was cancelled on the effective date of NEGT's plan of reorganization.

In addition to the reversal of deferred tax assets referred to above, and based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $94 million of consolidated tax obligations in 2004 attributable to NEGT's estimated taxable income through the effective date of NEGT's plan of reorganization.

PG&E Corporation and NEGT have entered into a separate agreement under which they have agreed to take certain actions and cooperate with each other with respect to certain tax matters, including future tax returns and audits. This litigation is discussed further in Note 6 of the Notes to the Consolidated Financial Statements.

For the nine-month period ended September 30, 2003, PG&E Corporation increased its valuation allowances against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty of their realization. During this period, valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million was recorded in accumulated other comprehensive loss. No valuation allowances were recorded in the three-month period ended September 30, 2003 or during 2004.

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 position 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. Also, 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 67 of the Notes to the Condensed Consolidated Financial Statements for further ~~discussion of environmental matters and significant pending legal matters.~~discussion.

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 4:4. 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 ~~September 30, 2004,~~March 31, 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 ~~the~~ Financial Accounting Standards ~~Board's,~~Board, or FASB, revision to FASB Interpretation No. 46, ~~"Consolidation~~''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~~Corporation's and the Utility's evaluation of disclosure controls and procedures performed as of ~~September 30, 2004,~~March 31, 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~~conso lidated VIEs.

There were no changes in internal controls over financial reporting that occurred during the quarter ended ~~September 30, 2004,~~March 31, 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 67 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company Chapter 11 Filing

~~Pacific Gas~~The petitions for review of the CPUC's orders approving the Settlement Agreement that were filed by the City and ~~Electric Company's,~~County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, remain pending at the California Court of Appeal. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions.

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 ~~2003~~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 quarterly periods ended March 31 and June 30, 2004 under Part II, Item 1:~~ Legal Proceedings." For additional information, see Note 2 of the Notes to the ~~Consolidated Financial Statements.~~

~~Chapter 11 Filing of NEGT~~

On October 29, 2004, NEGT's plan of reorganization became effective and PG&E Corporation's equity interest in NEGT was cancelled. For more information regarding this matter, see PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K, in "Part I, Item 3: Legal Proceedings" and Note 4 of the Notes to theCondensed 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 - Pacific Gas and Electric Company vs. Michael Peevey, et al."~~Proceedings" in PG&E Corporation's and the Utility's combined ~~2003~~2004 Annual Report on Form ~~10-K and PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 under Part II, Item 1: Legal Proceedings."~~10-K.

In re: Natural Gas Royalties Qui Tam Litigation

For information regarding this matter, see "Part I, Item 3: Legal Proceedings" ofin PG&E Corporation's and the Utility's combined ~~2003~~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 ~~2003~~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 on Form 10-Q for the quarterly period ended March 31, 2004.~~10-K.

Compressor Station Chromium Litigation

As previously disclosed, the Utility has filed 14 summary judgment motions or motions in limine, which challenge plaintiffs' lack of admissible scientific evidence that chromium caused the injuries alleged by the test plaintiffs. The Superior Court for the County of Los Angeles, or Superior Court, began hearing arguments on two of these motions in February 2004. In February 2005, the Superior Court denied these two motions for summary judgment. The Utility has filed motions for reconsideration of these orders with the Superior Court and also filed a request with the appellate court seeking to overturn or modify the orders because they are inconsistent with recent California appellate decisions concerning the admissibility of expert testimony and the requirements for proving medical causation. After the motions for reconsideration and the request were filed, the California Supreme Court granted review of one of th ese recent appellate decisions. On April 26, 2005, the Superior Court heard argument on the motions for reconsideration, but has not yet issued a decision. For more information regarding the chromium litigation, see "Part I, Item 3: Legal Proceedings - Compressor Station Chromium Litigation" in PG&E Corporation's and the Utility's combined ~~2003~~2004 Annual Report on Form 10-K and ~~"Part II, Item 1: Legal Proceedings - Compressor Station Chromium Litigation" in PG&E Corporation's and~~Note 7 to the ~~Utility's combined Quarterly Report on Form 10-Q for~~Notes to the ~~quarterly period ended March 31, 2004.~~Condensed Consolidated Financial Statements.

