



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, 2003~~March 31, 2004 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, ~~November 10, 2003:~~April 28, 2004:
PG&E Corporation			~~414,758,513~~398,752,930 shares (excluding 23,815,500shares 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, 2003~~MARCH 31, 2004
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of ~~Income~~Operations		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company, A Debtor-In-Possession
		Condensed Consolidated Statements of ~~Income~~Operations		87
		Condensed Consolidated Balance Sheets		98
		Condensed Consolidated Statements of Cash Flows		1110
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	1211
	NOTE 2:		The Utility Chapter 11 Filing	2019
	NOTE 3:		Debt	2623
	NOTE 4:		Discontinued Operations	2827
	NOTE 5:		Price Risk Management	3128
	NOTE 6:		Commitments and Contingencies	33
	~~NOTE 7:~~		~~Segment Information~~	46
	~~NOTE 8:~~		~~Employee Benefit Plans~~	4730

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			4840
	Results of Operations			47
	Liquidity and Financial Resources			51
	~~Results of Operations~~			58
	~~Cash Flows~~			65
	Capital Expenditures and Commitments			6855
	Regulatory Matters			6856
	Risk Management Activities			8063
	Critical Accounting Policies			8566
	Accounting Pronouncements Issued But Not Yet Adopted			8767
	Taxation Matters			8767
	Additional Security Measures			88
	~~Other Long-Term Capital Expenditures~~			88
	~~Utility Customer Information System~~			8968
	Environmental and Legal Matters			89
	~~Other Matters~~			8968

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			9069
ITEM 4.	CONTROLS AND PROCEDURES			9069

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			9170
ITEM 2.2.	CHANGES IN SECURITIES AND USE OF PROCEEDS			9472
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES			9472
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			73
ITEM 5.	OTHER INFORMATION			9676
ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K			9777

SIGNATURES				~~100~~81

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in millions, except per share amounts)
Three months ended
Nine months ended
September 30,
September 30,
2003
2002
2003
2002
Operating Revenues
Electric
$
2,524
$
2,483
$
5,823
$
6,454
Natural gas
579
464
2,074
1,654
Total operating revenues
3,103
2,947
7,897
8,108
Operating Expenses
Cost of electricity
679
550
1,725
874
Cost of natural gas
233
108
1,010
586
Operating and maintenance
690
865
2,110
2,280
Depreciation, amortization, and decommissioning
312
314
910
881
Reorganization professional fees and expenses
16
41
116
75
Total operating expenses
1,930
1,878
5,871
4,696
Operating Income
1,173
1,069
2,026
3,412
Reorganization interest income
9
17
36
58
Interest income
6
3
13
2
Interest expense
(342)
(371)
(857)
(971)
Other income (expense), net
(5)
60
(10)
59
Income Before Income Taxes
841
778
1,208
2,560
Income tax provision
333
299
454
1,028
Income From Continuing Operations
508
479
754
1,532
Discontinued Operations
Gain/(Loss) from operations of NEGT, Inc.
(net of income tax benefit of $10 million and $85 million for the three months ended September 30, 2003, and 2002, and $230 million and $257 million for the nine months ended September 30, 2003, and 2002)
2
(13)
(365)
(156)
Net Income Before Cumulative Effect of Changes
in Accounting Principles
510
466
389
1,376
Cumulative effect of changes in accounting principles, $(8) million and $(103) million related to discontinued operations for the nine months ended September 30, 2003 and 2002 (net of income tax benefit of $4million and $42 million for the nine months ended September 30, 2003, and 2002)
-
-
(6)
(61)
Net Income
$
510
$
466
$
383
$
1,315
Weighted Average Common Shares Outstanding, Basic
387
373
384
368
Earnings Per Common Share
from Continuing Operations, Basic
$
1.31
$
1.28
$
1.96
$
4.16
Net Earnings Per Common Share, Basic
$
1.32
$
1.25
$
1.00
$
3.57
Earnings Per Common Share
from Continuing Operations, Diluted
$
1.24
$
1.22
$
1.86
$
4.06
Net Earnings Per Common Share, Diluted
$
1.24
$
1.19
$
0.96
$
3.49
See accompanying Notes to the Condensed Consolidated Financial Statements.

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

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

		2004		2003

Operating Revenues
Electric		$	1,791	$		1,305
Natural gas		931		828

Total operating revenues		2,722		2,133

Operating Expenses
Cost of electricity		561		544
Cost of natural gas		578		471
Operating and maintenance		816		711
Recognition of regulatory assets		(4,900)		-
Depreciation, amortization and decommissioning		312		310
Reorganization professional fees and expenses		2		35

Total operating (gain) expenses		(2,631)		2,071

Operating Income		5,353		62
Reorganization interest income		8		10
Interest income		6		2
Interest expense		(231)		(255)
Other expense, net		(27)		8

Income (Loss) Before Income Taxes		5,109		(173)
Income tax provision (benefit)		2,076		(90)

Income (Loss) From Continuing Operations		3,033		(83)
Discontinued Operations
Loss from operations of NEGT (net of income tax benefit of $156 million for the three months ended March 31, 2003)		-		(265)

Net Income (Loss) Before Cumulative Effect of Changes
in Accounting Principles		3,033		(348)
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 benefit of $1 million)	-			(6)

Net Income (Loss)		$	3,033	$	(354)



Weighted Average Common Shares Outstanding, Basic		393		382

Earnings (Loss) Per Common Share
from Continuing Operations, Basic		$	7.36	$	(0.22)



Net Earnings (Loss) Per Common Share, Basic		$	7.36	$	(0.93)



Earnings (Loss) Per Common Share
from Continuing Operations, Diluted		$	7.21	$	(0.22)



Net Earnings (Loss) Per Common Share, Diluted		$	7.21	$	(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,
2003
(Unaudited)
2002
ASSETS
Current Assets
Cash and cash equivalents
$
4,675
$
3,532
Restricted cash
555
527
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$60 million in 2003 and $59 million in 2002)
1,837
1,900
Related parties
16
-
Regulatory balancing accounts
196
98
Inventories:
Gas stored underground and fuel oil
251
154
Materials and supplies
120
121
Current assets of NEGT, Inc.
-
3,029
Prepaid expenses and other
70
111
Total current assets
7,720
9,472
Property, Plant and Equipment
Electric
20,173
18,922
Gas
8,291
8,123
Construction work in progress
370
427
Other
20
21
Total property, plant and equipment
28,854
27,493
Accumulated depreciation
(12,828)
(13,528)
Net property, plant and equipment
16,026
13,965
Other Noncurrent Assets
Regulatory assets
2,034
2,011
Nuclear decommissioning funds
1,416
1,335
Long-term assets of NEGT, Inc.
-
4,883
Other
564
1,373
Total other noncurrent assets
4,014
9,602
TOTAL ASSETS
$
27,760
$
33,039
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS


	Balance At

(in millions)	March 31,		December 31,
	2004 (Unaudited)		2003

ASSETS
Current Assets
Cash and cash equivalents	$	3,460	$	3,658
Restricted cash	531		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $61 million in 2004 and $68 million in 2003)	2,068		2,424
Related parties	-		15
Regulatory balancing accounts	546		248
Inventories:
Gas stored underground	80		166
Materials and supplies	130		126
Prepaid expenses and other	54		171

Total current assets	6,869		7,211

Property, Plant and Equipment
Electric	20,665		20,468
Gas	8,431		8,355
Construction work in progress	417		379
Other	19		20

Total property, plant and equipment	29,532		29,222
Accumulated depreciation	(11,236)		(11,115)

Net property, plant and equipment	18,296		18,107

Other Noncurrent Assets
Restricted cash	7,278		361
Regulatory assets	6,993		2,001
Nuclear decommissioning funds	1,547		1,478
Other	1,156		1,017

Total other noncurrent assets	16,974		4,857

TOTAL ASSETS	$	42,139	$	30,175




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance at
(in millions, except per share amounts)
September 30,
December 31,
2003
(Unaudited)
2002
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current
$
310
$
281
Current portion of rate reduction bonds
290
290
Accounts payable:
Trade creditors
479
380
Regulatory balancing accounts
61
360
Other
416
421
Interest payable
216
139
Income taxes payable
600
83
Current liabilities of NEGT, Inc.
-
6,657
Other
707
658
Total current liabilities
3,079
9,269
Noncurrent Liabilities
Long-term debt
3,313
3,715
Rate reduction bonds
947
1,160
Regulatory liabilities
1,074
1,461
Asset retirement obligations
1,197
-
Deferred income taxes
941
782
Deferred tax credits
131
144
Net investment in NEGT, Inc.
1,215
-
Long-term liabilities of NEGT, Inc.
-
1,907
Preferred stock of subsidiary with mandatory redemption provisions
137
-
Other
2,057
1,323
Total noncurrent liabilities
11,012
10,492
Liabilities Subject to Compromise
Financing debt
5,604
5,605
Trade creditors
3,713
3,580
Total liabilities subject to compromise
9,317
9,185
Commitments and Contingencies (Notes 1, 2, 4, and 6)
-
-
Preferred Stock of Subsidiaries
285
480
Common Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares, issued
412,147,679 common and 1,577,770 restricted shares in 2003 and 405,486,015 common shares in 2002
6,411
6,274
Common stock held by subsidiary, at cost, 23,815,500 shares
(690)
(690)
Unearned compensation
(22)
-
Accumulated deficit
(1,495)
(1,878)
Accumulated other comprehensive loss
(137)
(93)
Total common shareholders' equity
4,067
3,613
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
$
27,760
$
33,039
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,
	2004 (Unaudited)			2003

LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current	$		4	$	310
Current portion of rate reduction bonds	290			290
Accounts payable:
Trade creditors	428			657
Regulatory balancing accounts	431			186
Other	547			402
Interest payable	223			174
Income taxes payable	417			256
Other	956			867

Total current liabilities	3,296			3,142

Noncurrent Liabilities
Long-term debt	10,000			3,314
Rate reduction bonds	796			870
Regulatory liabilities	4,249			3,979
Asset retirement obligations	1,236			1,218
Deferred income taxes	2,804			856
Deferred tax credits	125			127
Net investment in NEGT	1,219			1,216
Preferred stock of subsidiary with mandatory redemption provisions	137			137
Other	1,636			1,497

Total noncurrent liabilities	22,202			13,214

Liabilities Subject to Compromise
Financing debt	5,603			5,603
Trade creditors	3,439			3,715

Total liabilities subject to compromise	9,042			9,318

Commitments and Contingencies (Notes 1, 2, 3, and 6)	-			-

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 420,671,789 common and 1,631,638 restricted shares in 2004 and 408,610,591 common and 1,569,260 restricted shares in 2003	6,540			6,468
Common stock held by subsidiary, at cost, 23,815,500 shares	(690)			(690)
Unearned compensation	(31)			(20)
Accumulated earnings (deficit)	1,575			(1,458)
Accumulated other comprehensive loss	(81)			(85)

Total common shareholders' equity	7,313			4,215

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	42,139		$	30,175




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,
2003
2002
Cash Flows From Operating Activities
Net income
$
383
$
1,315
Loss from discontinued operations
365
156
Cumulative effect of changes in accounting principles
6
61
Net income from continuing operations
754
1,532
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, amortization, and decommissioning
910
881
Deferred income taxes and tax credits, net
339
176
Reversal of ISO accrual
-
(970)
Other deferred charges and noncurrent liabilities
636
(188)
Loss from retirement of long-term debt
89
153
Gain on sale of assets
(10)
-
Net effect of changes in operating assets and liabilities:
Restricted cash
(28)
(131)
Accounts receivable
(23)
233
Inventories
(96)
29
Accounts payable
262
139
Income taxes payable
517
246
Regulatory balancing accounts, net
(397)
(1)
Other working capital
(26)
370
Payments authorized by the Bankruptcy Court on amounts classified as Liabilities Subject to Compromise
(83)
(1,180)
Other, net
72
(38)
Net cash provided by operating activities
2,916
1,251
Cash Flows From Investing Activities
Capital expenditures
(1,183)
(1,156)
Net proceeds from sale of asset
14
8
Other, net
(24)
15
Net cash used by investing activities
(1,193)
(1,133)
Cash Flows From Financing Activities
Long-term debt issued
582
564
Long-term debt matured, redeemed, or repurchased
(1,067)
(1,241)
Rate reduction bonds matured
(213)
(213)
Common stock issued
120
190
Other, net
(2)
-
Net cash provided by financing activities
(580)
(700)
Net change in cash and cash equivalents
1,143
(582)
Cash and cash equivalents at January 1
3,532
4,696
Cash and cash equivalents at September 30
$
4,675
$
4,114

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

	Three Months Ended
(in millions)	March 31,

	2004					2003

Cash Flows From Operating Activities
Net income (loss)	$			3,033		$				(354)
Loss from discontinued operations	-					265
Cumulative effect of changes in accounting principles	-					6

Net income from continuing operations	3,033					(83)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and decommissioning	312					310
Recognition of regulatory assets	(4,900)					-
Deferred income taxes and tax credits, net	1,926					(15)
Other deferred charges and noncurrent liabilities	237					189
Gain on sale of assets	(16)					-
Net effect of changes in operating assets and liabilities:
Restricted cash	(128)					206
Accounts receivable	352					402
Inventories	82					71
Accounts payable	(257)					81
Accrued taxes	65					(128)
Regulatory balancing accounts, net	(53)					(51)
Other working capital	287					4
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(20)					(39)
Other, net	(33)					(14)

Net cash provided by operating activities	887					933

Cash Flows From Investing Activities
Capital expenditures	(342)					(371)
Net proceeds from sale of assets	18					5
Increase in restricted cash	(6,917)					-
Other, net	(65)					9

Net cash used by investing activities	(7,306)					(357)

Cash Flows From Financing Activities
Net proceeds from long-term debt issued	6,547					-
Long-term debt matured, redeemed or repurchased	(310)					-
Rate reduction bonds matured	(74)					(74)
Common stock issued	58					21

Net cash provided (used) by financing activities	6,221					(53)

Net change in cash and cash equivalents	(198)					523
Cash and cash equivalents at January 1	3,658					3,532

Cash and cash equivalents at March 31	$			3,460		$				4,055



Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income			$		8			$	11
Cash paid for:
Interest (net of amounts capitalized)					197				149
Income taxes paid, net		-					1
Reorganization professional fees and expenses		5					22
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise from operating assets and liabilities		(257)					47

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	(Unaudited)

	Three Months Ended
(in millions)	March 31,

	2004			2003

Operating Revenues
Electric	$		1,791	$	1,305
Natural gas	931			830

Total operating revenues	2,722			2,135

Operating Expenses
Cost of electricity	561			554
Cost of natural gas	578			486
Operating and maintenance	808			712
Recognition of regulatory assets	(4,900)			-
Depreciation, amortization and decommissioning	311			310
Reorganization professional fees and expenses	2			35

Total operating (gain) expenses	(2,640)			2,097

Operating Income	5,362			38
Reorganization interest income	8			10
Interest income	3			1
Interest expense (non-contractual interest expense of $31 million in 2004 and $30 million in 2003)	(213)			(220)
Other income, net	13			15

Income (Loss) Before Income Taxes	5,173			(156)
Income tax provision (benefit)	2,099			(84)

Income (Loss) Before Cumulative Effect of a Change in Accounting Principle	3,074			(72)
Cumulative effect of change in accounting principle (net of income tax benefit of $1 million for the three months ended March 31, 2003)	-			(1)

Net Income (Loss)	3,074			(73)
Preferred dividend requirement	8			6

Income (Loss) Available for (Allocated to) Common Stock	$	3,066		$	(79)




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At

(in millions)	March 31,		December 31,
	2004 (Unaudited)		2003

ASSETS
Current Assets
Cash and cash equivalents	$	2,845	$	2,979
Restricted cash	529		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $61 million in 2004 and $68 million in 2003)	2,068		2,424
Related parties	2		17
Regulatory balancing accounts	546		248
Inventories:
Gas stored underground	80		166
Materials and supplies	130		126
Prepaid expenses and other	52		100

Total current assets	6,252		6,463

Property, Plant and Equipment
Electric	20,665		20,468
Gas	8,431		8,355
Construction work in progress	417		379

Total property, plant and equipment	29,513		29,202
Accumulated depreciation	(11,221)		(11,100)

Net property, plant and equipment	18,292		18,102

Other Noncurrent Assets
Restricted cash	6,917		-
Regulatory assets	6,993		2,001
Nuclear decommissioning funds	1,547		1,478
Other	1,098		1,051

Total other noncurrent assets	16,555		4,530

TOTAL ASSETS	$	41,099	$	29,095




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS

		Balance At

(in millions, except share amounts)		March 31,		December 31,
		2004 (Unaudited)		2003

LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current		$	4	$	310
Current portion of rate reduction bonds		290		290
Accounts payable:
Trade creditors		427		657
Related parties		93		224
Regulatory balancing accounts		431		186
Other		530		365
Interest payable		208		153
Income taxes payable		148		-
Deferred income taxes		66		86
Other		840		673

Total current liabilities		3,037		2,944

Noncurrent Liabilities
Long-term debt		9,117		2,431
Rate reduction bonds		796		870
Regulatory liabilities		4,249		3,979
Asset retirement obligations		1,236		1,218
Deferred income taxes		3,370		1,334
Deferred tax credits		125		127
Preferred stock with mandatory redemption provisions		137		137
Other		1,573		1,464

Total noncurrent liabilities		20,603		11,560

Liabilities Subject to Compromise
Financing debt		5,603		5,603
Trade creditors		3,622		3,899

Total liabilities subject to compromise		9,225		9,502

Commitments and Contingencies (Notes 1, 2, 3 and 6)		-		-

Shareholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable, 5% to 6%, outstanding 5,784,825 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 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	4,772			1,706
Accumulated other comprehensive loss	(3)			(6)

Total shareholders' equity	8,234			5,089

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$		41,099	$	29,095




See accompanying Notes to the Condensed Consolidated Financial Statements.

Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income
$
30
$
59
Cash paid for:
Interest (net of amounts capitalized)
555
856
Income taxes paid (refunded), net
(531)
541
Reorganization professional fees and expenses
84
25
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise
from operating assets and liabilities
193
(97)
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)

	Three Months Ended
(in millions)	March 31,

	2004		2003

Cash Flows From Operating Activities
Net income (loss)	$	3,074	$	(73)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and decommissioning	311		310
Recognition of regulatory assets	(4,900)		-
Deferred income taxes and tax credits, net	2,014		117
Other deferred charges and noncurrent liabilities	279		80
Gain on sale of assets	(16)		-
Cumulative effect of a change in accounting principle	-		1
Net effect of changes in operating assets and liabilities:
Restricted cash	(126)		(41)
Accounts receivable	353		381
Inventories	82		71
Accounts payable	(256)		122
Accrued taxes	98		(176)
Regulatory balancing accounts, net	(53)		(51)
Other working capital	253		24
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(20)		(39)
Other, net	(84)		8

Net cash provided by operating activities	1,009		734

Cash Flows From Investing Activities
Capital expenditures	(342)		(371)
Net proceeds from sale of assets	18		5
Increase in restricted cash	(6,917)		-
Other, net	(65)		9

Net cash used by investing activities	(7,306)		(357)

Cash Flows From Financing Activities
Net proceeds from issuance of long-term debt	6,547		-
Long-term debt matured, redeemed or repurchased	(310)		-
Rate reduction bonds matured	(74)		(74)

Net cash provided (used) by financing activities	6,163		(74)


Net change in cash and cash equivalents	(134)		303
Cash and cash equivalents at January 1	2,979		3,343

Cash and cash equivalents at March 31	$	2,845	$	3,646




Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	8	$	11
Cash paid for:
Interest (net of amounts capitalized)	175		116
Reorganization professional fees and expenses	5		22
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise (to) from operating assets and liabilities, net	(257)		47

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three months ended
Nine months ended
(in millions)
September 30,
September 30,
2003
2002
2003
2002
Operating Revenues
Electric
$
2,524
$
2,483
$
5,823
$
6,454
Natural gas
579
466
2,077
1,662
Total operating revenues
3,103
2,949
7,900
8,116
Operating Expenses
Cost of electricity
679
555
1,735
894
Cost of natural gas
233
119
1,039
632
Operating and maintenance
669
860
2,095
2,269
Depreciation, amortization, and decommissioning
311
315
916
880
Reorganization professional fees and expenses
16
41
116
75
Total operating expenses
1,908
1,890
5,901
4,750
Operating Income
1,195
1,059
1,999
3,366
Reorganization interest income
9
17
36
58
Interest income
2
1
6
1
Interest expense (noncontractual interest expense of $32
million and $99 million for the three and nine months ended September 30, 2003, and $34 million and $137 million for the three and nine months ended September 30, 2002)
(237)
(221)
(681)
(767)
Other income (expense), net
3
1
10
(5)
Income Before Income Taxes
972
857
1,370
2,653
Income tax provision
383
330
508
1,061
Income Before Cumulative Effect of a Change in
Accounting Principle
589
527
862
1,592
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
589
527
861
1,592
Preferred dividend requirement
6
7
18
19
Income Available for Common Stock
$
583
$
520
$
843
$
1,573
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance at
(in millions)
September 30,
December 31,
2003
(Unaudited)
2002
ASSETS
Current Assets
Cash and cash equivalents
$
4,195
$
3,343
Restricted cash
194
150
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$60 million in 2003 and $59 million in 2002)
1,837
1,900
Related parties
18
17
Regulatory balancing accounts
196
98
Inventories:
Gas stored underground and fuel oil
251
154
Materials and supplies
120
121
Prepaid expenses and other
68
165
Total current assets
6,879
5,948
Property, Plant and Equipment
Electric
20,173
18,922
Gas
8,291
8,123
Construction work in progress
368
427
Total property, plant and equipment
28,832
27,472
Accumulated depreciation
(12,813)
(13,515)
Net property, plant and equipment
16,019
13,957
Other Noncurrent Assets
Regulatory assets
2,034
2,011
Nuclear decommissioning funds
1,416
1,335
Other
502
1,300
Total other noncurrent assets
3,952
4,646
TOTAL ASSETS
$
26,850
$
24,551
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
Balance at
(in millions, except per share amounts)
September 30,
December 31,
2003
(Unaudited)
2002
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current
$
310
$
281
Current portion of rate reduction bonds
290
290
Accounts payable:
Trade creditors
479
380
Related parties
206
130
Regulatory balancing accounts
61
360
Other
381
374
Interest payable
200
126
Income taxes payable
437
-
Deferred income taxes
109
-
Other
548
625
Total current liabilities
3,021
2,566
Noncurrent Liabilities
Long-term debt
2,429
2,739
Rate reduction bonds
947
1,160
Regulatory liabilities
1,074
1,461
Asset retirement obligations
1,197
-
Deferred income taxes
1,470
1,485
Deferred tax credits
131
144
Preferred stock with mandatory redemption provisions
137
-
Other
1,966
1,274
Total noncurrent liabilities
9,351
8,263
Liabilities Subject to Compromise
Financing debt
5,604
5,605
Trade creditors
3,897
3,786
Total liabilities subject to compromise
9,501
9,391
Commitments and Contingencies (Notes 1, 2, and 6)
-
-
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009
-
137
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 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
1,964
1,964
Reinvested earnings
1,648
805
Accumulated other comprehensive loss
(60)
-
Total shareholders' equity
4,977
4,194
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
$
26,850
$
24,551
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine months ended
(in millions)
September 30,
2003
2002
Cash Flows From Operating Activities
Net income
$
861
$
1,592
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, amortization, and decommissioning
916
880
Deferred income taxes and tax credits, net
122
157
Other deferred charges and noncurrent liabilities
395
(141)
Gain on sale of assets
(10)
-
Reversal of ISO accrual
-
(970)
Cumulative effect of changes in accounting principles
2
-
Net effect of changes in operating assets and liabilities:
Restricted cash
(44)
(57)
Accounts receivable
(8)
245
Inventories
(96)
29
Accounts payable
350
139
Income taxes payable
437
179
Regulatory balancing accounts, net
(397)
(1)
Other working capital
77
345
Payments authorized by the Bankruptcy Court on amounts
classified as Liabilities Subject to Compromise
(83)
(1,180)
Other, net
17
37
Net cash provided by operating activities
2,539
1,254
Cash Flows From Investing Activities
Capital expenditures
(1,182)
(1,156)
Net proceeds from sale of assets
14
8
Other, net
(25)
16
Net cash used by investing activities
(1,193)
(1,132)
Cash Flows From Financing Activities
Long-term debt matured, redeemed, or repurchased
(280)
(333)
Rate reduction bonds matured
(213)
(213)
Other, net
(1)
-
Net cash used by financing activities
(494)
(546)
Net change in cash and cash equivalents
852
(424)
Cash and cash equivalents at January 1
3,343
4,341
Cash and cash equivalents at September 30
$
4,195
$
3,917
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income
$
30
$
59
Cash paid for:
Interest (net of amounts capitalized)
475
830
Income taxes paid (refunded), net
(32)
708
Reorganization professional fees and expenses
84
25
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to
compromise (to) from operating assets and liabilities, net
193
(97)
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, ~~(Utility),~~or the Utility, a ~~vertically integrated~~public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas ~~utility.~~distribution, electricity generation, electricity transmission, and natural gas transportation and storage. PG&E Corporation became the holding company of the Utility ~~a debtor-in-possession,~~ and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. ~~The Utility delivers electric service to approximately 5 million customers and natural gas service to approximately 4 millioncustomers in Northern and Central California.~~ Both PG&E Corporation and the Utility are headquartered in San ~~Francisco.~~Francisco, California.

As discussed further in Note 2, on April ~~6, 2001,~~12, 2004, the ~~Utility filed a voluntary petition for relief~~Utility's plan of reorganization, or Plan of Reorganization, under the provisions of Chapter 11 of the ~~federal~~U.S. Bankruptcy Code, ~~(Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (referred to as the Bankrupt cy Court in this report's discussion of the Utility's~~or Chapter 11, ~~filing). Pursuant to~~became effective. During its Chapter 11 proceeding, the Utility ~~has~~ retained control of its assets and iswas authorized to operate its business as a ~~debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.~~debtor-in-possession.

PG&E Corporation's other significant subsidiary is National Energy & Gas Transmission, Inc., formerly known as PG&E National Energy Group, Inc. ~~(PG~~, or PG&E ~~NEG),~~NEG, headquartered in Bethesda, Maryland.PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, PG&E NEG and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt ~~Division (referred to as the Bankruptcy Court in this report's discussion of PG&E NEG's Chapter 11 filing).~~Division. Subsequently, on July 29, 2003, two additional subsidiaries of PG&E NEG also filed voluntary Chapter 11 petitions. ~~Pursuant to Chapter 11,~~ PG&E NEG and those subsidiaries in ~~bankruptcy~~Chapter 11 retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On July 8, 2003, PG&E NEG also filed a proposed plan o f reorganization with the Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest in PG&E NEG.bankruptcy court. On October 3, ~~2003,~~2 003, the ~~Bankruptcy Court~~bankruptcy court authorized PG&E NEG to change its name to National Energy ~~and~~& Gas Transmission, Inc. ~~(NEGT, Inc.).~~, or NEGT. The change reflects ~~NEGT, Inc.'s~~NEGT's pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG in these Notes to the Condensed Consolidated Financial Statements ~~including its Chapter 11 filing and its~~will refer to NEGT. NEGT's plan of reorganization, ~~will refer to NEGT, Inc.~~if implemented, would eliminate PG&E Corporation's equity interest in NEGT.