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

As previously disclosed, in approving PG&E Corporation's formation as the holding company of the Utility, the California Public Utilities Commission, or the CPUC, imposed certain conditions, including an obligation by PG&E Corporation's Board of Directors to give "first priority" to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve and to operate inAt a prudent and efficient manner. The CPUC later issued decisions in which it adopted an expansive interpretation of holding companies' obligations under this condition, including the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." The CPUC also asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies. PG&E Corpo ration and the holding companies of the other major California investor-owned electric utilities appealed these decisions. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the capital requirements condition was not ripe for review. PG&E Corporation appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition.

~~With respect to the litigation pending in~~case management conference held on March 18, 2005, the San Francisco Superior Court, or ~~the~~ Superior Court, ~~at a hearing~~issued its final ruling on ~~September 8, 2004,~~rejecting the ~~Superior Court granted PG&E Corporation's request to bifurcate~~"per victim" and "per [customer] bill" standards advocated by the ~~trial on the issue of how to determine the standard~~plaintiffs to be applied in calculating the number of alleged violations ~~that plaintiffs allege have been committed. A trial on this issue has been scheduled for December 8, 2004. PG&E Corporation believes~~of California Business and Professions Code Section 17200, or Section 17200. The Superior Court found that the ~~applicable calculation methodology for civil penalties, if any violations~~appropriate standard to be applied was the "per act" test, and that the acts alleged to violate Section 17200 are "transfers of assets to [PG&E Corporation] from its utility subsidiary." Such asset transfers were ~~found, would not result in a material adverse effect on its financial condition or results~~effected primarily through the Utility's payment of ~~operations.~~

~~On October 22, 2004, Cynthia Behr dismissed with prejudice her lawsuit against~~dividends to PG&E Corporation and ~~its directors,~~through share repurchases from the date of PG&E Corporation's formation on January 1, 1997, through the end of 2000, when dividends were last paid.

Also on March 18, the Superior Court ordered plaintiffs to provide a list of the transfers that they claim are unlawful, as well as the ~~Utility's directors, in exchange~~basis for ~~PG&E Corporation's waiver of costs in~~their claim with respect to each transfer, at the ~~matter.~~next case management conference scheduled for May 10, 2005.

For more information regarding these cases, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined ~~2003~~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 on Form 10-Q for the quarterly periods ended March 31, 2004 and June 30, 2004.~~10-K.

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 March 31, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase 77,857 shares, and received 77,833 shares of PG&E Corporation common stock. As of ~~September 30, 2004, warrantholders~~March 31, 2005, warrant holders had exercised, on a net exercise basis, warrants to purchase ~~3,757,539~~4,796,876 shares, and had received ~~3,756,107~~4,795,123 shares of PG&E Corporation common ~~stock.~~stock since the warrants were issued.

Pacific Gas and Electric Company did not make any sales of unregistered equity securities during the quarter ended March 31, 2005, the period covered by this report.

Issuer Purchases of Equity Securities

Period	Period		Total Number of Shares Purchased⁽¹⁾			Average Price Paid Per Share⁽²⁾				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^{(3) (4)}				Approximate Dollar Value of Shares that may yet be Purchased Under the Plans or Programs		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

July 1 through July 31, 2004				150,000	$			25.410625				-	$		-
August 1 through August 31, 2004		-			-				-				-
September 1 through September 30, 2004		-			-				-				-
																	Preferred Stock	Common Stock		Preferred Stock		Common Stock	Preferred Stock	Common Stock	Preferred Stock		Common Stock

January 1 through January 31, 2005																January 1 through January 31, 2005	125,000⁽¹⁾	-	$	25.39375		-	-	-	-	$	975,000,000
February 1 through February 28, 2005																February 1 through February 28, 2005	-	-		-		-	-	-	-		1,050,000,000
March 1 through March 31, 2005																March 1 through March 31, 2005	-	29,489,400		-	$	35.60	-	29,489,400	-		-