Under accounting principles generally accepted in the United States of America, ~~(GAAP),~~or GAAP, consolidation is generally required for investments of more than ~~50 percent~~50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Under these rules, legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. ~~As discussed above, as a result~~In anticipation of ~~NEGT, Inc.'s~~NEGT's Chapter 11 filing, ~~the resignation of~~ PG&E Corporation's representatives, who previously served on the NEGT ~~Inc.~~ Board of Directors, resigned on July 7, 2003 and ~~their replacement~~were replaced with Board members who are not affiliated with PG&E ~~Corporation,~~Corporation. As a result, PG&E Corporation no longer retains significant influence over the ongoing operations of ~~NEGT, Inc. PG&E Corporation anticipates that the Bankruptcy Court will approve NEGT, Inc.'s proposed~~NEGT. On May 3, 2004, NEGT's plan of reorganization, ~~or a plan with similar~~which eliminates PG&E Corporation's equity ~~loss provisions for PG&E Corp oration. Therefore, as of~~ownership , was confirmed by the bankruptcy court. Effective July 8, 2003, PG&E Corporation ~~has deconsolidated~~no longer consolidates the ~~operations~~earnings and losses of NEGT ~~Inc.~~or its subsidiaries and has reflected its ownership interest in NEGT ~~Inc.~~ utilizing the cost method of accounting, under which PG&E Corporation's investment in NEGT ~~Inc.~~ is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation ~~and the recording of earnings and losses from NEGT, Inc. ceased after July 7, 2003.~~at March 31, 2004. In addition, for the reasons described above, PG&E Corporation considers NEGT ~~Inc.~~ to be an abandoned asset under Statement of Financial Accounting Standards, ~~(SFAS),~~or SFAS, "Accounting for Impairment or Disposal of Long-Lived ~~Assets" (SFAS~~Assets," or SFAS No. ~~144),~~144, and, as a result, the operations of NEGT ~~Inc.~~ prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations onin the ~~Condensed~~ Consolidated Financial Statements (see Note 4 for further information).

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.~~subsidiaries, and variable interest entities for which it is subject to a majority of the risk of loss or gain. Both PG&E Corporation's and the Utility's Consolidated Balance Sheets ~~as of~~at December 31, ~~2002,~~2003 were derived from the audited Consolidated Balance Sheets ~~filed~~included in the combined ~~2002~~2003 Annual Report filed with the Current Report on Form ~~10-K, as amended.~~8-K dated March 2, 2004.

PG&E Corporation and the Utility believe that the accompanying Consolidated Financial Statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. All significant intercompany transactions have been eliminated from the Consolidated Financial Statements.

This Quarterly Report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their combined 2002 Annual Report on Form 10-K, as amended, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission (SEC) since their combined 2002 Annual Report on Form 10-K, as amended, was filed.

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. As these estimates involve judgments on a wide range of factors, including future economic conditions that are difficult to predict, actual results could differ from these estimates.

PG&E Corporation's and the Utility's Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position ~~(SOP)~~ 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy ~~Code" (SOP 90-7),~~Code," or SOP 90-7, and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. As a result of the Utility's Chapter 11 filing, the realization of assets and liquidation of liabilities ~~are~~were subject to ~~uncertainty.~~uncertainty while the Utility was in Chapter 11. Under SOP 90-7, certain claims against the Utility existing before the Utility's Chapter 11 filing are classified as ~~Liabilities Subject~~liabilities subject to ~~Compromise~~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~~C hapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings are reported separately as reorganization items. Finally, the extent to which the Utility's reported interest expense differs from its stated contractual interest is disclosed on the Utility's Condensed Consolidated Statements of ~~Income.~~

Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. These reclassifications did not affect the consolidated net income reported by PG&E Corporation and the Utility for the periods presented.Operations.

Adoption of New Accounting Policies and Summary of Significant Accounting Policies

The accounting policies used by PG&E Corporation and the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission, ~~(CPUC)~~or the CPUC, and the Federal Energy Regulatory Commission, ~~(FERC).~~or the FERC. Except as disclosed below, PG&E Corporation and the Utility are following the same accounting policies discussed in their combined ~~2002~~2003 Annual Report filed with the Current Report on Form ~~10-K, as amended.~~8-K dated March 2, 2004.

~~Accounting for Certain Financial Instruments with Characteristics of Both Liabilities~~Participating Securities and ~~Equity~~the Two-Class Method

~~In May 2003,~~ On March 31, 2004, the Financial Accounting Standards Board, ~~(FASB) issued~~or FASB, ratified the consensus reached by its Emerging Issues Task Force, or EITF, on EITF Issue 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. ~~150, "Accounting~~128," or EITF 03-06. EITF 03-06 provides additional guidance related to the calculation of earnings per share under FASB Statement 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 adopted EITF 03-06 for the quarter ending March 31, 2004 and all prior periods presented.

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 03-6 requires that earnings be allocated between common stock and the participating security.

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 entity is a variable interest entity if it does not have sufficient equity investment at risk, or if the holders of the entity's equity instruments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the company that is subject to a majority of the risk of loss from a variable interest entity's activities, or is entitled to receive a majority of the entity's residual returns, or both, consolidate the variable interest entity. A company that consolidates a variable interest entity is called the primary beneficiary.

PG&E Corporation and the Utility adopted FIN 46R on January 1, 2004. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of two low-income housing partnerships that were determined to be variable interest entities under FIN 46R. The consolidation of these variable interest entities resulted in an increase in total assets and total liabilities of $16 million. There was no impact on income resulting from the adoption of FIN 46R.

Low Income Housing Partnerships

The Utility is a limited partner in two low-income housing partnerships, or LIHPs, that are considered to be variable interest entities. The Utility was determined to be the primary beneficiary of both of these entities. The two partnerships were formed to invest in low-income housing projects sponsored by non-profit organizations in the state of California. The LIHPs have issued debt in the amount of $8 million, which is secured by assets of the partnerships in the amount of $28 million and the Utility's capital infusion commitments. In addition to the amounts recorded above, the Utility is required to make capital infusions of approximately $16 million to the two LIHPs over the next five years.

The Utility has not applied FIN 46R to 11 other low-income housing partnership investments that are subsidiaries of one of the LIHPs. The Utility is unable to apply FIN 46R to these partnerships because it does not have the legal right to the information necessary to determine if these entities are variable interest entities or to perform the accounting required to consolidate the entities. The Utility's maximum exposure to loss from these partnership investments is the partnership's current investment of $26 million.

Power Purchase Agreements

The Utility is unable to apply the provisions of FIN 46R to 28 entities that are counterparties of power purchase agreements. It is conceivable that the Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a variable interest entity and it owns 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. The Utility was unable to obtain the information necessary to determine whether 28 of its power purchase agreement counterparties are variable interest entities or determine if the Utility is the primary beneficiary of these entities because the counterparties are not legally required to provide the Utility with the information.

These 28 entities are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement. In regards to these 28 agreements, approximately 1,000 megawatts, or MW expire between 2004 and 2 026 and approximately 143 MW have no specific expiration dates. Collective purchases from these entities were $115 million for the three months ended March 31, 2004 and $102 million for the three months ended March 31, 2003. The Utility has no investment at risk in the counterparty entities or commitment to fund losses.

Changes in Accounting for Certain ~~Financial Instruments with Characteristics~~Derivative Contracts

In November 2003 the FASB approved an amendment to an interpretation issued by the Derivatives Implementation Group C15 (as previously amended in October 2001 and December 2001, or DIG C15), that changed the definition of ~~Both Liabilities~~normal purchases and ~~Equity" (SFAS No. 150). SFAS No. 150 addresses concerns of how to measure~~sales for certain power contracts that contain optionality.

PG&E Corporation and ~~classify in~~ the ~~balance sheet certain financial~~Utility had previously adopted the new DIG C15 guidelines prospectively for new derivative instruments that have characteristics of both liabilities and equity. The following freestanding financial instruments must be classified as liabilities: mandatorily redeemable financial instruments, obligations to repurchase an issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares.

entered into after June 30, 2003. On January 1, 2004, PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in the third quarter of 2003. As a result, the Utility reclassified and remeasured $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability. The remeasurement and reclassification did not have an impact on earnings of PG&E Corporation or the Utility. Upon adopting SFAS No. 150 all amounts paid ornew DIG C15 guidelines for certain power contracts that contain optionality that existed prior to be paid to the holders of preferred stock with mandatory redemption provisions in excess of the initial measured amount are reflected in interest cost. Dividends paid or accrued in prior periods have not been reclassified.

~~Determining Whether an Arrangement Contains a Lease~~

In May 2003, the Emerging Issues Task Force (EITF) reached consensus on EITF 01-8, "Determining Whether an Arrangement Contains a Lease" (EITF 01-8). EITF 01-8 establishes criteria to be applied to any new or modified agreement in order to ascertain if such agreement is in effect a lease, and subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, "Accounting for Leases" (SFAS No. 13). EITF 01-8 is effective for all new or modified arrangements entered into as of July 1, 2003. The adoption of ~~EITF 01-8 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.~~

~~Amendment of Statement 133 on Derivative Instruments and Hedging Activities~~

In April 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies circumstances under which a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. The provisions of SFAS No. 149 that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

~~Guarantor's Accounting and Disclosure Requirements for Guarantees~~

PG&E Corporation incorporated the disclosure requirements from FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), into its December 31, 2002, disclosures of guarantees. Beginning January 1, 2003, PG&E Corporation applied the initial recognition and measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002.

FIN 45 elaborates on existing disclosure requirements for most guarantees. It also clarifies that at the time a company issues a guarantee, it must recognize a liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. This information also must be disclosed in interim and annual financial statements.

~~The adoption of this interpretation did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.~~

~~Accounting for Asset Retirement Obligations~~

On January 1, 2003, PG&E Corporation adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible long-lived assets. 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. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the 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.

~~The impacts of adopting SFAS No. 143 were as follows:~~

The Utility has identified its nuclear generation and certain fossil generation facilities as having asset retirement obligations as of January 1, 2003. No additional asset retirement obligations had been identified as of September 30, 2003.Through December 31, 2002, the Utility had recorded $1.4 billion for its nuclear and fossil decommissioning obligations in Accumulated Depreciation and Decommissioning in the Consolidated Balance Sheets.

Upon adoption of SFAS No. 143, the Utility reclassified the decommissioning liabilities recorded through December 31, 2002 as Asset Retirement Obligations in the Consolidated Balance Sheets. To record the decommissioning liabilities at fair value as required by SFAS No. 143, the Utility then reduced the asset retirement obligations by $53 million. The Utility increased its Property, Plant and Equipment balance by $332 million to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, less accumulated depreciation from the date the obligation was incurred through December 31, 2002. Finally, the Utility recorded a regulatory liability of $387 million to reflect the cumulative effect of adoption for its nuclear facilities. This regulatory liability represents timing differences between recognition of nuclear decommissioning obligations in accordance with GAAP and ratemaking purposes. The cumulative effect of the change in accounting principle for the Utility's fo ssil facilities as a result of adopting SFAS No. 143 was a loss of $1 million, after-tax.

In connection with an application filed with the CPUC requesting an increase in the Utility's nuclear decommissioning revenue requirements for the years 2003 through 2005, the Utility developed a new estimate for costs to decommission its nuclear facilities. As a result, the Utility has reduced its asset retirement obligation by $223 million from the amount recorded upon the Utility's adoption of SFAS No. 143 on January 1, 2003. The Utility also reduced its Property, Plant and Equipment balance by $61 million. Finally, to account for timing differences between recognition of the modified asset retirement obligation as recorded in accordance with GAAP and ratemaking purposes, the Utility increased its regulatory liability by $162 million.

If SFAS No. 143 had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three- and nine-month periods ended September 30, 2002 would not have been material. The amounts recorded upon adoption of SFAS No. 143 reflect the pro forma effects on the Consolidated Balance Sheets if SFAS No. 143 had been adopted on December 31, 2002.

The Utility has established trust funds that are legally restricted for purposes of settling its nuclear decommissioning obligations. As of September 30, 2003, the fair value of these trust funds was approximately $1.4 billion.

The Utility may have potential asset retirement obligations under various land right documents associated with its transmission and distribution facilities. The majority of the Utility's land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because the Utility intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements are unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated.

The Utility collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations and will continue to be recorded in accumulated depreciation. As of September 30, 2003, the Utility's estimated removal costs recorded in accumulated depreciation were approximately $1.8 billion.

~~Accounting for Costs Associated with Exit or Disposal Activities~~

On January 1, 2003, PG&E Corporation adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity" (EITF 94-3). SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost is recognized at the commitment date of an exit plan. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. The adoption of SFAS No. 146DIG C15 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Regulation and Statement of Financial Accounting Standards No. 71

PG&E Corporation and the Utility ataccount for the ~~date~~financial effects of ~~adoption.~~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 the costs of providing service. SFAS No. 71 applies to all of the Utility's operations except for a natural gas pipeline. 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. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, among others.

SFAS No. 71 provides for the recording of 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. 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.

Earnings (Loss) Per Share

~~Basic~~ As a result of the implementation of the Settlement Agreement and the related recognition of the regulatory assets, discussed in Note 2, at March 31, 2004, PG&E Corporation had retained earnings of approximately $1.6 billion. Accordingly, basic earnings (loss) per share is calculated utilizing the "two-class" method by dividing ~~net income~~earnings (loss) allocated to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by dividing net income (loss), adjusted for the net interest and ~~amortization~~the change in market value of dividend participation rights associated with ~~PG&E Corporation's~~the Convertible ~~Subordinated~~ Notes, by the sum of the weighted average number of common shares outstanding and the assumed issuance of common shares for all dilutive securities.

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

Three months ended
Nine months ended
(in millions, except per share amounts)
September 30,
September 30,
2003
2002
2003
2002
Income from continuing operations
$
508
$
479
$
754
$
1,532
Discontinued operations
2
(13)
(365)
(156)
Net income before cumulative effect of changes
in accounting principles
510
466
389
1,376
Cumulative effect of changes in accounting principles
-
-
(6)
(61)
Net Income
510

466
383
1,315
Interest expense on 9.5% Convertible Subordinated Notes
4

3
12
4
Net Income for Diluted Calculations
$
514
$
469
$
395
$
1,319
Weighted average common shares outstanding, basic
387
373
384
368
Add:
Employee stock options and PG&E Corporation
shares held by grantor trusts
5
-
2
2
PG&E Corporation Warrants
5
3
5
1
9.5% Convertible Subordinated Notes
19
19
19
7
Shares outstanding for diluted calculations
416
395
410
378
Earnings Per Common Share, Basic
Income from continuing operations
$
1.31
$
1.28
$
1.96
$
4.16
Discontinued operations
0.01
(0.03)
(0.95)
(0.42)
Cumulative effect of changes in accounting principles
-
-
(0.01)
(0.17)
Net earnings
$
1.32
$
1.25
$
1.00
$
3.57
Earnings Per Common Share, Diluted
Income from continuing operations
$
1.24
$
1.22
$
1.86
$
4.06
Discontinued operations
-
(0.03)
(0.89)
(0.41)
Cumulative effect of changes in accounting principles
-
-
(0.01)
(0.16)
Net earnings
$
1.24
$
1.19
$
0.96
$
3.49

	Three Months Ended
	March 31,

(in millions, except share amounts)	2004		2003


Income (loss) from continuing operations	$	3,033	$	(83)
Discontinued operations		-		(265)

Net income (loss) before cumulative effect of changes in accounting principles	3,033		(348)
Cumulative effect of changes in accounting principles	-		(6)

Net income (loss) for basic calculations	3,033		(354)

Earnings (loss) allocated to common shareholders, basic	2,893		(354)
Earnings (loss) allocated to Convertible Notes, basic	140		-

Net income (loss)	3,033		(354)

9.50% Convertible Notes:
Change in market value of dividend participation rights	19		-
Interest expense	4		-

Net income (loss) for diluted calculations	$	3,056	$	(354)




Weighted average common shares outstanding, basic	393		382
Add: 9.50% Convertible Notes	19		-
Employee stock options and PG&E Corporation shares held by grantor trusts	7		-
PG&E Corporation Warrants	4		-
Rounding	1		-

Shares outstanding for diluted calculations	424		382



Earnings (Loss) Per Common Share, Basic
Income (loss) from continuing operations	$	7.36	$	(0.22)
Discontinued operations	-		(0.69)
Cumulative effect of changes in accounting principles	-		(0.02)

Net earnings (loss)	$	7.36	$	(0.93)



Earnings (Loss) Per Common Share, Diluted
Income (loss) from continuing operations	$	7.21	$	(0.22)
Discontinued operations	-		(0.69)
Cumulative effect of changes in accounting principles	-		(0.02)

Net earnings (loss)	$	7.21	$	(0.93)

No portion of the loss for the period ended March 31, 2003 was allocated to the participating security under the "two-class" method since there is no contractual obligation for these Convertible Notes to share in the losses of PG&E Corporation.

Diluted earnings per share for the three months ended March 31, 2003 excludes 19 million incremental shares related to the Convertible Notes, approximately one million incremental shares related to employee stock options and shares held by grantor trusts and four million incremental shares related to warrants and includes associated interest expense of $4 million (net of income taxes of $3 million) due to the anti-dilutive effect upon loss from continuing operations.

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 account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by SFAS No. 123, "Accounting for Stock-Based ~~Compensation" (SFAS~~Compensation," or SFAS No. ~~123),~~123, as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. ~~123" (collectively,~~123," or SFAS No. ~~123).~~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. ~~Had~~If compensation expense had been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings (loss) and earnings (loss) per share would have been as follows:

Three months ended
Nine months ended
(in millions, except per share amounts)
September 30,
September 30,
2003
2002
2003
2002
Net income:
As reported
$
510
$
466
$
383
$
1,315
Deduct: Total stock-based employee
compensation expense determined
under the fair value based method
for all awards, net of related tax effects
5
5
15
14
Pro forma
$
505
$
461
$
368
$
1,301
Basic earnings per share:
As reported
1.32
1.25
1.00
3.57
Pro forma
1.30
1.24
0.96
3.54
Diluted earnings per share:
As reported
1.24
1.19
0.96
3.49
Pro forma
1.22
1.17
0.93
3.45

~~Had~~

		Three Months Ended
		March 31,

(in millions, except share amounts)		2004		2003

Net Earnings (Loss):
As reported		$	3,033	$	(354)
	Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(4)		(5)

Pro forma		$	3,029	$	(359)




Basic earnings (loss) per share:
As reported		$	7.36	$	(0.93)
Pro forma			7.35		(0.94)

Diluted earnings (loss) per share:
As reported		$	7.21	$	(0.93)
Pro forma			7.20		(0.94)

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

Three months ended
Nine months ended
(in millions)
September 30,
September 30,
2003
2002
2003
2002
Income available for common stock:
As reported
$
583
$
520
$
843
$
1,573
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
5
Pro forma
$
581
$
518
$
837
$
1,568

~~As of September 30, 2003,~~

		Three Months Ended
		March 31,

(in millions)		2004		2003

Net Earnings (Loss):
As reported		$	3,066	$	(79)
	Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects		(2)		(2)

Pro forma		$	3,064	$	(81)

At March 31, 2004, a total of ~~1.6 million~~2,086,180 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its ~~subsidiaries.~~subsidiaries, of which 1,278,140 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 ~~were issued at the grant date and~~ 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 percent~~80% of the shares lapse automatically over a period of four years at the rate of ~~20 percent~~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 percent~~20% of the shares will lapse at a rate of ~~5 percent~~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 the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Statements of Income was $1.8 million and $5.0 million for the three- and nine-month periods ended September 30, 2003, of which $1.0 million and $2.9 million for the three- and nine-month periods was recognized by the Utility.