Total	Total			150,000	$		25.410625				-		$		-	Total	125,000	29,489,400	$	25.39375	$	35.60	-	29,489,400	-		-


~~(1)~~


~~(1)~~	On July 31, 2004, pursuant to a mandatory sinking fund redemption provision, the Utility redeemed 150,000 shares of its 6.57% Series of First Preferred Stock.
(2)	The redemption price includes any accumulated and unpaid dividends existing as of the redemption date.
~~(3)~~(1)	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 until the program expires on December 31, 2005.															On January 31, 2005, pursuant to a mandatory sinking fund redemption provision, the Utility redeemed 125,000 shares of its 6.30% Series of First Preferred Stock. The redemption price includes any accumulated and unpaid dividends existing as of the redemption date.
~~(4)~~(2)	Also on September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $350 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Any repurchase under this program may not be initiated until PG&E Corporation redeems the full $600 million aggregate principal amount of the Senior Secured Notes due 2008, which is expected to be on November 15, 2004. Repurchases may be made from time to time after this date until the program expires on December 31, 2005.															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 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)																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. 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.

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

PG&E Corporation:

On April 20, 2005, PG&E Corporation held its annual meeting of shareholders. At the meeting, the shareholders voted as indicated below on the following matters:

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

For

Withheld
David R. Andrews
299,848,011

7,547,101
Leslie S. Biller
299,930,742

7,464,370
David A. Coulter
230,734,940

76,660,172
C. Lee Cox
298,746,220

8,648,892
Peter A. Darbee
299,920,605

7,474,507
Robert D. Glynn, Jr.
297,333,005

10,062,107
Mary S. Metz
299,595,454

7,799,658
Barbara L. Rambo
298,729,457

8,665,655
Barry Lawson Williams
297,680,081

9,715,031

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005 (included as Item 2 in the proxy statement):

For:
301,591,184
Against:
2,895,809
Abstain:
2,908,119

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

3. Consideration of management's proposal regarding the adoption of a new long-term incentive plan (included as Item 3 in the proxy statement):

For:
222,208,088
Against:
33,828,404
Abstain:
4,284,940
Broker non-vote⁽¹⁾:
47,073,680

This management proposal was approved by a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the proposal, which shares voting affirmatively also constituted a majority of the required quorum.

4. Consideration of a shareholder proposal regarding the expensing of stock options (included as Item 4 in the proxy statement):

For:
114,642,888
Against:
138,186,945
Abstain:
7,491,599
Broker non-vote⁽¹⁾:
47,073,680

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

5. Consideration of a shareholder proposal regarding radioactive wastes (included as Item 5 in the proxy statement):

For:
9,194,928
Against:
225,080,468
Abstain:
26,046,036
Broker non-vote⁽¹⁾:
47,073,680

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

6. Consideration of a shareholder proposal regarding poison pills (included as Item 6 in the proxy statement):

For:
73,493,699
Against:
180,191,178
Abstain:
6,636,555
Broker non-vote⁽¹⁾:
47,073,680

7. Consideration of a shareholder proposal regarding performance-based options (included as Item 7 in the proxy statement):

For:
99,406,293
Against:
154,791,718
Abstain:
6,123,421
Broker non-vote⁽¹⁾:
47,073,680

8. Consideration of a shareholder proposal regarding future golden parachutes (included as Item 8 in the proxy statement):

For:
142,467,316
Against:
113,113,566
Abstain:
4,740,550
Broker non-vote⁽¹⁾:
47,073,680

This shareholder proposal was approved by a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the proposal, which shares voting affirmatively also constituted a majority of the required quorum.