~~The total unamortized balance of unearned compensation resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Balance Sheets was $22 million at September 30, 2003.~~

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, "Accounting for Derivative Instruments and Hedging Activities,'' as amended, or SFAS No. 133, and the effects of the remeasurement of the defined benefit pension plan.

Three months ended
Nine months ended
September 30, 2003
September 30, 2003
PG&E
PG&E
Corporation⁽¹⁾
Utility
Corporation⁽¹⁾
Utility
Net income available for common stock
$
510
$
583
$
383
$
843
Continuing operations
Foreign currency translation adjustment
-
-
3
-
Retirement plan remeasurement (Note 8)
-
-
(60)
(60)
Comprehensive income from continuing operations
510
583
326
783
Discontinued operations (Note 4)
Net loss in other comprehensive income (OCI)
from current period hedging transactions and price
changes in accordance with SFAS No. 133
-
-
(5)
-
Net reclassification from OCI to earnings
2
-
17
-
Other
1
-
1
-
Comprehensive income from discontinued operations
3
-
13
-
Total comprehensive income
$
513
$
-
$
339
$
783
(1)
Includes other comprehensive income of NEGT, Inc. prior to July 8, 2003, after which PG&E Corporation accounts for NEGT, Inc. using the cost method of accounting.
Three months ended
Nine months ended
September 30, 2002
September 30, 2002
PG&E
PG&E
Corporation
Utility
Corporation
Utility
Net income available for common stock
$
466
$
520
$
1,315
$
1,573
Net loss in other comprehensive income (OCI)
from current period hedging transactions and price
changes in accordance with SFAS No. 133
(153)
-
(237)
-
Net reclassification from OCI to earnings
(2)
-
3
-
Foreign currency translation adjustment
-
-
3
2
Total comprehensive income
$
311
$
520
$
1,084
$
1,575

		Three Months Ended
		March 31, 2004

		PG&E
		Corporation		Utility


Net income available for common stock		$	3,033	$	3,066
Net gain in other comprehensive income (OCI)
	from current period hedging transactions and price changes in accordance with SFAS No. 133 (net of income tax expense of $2 million)
		3		3
Net reclassification from OCI to earnings		-		-
Foreign currency translation adjustment		-		-
Other		1		-

Total comprehensive income (loss)		$	3,037	$	3,069

	Three Months Ended
	March 31, 2003

	PG&E
	Corporation			Utility


Net loss allocated to common stock	$		(354)	$		(79)
Net loss in OCI from current period hedging transactions and price changes in accordance with SFAS No. 133 (net of income tax benefit of $1 million)

	(1)			-
Net reclassification from OCI to earnings (net of income tax expense of $47 million)	5			-
Foreign currency translation adjustment (net of income tax expense of $2 million)	3			-

Total comprehensive loss	$	(347)		$	(79)

The above changes to OCI are stated net of income taxes benefits of ~~zero and $46~~$2 million for the ~~three-~~three-month period ended March 31, 2004, and ~~nine-month periods ended September 30, 2003, and $91 million and $132~~$48 million for the ~~three-~~three-month period ended March 31, 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 ~~nine-month periods ended September 30, 2002.~~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	(1)		-		-		-		(1)
Net reclassification to earnings	5		-		-		-		5
Other	-		3		-		-		3

Balance at March 31, 2003	$	(86)	$	-	$	-	$	-	$	(86)




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
Net reclassification to earnings	-		-		-		-		-
Other	-		-		-		1		1

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

Amounts included in accumulated other comprehensive income (loss) related to discontinued operations were $77 million at March 31, 2004, and $(86) million at March 31, 2003.

Income Taxes

In 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty in ~~realizing certain state deferred tax assets arising at NEGT, Inc.~~their realization. Valuation allowances of ~~zero and $24~~$17 million were recorded in discontinued operations, ~~and zero~~ and $5 million in accumulated other comprehensive loss for the ~~three- and nine-month periods~~three-month period ended ~~September 30,~~March 31, 2003.

In addition, PG&E Corporation recognized federal deferred tax assets related to losses incurred at NEGT, Inc. These deferred tax assets were determined on a consolidated basis, with the related tax benefit of zero and $157 million recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and zero and $44 million in accumulated other comprehensive loss for the three- and nine-month periods ended September 30, 2003.

Upon deconsolidation of NEGT ~~Inc.~~ for financial statement purposes, PG&E Corporation adopted the cost method of accounting for its ownership interest in ~~NEGT, Inc.~~NEGT. As a result of this accounting change, PG&E Corporation will not recognize additional ~~deferred~~income tax ~~assets~~benefits for financial statement reporting purposes after July 8,7, 2003, with respect to losses ofrelated to NEGT ~~Inc.~~or its subsidiaries even though it continues to include NEGT ~~Inc.~~ and its subsidiaries in its consolidated income tax returns. Any ~~unrealized~~such unrecognized benefits and deferred tax assets ~~relating~~arising from losses related to ~~the losses of~~ NEGT ~~Inc.~~or its subsidiaries that have been recognized through July 7, 2003, will ~~reverse~~be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in ~~NEGT, Inc. This reversal of deferred tax assets will partially offset any one-time gain recognized when PG&E Corporation writes off its net investment in NEGT, Inc.~~NEGT.

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.~~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 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 factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other cost-causal methods. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, ~~(GTNW),~~or GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. Effective April 1, 2003, the Utility no longer purchases ~~nat ural~~natural gas from NEGT Energy Trading Holdings Corporation, ~~(NEGT ET),~~or NEGT ET, formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are subsidiaries of ~~NEGT, Inc.~~NEGT. The Utility ~~continues to sell~~sold natural gas ~~transmission~~transportation capacity and other ancillary services to NEGT ~~ET.~~ET until NEGT's Chapter 11 proceeding was imminent. These services ~~are~~were priced at either tariff rates or fair market value, depending on the nature of the services provided. ~~Intercompany~~Through July 7, 2003, all significant intercompany transactions are eliminated in consolidation; therefore, no profit ~~results~~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
(in millions)
September 30,
December 31,
2003
2002
2003
2002
2003
2002
Utility revenues from:
Administrative services provided to
   PG&E Corporation
$
2
$
3
$
6
$
6
$
1
$
1
Natural gas transmission capacity
   services provided to NEGT ET
2
2
6
8
1
-
Contribution in aid of construction    received from NEGT, Inc.
-
-
-
-
-
3
Trade deposit due from GTNW
-
-
3
-
15
12
Utility expenses from:
Administrative services received from
   PG&E Corporation
$
40
$
16
$
137
$
66
$
(376)
$
(289)
Interest accrued on pre-petition liability    due to PG&E Corporation
2
-
5
-
(2)
(2)
Administrative services received
   from NEGT, Inc.
-
-
2
-
(1)
(2)
Software purchases from NEGT ET
-
-
1
-
-
-
Gas commodity services
   received from NEGT ET
-
5
10
33
-
(26)
Gas transportation services received
   from GTNW
14
11
43
33
(8)
(8)
Trade deposit due to NEGT ET
(6)
-
(5)
-
(2)
(7)

~~Payment~~

	Three Months Ended March 31,				Receivable (Payable) Balance Outstanding At
					March 31,		December 31,

(in millions)	2004		2003		2004		2003

Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	2	$	1	$	-
Natural gas transportation capacity services provided to NEGT ET	-		3		-		-
Trade deposit due from GTNW	(15)		3		-		15
Utility expenses from:
Administrative services received from PG&E Corporation	$	22	$	13	$	(265)	$	(396)
Interest accrued on pre-petition liability due to PG&E Corporation	2		2		(2)		(2)
Administrative services received from NEGT	-		1		-		(1)
Gas commodity services received from NEGT ET	-		10		-		-
Gas transportation services received from GTNW	15		15		(8)		(8)
Trade deposit due to NEGT ET	-		1		-		-

As discussed further in Note 2, as of ~~outstanding amounts owed~~March 31, 2004, PG&E Corporation recorded the impact of the Settlement Agreement. 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 contribution to the Utility by ~~NEGT, Inc.~~PG&E Corporation, net of taxes of $52 million, and an increase to additional paid-in capital by the Utility.

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 ~~July 8, 2003,~~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 ~~date of NEGT, Inc.'s Chapter 11 filing, are subject to the approval~~nature of the ~~Bankruptcy Court.~~assets, as reported by the trustee to determine the fair value of the plan assets.

Under SFAS No. 71, regulatory adjustments are recorded in the Consolidated Statements of Operations 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 postretirement benefits for 1993 and beyond.

Net periodic benefit cost as reflected in PG&E Corporation's and the Utility's Statement of Operations for the three months ended March 31, 2004 and March 31, 2003 are as follows:

PG&E Corporation

	Pension Benefits				Other Benefits

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	47	$	41	$	9		$	8
Interest cost	118		114		23			20
Expected return on Plan's assets	(141)		(122)		(19)			(15)
Amortized prior service cost	14		14		9			7
Amortization of unrecognized loss	-		10		-			1

Net periodic benefit cost	$	38	$	57	$	22		$	21

Utility

	Pension Benefits				Other Benefits

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	46	$	40	$	9	$	8
Interest cost	117		113		23		20
Expected return on Plan's assets	(141)		(121)		(19)		(15)
Amortized prior service cost	15		14		9		7
Amortization of unrecognized loss	-		10		-		1

Net periodic benefit cost	$	37	$	56	$	22	$	21

The Utility previously disclosed in its Annual Report for the year ended December 31, 2003 that it expected to contribute up to $129 million to its pension benefits plan, assuming favorable resolution of pension-related rate recovery in the 2003 general rate case, or GRC, in which it requested the CPUC to approve a related $75 million additional revenue requirement. On April 6, 2004, the administrative law judge, or ALJ, issued a proposed decision in the 2003 GRC recommending rejection of the Utility's request. A final decision on pension funding for 2003 will be made upon receipt of the final GRC decision.

Accounting Pronouncements Issued But Not Yet Adopted

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

In ~~January 2003,~~March 2004, the FASB issued ~~Interpretation~~Staff Position SFAS No. ~~46, "Consolidation~~106-b, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of ~~Variable Interest Entities" (FIN 46),~~2003," or SFAS No. 106-b. SFAS No. 106-b supersedes SFAS No. 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 related to the Prescription Drug Act. Under the current proposal, SFAS No. 106-b is to become effective for the third quarter 2004, which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity. A "variable interest entity" is an entity that does not have sufficient equity investment at risk or lacks the essential characteristics of a controlling financial interest.

Until the issuance of FIN 46, a company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities or is entitled to receive a majority of the entity's residual returns, or both. A company that consolidates a variable interest entity is now referred to as the "primary beneficiary" of that entity. FIN 46 requires disclosure of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E Corporation or the Utility between Februarybegins on July 1, ~~2003 and September 30, 2003. PG&E Corporation and the Utility must apply the provisions of FIN 46 as of December 31, 2003, for entities created prior to February 1, 2003.~~

2004. PG&E Corporation and the Utility are continuing to evaluate the ~~impacts~~impact of ~~FIN 46's initial~~SFAS No. 106-b's recognition, measurement and disclosure provisions on the consolidated financial statements and are unable to estimate the impact, if any, which will result when FIN 46 becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in two of these entities as a result of the adoption of FIN 46. As of September 30, 2003, the Utility's recorded investment in these entities is approximately $17 million. As a limited partner, the Utility's exposure to potential loss is limited to its investment in each partnership.

~~Changes to Accounting for Certain Derivative Contracts~~

~~In June 2003, the FASB issued a new Derivatives Implementation Group (DIG) interpretation of SFAS No. 133, Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of~~~~Not Clearly and Closely Related~~in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature" (DIG C20). DIG C20 specifies additional circumstances under which price adjustment features, such as those based on broad market indices, in a derivative contract would not be an impediment to qualify for the normal purchases and normal sales scope exception under SFAS No. 133. One of the attributes necessary to qualify for the normal purchases and sales exception is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. Under DIG C20, as long as the price adjustment feature in a contract is expected to be highly correlated to the asset to be delivered under that contract, the use of a broad market index (such as the consumer price index) as a price a djustment feature is considered clearly and closely related. Previously, under DIG C11, "Interpretations of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exceptions," the use of a price adjustment based on a broad market index was not considered to be clearly and closely related to the asset to be delivered, and the contract was not eligible for the normal purchases and sales exception. The guidance in DIG C11 is superseded by DIG C20.

The implementation guidance in DIG C20 is effective for derivative contracts in the fourth quarter of 2003. Application of the DIG C20 guidance to existing contracts that were not previously eligible for the normal purchases and sales exception under DIG C11 will be applied prospectively. The contract's fair value as of the date of adoption of DIG C20 should become the carrying value at that date. PG&E Corporation and the Utility currently are evaluating the impacts, if any, of DIG C20 on their Consolidated Financial Statements.

NOTE 2: THE UTILITY CHAPTER 11 FILING

The discussion of the Utility's Chapter 11 filing matters below should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements of PG&E Corporation's and the Utility's combined ~~2002~~2003 Annual Report filed with the Current Report on Form ~~10-K, as amended.~~8-K dated March 2, 2004.

Emergence From Chapter 11 ~~Filing~~

On April ~~6, 2001,~~12, 2004, the ~~Utility filed a voluntary petition for relief~~Utility's Plan of Reorganization under Chapter 11 of the U.S. Bankruptcy Code became effective. The Plan of Reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. Although the Utility's operations will no longer be subject to the oversight of the bankruptcy court, the bankruptcy court will retain jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the Plan of Reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the Plan of Reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining dispute d claims.

In anticipation of its emergence from Chapter 11, the Utility consummated its public offering of $6.7 billion of first mortgage bonds, or First Mortgage Bonds, on March 23, 2004. Upon the effectiveness of the Plan of Reorganization, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds for these transactions:

(in millions)
Sources			Uses


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

Account 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 its emergence from Chapter 11, the Utility received investment grade issuer credit ratings of Baa3 from Moody's Investors Service, or Moody's, and BBB- from Standard & Poor's, or S&P.

Appeals of the bankruptcy court's order confirming the Plan of Reorganization are still pending in the ~~Bankruptcy~~U.S. District Court for the Northern District of ~~California. Pursuant~~California, or the District Court. These appeals were filed by the two CPUC commissioners who did not vote to ~~Chapter 11,~~approve the ~~Utility retains control~~Settlement Agreement, or the dissenting commissioners, and a municipality. The District Court will set a schedule for briefing and argument of the appeals at a later date. 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 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 ~~assets~~December 18, 2003 decision. CCSF and ~~is authorized~~Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF r equests the appellate court to ~~operate its business as a debtor-in-possession while subject to~~hear and review the ~~jurisdiction of~~CPUC's decisions approving the ~~Bankruptcy Court.~~Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. PG&E Corporation and ~~subsidiaries~~the Utility believe the petitions are without merit and should be denied. The Utility's answer in opposition to the petitions for review is due May 19, 2004.

Under applicable federal precedent, once the Plan of Reorganization has been "substantially consummated," any pending appeals of the ~~Utility, including~~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 ~~Funding LLC (which issued rate reduction bonds)~~Corporation and the Utility's financial condition and results of operations could be materially adversely affected and PG&E ~~Holdings, LLC (which holds stock~~Corporation and the Utility's ability to make payments on debt could be materially adversely affected.

The Utility believes that the uncertainty regarding the outcome of the ~~Utility),~~pending appeals and petitions does not alter the assessment that the regulatory assets provided under the Settlement Agreement are ~~not included~~probable of recovery in rates, as discussed below.

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 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, regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $0.7 billion, after-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
Less: amortization from January 1 to March 31	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
Less: offsets of supplier settlements, after-tax	8			-		8

Net, 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 will be reduced 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, including those arising from the settlement of CPUC litigation against El Paso Natural Gas Company. As of March 31, 2004, the Utility recognized a one-time non-cash gain of $3.7 billion, pre-tax, for the Settlement Regulatory A sset.

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, as of March 31, 2004 the Utility recognized a one-time non-cash gain of $1.2 billion, pre-tax, for the retained generation regulatory assets. The individual components of the regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years.

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, including the Utility's pending 2003 GRC. 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 ten years, although the Utility will be entitled to recover these payments in rates. At March 31, 2004, the Utility recorded an $83 million regulatory asset and associated liability based on the discounted present value of future cash payments. On April 12, 2004, the Utility made its first $10 million installment payment to this corporation.
·	The Utility has also agreed to establish a California non-profit corporation dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory. The Utility has agreed to fund this corporation with $30 million payable over five years beginning in January 2005. These contributions may not be recovered in rates. At March 31, 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 ~~Chapter 11 filing.~~or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements. At March 31, 2004, the Utility recorded a $1 million pre-tax charge to earnings associated with the land donation obligation.

Fees and Expenses

In 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. At March 31, 2004, the Utility recorded a regulatory asset and associated liability of approximately $30 million for the CPUC reimbursable fees and expenses. 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 contribution to the Utility by PG&E Corporation, net of taxes, and an increase to additional paid-in capital by the Utility.

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 pre-tax 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 the following conditions are met:

·	Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the Settlement Regulatory Asset and associated federal and state income and franchise taxes and providing for the collection in the Utility's rates of any portion of the associated tax amounts not securitized;
·	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 IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

The Utility would be permitted to complete the refinancing in up to two tranches up to one year apart. Upon refinancing with securitization, the equity and debt components of the Utility's rate of return on the Settlement Regulatory Asset would be eliminated. Instead the Utility would collect from customers amounts sufficient to service the securitized debt. 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.

On January 22, 2004, the CPUC approved proposed legislation, Senate Bill 772, which would authorize a dedicated rate component to securitize the Settlement Regulatory Asset and the related taxes. The California legislature has been considering the proposed legislation and it may be presented for signature by the Governor as soon as the end of May 2004.