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

Pacific Gas and Electric Company:

On April 20, 2005, Pacific Gas and Electric Company, or the Utility, held its annual meeting of shareholders. Shares of capital stock of Pacific Gas and Electric Company consist of shares of common stock and shares of first preferred stock. As PG&E Corporation and a subsidiary own all of the outstanding shares of common stock, they hold approximately 95% of the combined voting power of the outstanding capital stock of the Utility. PG&E Corporation and the ~~Utility contained in Part I, Management's Discussion and Analysis~~subsidiary voted all of ~~Financial Condition and Results~~their respective shares of ~~Operations,~~common stock for the nominees named in the ~~section entitled "Dividends~~2005 joint proxy statement and ~~Share Repurchases" is incorporated herein~~for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005. The balance of the votes shown below was cast by ~~reference.~~holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters:

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

For

Withheld
David R. Andrews
335,101,496

134,171
Leslie S. Biller
335,093,610

142,057
David A. Coulter
334,812,805

422,862
C. Lee Cox
335,097,258

138,409
Peter A. Darbee
335,098,109

137,558
Robert D. Glynn, Jr.
335,092,033

143,634
Mary S. Metz
335,086,883

148,784
Barbara L. Rambo
335,087,579

148,088
Gordon R. Smith
335,098,589

137,078
Barry Lawson Williams
335,090,698

144,969

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005 (included as Item 2 in the proxy statement):

For:
335,126,354
Against:
43,606
Abstain:
65,707

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 Utility's, earnings to fixed charges ratio for the three months ended ~~September 30, 2004,~~March 31, 2005, was ~~3.72.~~3.27. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended ~~September 30, 2004,~~March 31, 2005, was ~~3.51.~~3.09. 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 secured bonds, respectively.

ITEM 6. EXHIBITS

4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A.
10.1	Master Confirmation dated March 4, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.2	First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004 (previously filed with PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99), among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New York
10.3	Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders
10.4*	PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed April 25, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
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: ~~November 2, 2004~~May 4, 2005

EXHIBIT INDEX

4.1	Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A.
10.1	Master Confirmation dated March 4, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.2	First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004 (previously filed with PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99), among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New York
10.3	Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders
10.4*	PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed April 25, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
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.

(in millions)	September 30, 2004		December 31, 2003

Settlement Regulatory Asset	$	3,256	$	-
Utility retained generation regulatory assets		1,200		-
Rate reduction bond assets	815		1,054
Regulatory assets for deferred income tax	470		324
Unamortized loss, net of gain, on reacquired debt	351		277
Qualifying facilities restructuring costs	144		151
Environmental compliance costs	177		139
Regulatory assets associated with Plan of Reorganization	174		-
Other, net	48		56

Total regulatory assets	$	6,635	$		2,001

	Hedging Transactions in Accordance with SFAS No. 133		Foreign Currency Translation Adjustment		Retirement Plan Remeasurement		Other		Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2002	$	(90)	$	(3)	$	-	$	-	$	(93)
Period change in:
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133	(5)		-		-		-		(5)
Net reclassification to earnings	17		-		-		-		17
Other	-		3		(60)		1		(56)

Balance at September 30, 2003	$	(78)	$	-	$	(60)	$	1	$	(137)



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

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

	Pension Benefits Nine Months Ended September 30				Other Benefits Nine Months Ended September 30

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	146	$	127	$	24	$	22
Interest cost	361		335		63		59
Expected return on plan assets	(422)		(381)		(57)		(46)
Amortization of transition obligation	4		10		19		19
Amortization of prior service cost	41		32		9		1
Amortization of recognized loss	6		34		-		1
Settlement loss	1		2		-		-

Net periodic benefit cost	$	137	$	159	$	58	$	56

(in millions)
Sources			Uses


First Mortgage Bonds	$	6,700	Payments to Creditors	$	8,394
Term Loans	799		Disputed Claims Escrow	1,843
Accounts Receivable Financing Facility	350

Total Debt Financing	7,849
Cash Used to Pay Claims	2,388

Sources of Funds for Claims	10,237		Uses of Funds for Claims	10,237

Reinstated Pollution Control Bond-Related Obligations	814		Reinstated Pollution Control Bond-Related Obligations	814
Reinstated Preferred Stock	421		Reinstated Preferred Stock	421
Cash on Hand	225		Preferred Dividends	93
			Environmental Measures	10
			Transaction Costs	122

Total Sources of Funds	$	11,697	Total Uses of Funds	$	11,697

(in millions)	Settlement Regulatory Asset		Utility Retained Generation Regulatory Assets		Total


Authorized, pre-tax, January 1, 2004	$	3,730	$	1,249	$	4,979
Amortization from January 1 to March 31, 2004	(58)		(21)		(79)

Recognition of regulatory assets, pre-tax, March 31, 2004	3,672		1,228		4,900
Deferred income taxes	(1,496)		(500)		(1,996)

Recognition of regulatory assets, after tax, March 31, 2004	2,176		728		2,904
Offsets of supplier settlements, after-tax	(8)		-		(8)

Net regulatory assets, after-tax, March 31, 2004	$	2,168	$	728	$	2,896

					Amount Previously Recorded in 2003

	Impact Related to						Net 2004 Adjustment

(in millions)	2003		2004


Electricity revenue	$	273	$	152	$	268	$	157
Natural gas revenue	52		25		-		77
Electricity attrition	-		48		-		48
Natural gas attrition	-		9		-		9
Regulatory assets, net	(17)		158		-		141

Total	$	308	$	392	$	268	$	432

	Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)	2004		2003		2004				2003

Electric revenues	$	2,909	$	2,771		$	7,218	$		7,134
DWR pass-through revenue	(560)		(291)		(1,479)				(1,642)

Subtotal	2,349		2,480		5,739				5,492
Miscellaneous	(307)		29		163				429

Total electric operating revenues	$	2,042	$	2,509		$	5,902		$	5,921

	2004						2005

		Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost


Long-term debt	5.82%		48.2%		2.81%		5.94%		45.5%		2.70%
Preferred stock	6.76%		2.8%		0.19%		6.42%		2.5%		0.16%
Common equity	11.22%		49.0%		5.50%		11.60%		52.0%		6.03%
Return on rate base					8.49%						8.90%

	For	Withheld


David R. Andrews	299,848,011	7,547,101
Leslie S. Biller	299,930,742	7,464,370
David A. Coulter	230,734,940	76,660,172
C. Lee Cox	298,746,220	8,648,892
Peter A. Darbee	299,920,605	7,474,507
Robert D. Glynn, Jr.	297,333,005	10,062,107
Mary S. Metz	299,595,454	7,799,658
Barbara L. Rambo	298,729,457	8,665,655
Barry Lawson Williams	297,680,081	9,715,031

For:	222,208,088
Against:	33,828,404
Abstain:	4,284,940
Broker non-vote⁽¹⁾:	47,073,680

For:	114,642,888
Against:	138,186,945
Abstain:	7,491,599
Broker non-vote⁽¹⁾:	47,073,680

For:	9,194,928
Against:	225,080,468
Abstain:	26,046,036
Broker non-vote⁽¹⁾:	47,073,680

For:	73,493,699
Against:	180,191,178
Abstain:	6,636,555
Broker non-vote⁽¹⁾:	47,073,680

For:	99,406,293
Against:	154,791,718
Abstain:	6,123,421
Broker non-vote⁽¹⁾:	47,073,680

For:	142,467,316
Against:	113,113,566
Abstain:	4,740,550
Broker non-vote⁽¹⁾:	47,073,680

	For	Withheld


David R. Andrews	335,101,496	134,171
Leslie S. Biller	335,093,610	142,057
David A. Coulter	334,812,805	422,862
C. Lee Cox	335,097,258	138,409
Peter A. Darbee	335,098,109	137,558
Robert D. Glynn, Jr.	335,092,033	143,634
Mary S. Metz	335,086,883	148,784
Barbara L. Rambo	335,087,579	148,088
Gordon R. Smith	335,098,589	137,078
Barry Lawson Williams	335,090,698	144,969