Chapter 11 Claims

Claims filed in the Chapter 11 proceeding ~~various parties filed claims with the Bankruptcy Court totaling~~totaled approximately ~~$51.3~~$51.7 billion. Of these claims, ~~filed, $9.9~~approximately $9.8 billion is related to California Independent System Operator, ~~(ISO)/~~or ISO, Power Exchange, ~~(PX)~~or PX, and generator claims. ~~Pursuant to the Bankruptcy Court's Order on Debtor's Omnibus Objection to Duplicate PX and Generator Claims,~~Under a bankruptcy court order the aggregate allowable amount of ~~these~~ISO, PX and generator claims iswas limited to approximately ~~$1.8 billion. Of that amount, approximately $0.2~~$1.6 billion ~~is subject to a pre-petition offset, thereby reducing the aggregate allowable amount~~after giving effect to approximately ~~$1.6 billion.~~$200 million in pre-petition offset. The Utility expects that this ~~$1.6 billion~~ amount will be further reduced as a result of certain proceedings pending at the FERC. Of the ~~remaining $43.0~~approximately $43.5 billion of filed claims, including the limited amount of ISO, PX and generator claims of approximately ~~$23.4~~$1.6 billion, ~~has been~~approximately $24.3 billion was disallowed by the ~~Bankruptcy Court~~bankruptcy court due to objections, claim withdrawals and agreements with claimants. The Utility has objected to ~~or intends to object to ,~~ approximately ~~$0.9~~$1.1 billion of the remaining ~~$19.6~~approximately $19.2 billion of filed claims. In addition, certain claims, including those related to environmental, pending litigation and tort claims, aggregating approximately $4.7 billion of the remaining ~~approximately $19.6~~$19.2 billion of filed claims, ~~approximately $5.5 billion of~~have passed through the bankruptcy. The Utility has analyzed these pass-through claims and has recorded reserves for such claims that are ~~expected to pass through~~included in the ~~Chapter 11 proceeding~~Utility's undiscounted environmental remediation liability of approximately $337 million at March 31, 2004 and ~~be determined~~the Utility's provision for legal matters of $191 million at March 31, 2004, as discussed below in ~~a forum other than~~Note 6. At March 31, 2004, the ~~Bankruptcy Court, or do not represent liabilities for which payment will be required~~Utility had made approximately $2.3 billion in claims-related principal payments and settled additional claims of approximately $300 million with the cancellation of certain bonds owned by the Utility. ~~Since the Utility's filing for Chapter 11 protection in April 2001, the Utility has made approximately $2.0 billion in claim-related principal payments.~~

The Utility has recorded its estimate of all valid claims at ~~September 30, 2003,~~March 31, 2004 as ~~$9.5~~approximately $9.2 billion of ~~Liabilities Subject~~liabilities subject to ~~Compromise, which includes~~compromise (including interest on ~~disputed claims,~~claims) and ~~$2.7~~approximately $2.4 billion of ~~Long-Term Debt. As of~~long-term debt. At December 31, ~~2002,~~2003, the Utility had recorded ~~$9.4~~approximately $9.5 billion of ~~Liabilities Subject~~liabilities subject to ~~Compromise. The increase from $9.4~~compromise and approximately $2.7 billion ~~is primarily due~~of long-term debt. Upon the effectiveness of the Plan of Reorganization, the Utility paid approximately $8.4 billion in cash to ~~interest accruals during the nine months ended September 30, 2003.~~

~~The Bankruptcy Court has authorized certain payments~~holders of allowed claims and ~~actions necessary~~deposited approximately $1.8 billion into escrow accounts for the ~~Utility~~payment of disputed claims, which is approximately equal to ~~continue its normal business operations while operating~~the amounts accrued as ~~a debtor-in-possession. For example,~~liabilities for these claims at that date (see the sources and uses of funds table as discussed above in the "Emergence From Chapter 11" section).

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

		March 31,		December 31,
(in millions)		2004		2003

PG&E Corporation
Senior secured notes, 6 ⅞%, due 2008		$	600	$	600
Convertible subordinated notes, 9.50%, due 2010			280		280
Other long-term debt		3		3

Total long-term debt		883		883


Utility
First and refunding mortgage bonds:
5.85% to 8.80% bonds, maturing 2004-2026			2,454		2,764
Unamortized discount net of premium			(23)		(23)

Total first and refunding mortgage bonds		2,431		2,741
First mortgage bonds
1.81% to 6.05% bonds, maturing 2006-2034		6,700		-
Unamortized discount net of premium		(18)		-

Total first mortgage bonds		6,682		-
Other⁽¹⁾		8		-
Less current portion⁽¹⁾		(4)		(310)

Total long-term debt, net of current portion			9,117		2,431


Total consolidated long-term debt, net of current portion		$	10,000	$	3,314




Long-term debt subject to compromise:
Senior notes, 10.75%, due 2005		$	680	$	680
Pollution control loan agreements, variable rates, due 2026		614		614
Pollution control loan agreement, 5.35%, due 2016		200		200
Unsecured medium-term notes, 6.94% to 9.58%, due 2004-2014		287		287
Deferrable interest subordinated debentures, 7.90%, due 2025		300		300
Other		17		17

Total long-term debt subject to compromise		$	2,098	$	2,098






(1)	Other includes debt of two low-income housing partnerships that have been consolidated on adoption of FIN 46R. At March 31, 2004, $7.3 million of the debt was in default due to the Utility's Chapter 11 filing. When the Utility emerged from Chapter 11 on April 12, 2004, this default was cured.

Utility

In March 2004, in connection with the implementation of the Plan of Reorganization, the Utility ~~is authorized to pay employee wages~~issued $6.7 billion of First Mortgage Bonds and, ~~benefits, amounts due under contracts~~together with ~~the majority~~its consolidated subsidiaries, entered into $2.9 billion of qualifying facilities (QFs), interest on certain secured and unsecured debt, environmental remediation expenses, and expenditures related to property, plant and equipment. In addition, the Utility is authorized to refund certain customer deposits, use certain bank accounts and make cash collateral deposits, and assume responsibility for various hydroelectric contracts.credit facilities. The Utility also ~~has received permission from the Bankruptcy Court to make payments~~obtained an interim $400 million cash collateralized letter of credit facility, which was terminated on ~~(1) pre- and post-petition interest on certain claims, (2) pre-petition secured debt that has matured, and (3) certain other claims.~~

~~The Utility has agreed to pay pre- and post-petition interest on Liabilities Subject to Compromise at the rates set forth below.~~

(in millions)
Amount Owed
Agreed Upon Interest Rate
at September 30, 2003
(per annum)
Commercial Paper Claims
$
873
8.216%
Floating Rate Notes
1,240
8.333%
Senior Notes
680
10.375%
Medium-Term Notes
287
6.560% to 9.200%
Revolving Line of Credit Claims
938
8.750%
Pollution Control Bonds
814
1.230% to 5.350%
QFs
52
5.000%
Other Claims
4,617
3.100% to 12.000%
Liabilities Subject to Compromise at September 30, 2003
$
  9,501

As the Utility's proposed plan of reorganization (see below) did not become effective on or before September 15, 2003, the interest rates for Commercial Paper Claims, Floating Rate Notes, Senior Notes, Medium-Term Notes, and Revolving Line of Credit Claims set forth above reflect an increase of a total of 75.0 basis points over the originally agreed upon rates, for periods on and after September 15, 2003. IfApril 12, 2004, the effective date of the ~~proposed plan~~Plan of ~~reorganization does not occur on~~Reorganization, or ~~before~~the Effective Date, and the letters of credit outstanding were transferred to the $850 million revolving credit facility.

First Mortgage Bonds

On March ~~15,~~23, 2004, the Utility closed a public offering of $6.7 billion of 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 ~~rates~~rate for ~~these claims~~the Floating Rate Mortgage Bonds is based on ~~and after such date~~the three-month LIBOR, plus 0.70%, that will ~~increase by an~~reset quarterly beginning on July 3, 2004.

In addition, approximately $2.5 billion of additional ~~37.5 basis points. For other claims,~~First Mortgage Bonds were used on the ~~Utility has recorded interest at the contractual or FERC-tariffed interest rate. When those rates do not apply, the Utility has recorded interest at the federal judgment rate.~~

~~Competing Plans of Reorganization~~

~~In September 2001, PG&E Corporation and the Utility submitted a proposed plan of reorganization~~Effective Date to ~~the Bankruptcy Court (the original plan of reorganization) that proposed to disaggregate~~secure the Utility's ~~current business~~credit facilities as described below and to ~~refinance~~secure the ~~restructured businesses. In April 2002,~~Utility's reimbursement obligation under an insurance policy relating to certain pollution control bonds that were issued for the ~~CPUC, later joined~~benefit of the Utility.

The First Mortgage Bonds are secured by ~~the Official Committee of Unsecured Creditors (OCC), submitted an alternate proposed plan of reorganization with the Bankruptcy Court that did not provide for disaggregation~~a first priority lien on substantially all of the Utility's ~~business. In March 2003,~~real property and certain tangible personal property related to the ~~Bankruptcy Court stayed~~Utility's facilities. Subject to certain conditions, the Utility will be entitled to terminate the lien and eliminate all ~~proceedings~~terms and conditions relating to ~~the confirmation trial~~collateral for the ~~competing plans to allow~~First Mortgage Bonds on the release date. In general, the release date will occur when the Utility provides written evidence to the CPUC, and certain other parties to participate in a judicially supervised settlement conference in order to explore the possibility of resolving the differences between the competing plans of reorganization and developing a consensual plan.

~~The Proposed CPUC Settlement Agreement~~

~~On June 19, 2003, PG&E Corporation, the Utility, and the staff~~trustee of the CPUC announced a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization. Under the proposed CPUC settlement agreement, PG&E Corporation and the Utility would agreeFirst Mortgage Bonds that the Utility remains a vertically integrated utility subject to the CPUC's jurisdiction. The proposed CPUC settlement agreement would permit the Utility to emerge from Chapter 11 as an investment grade rated company (at least BBB- from Standard & Poor's (S&P) and Baa3 from Moody's Investors Service (Moody's)), and to pay in full all the Utility's valid creditor claims, plus applicable interest.

The proposed CPUC settlement agreement contains a statement of intent that it is in the public interest to restore the Utility to financial health and to maintain and improve the Utility's financial condition in the future to ensure that the Utility is able to provide safe and reliable electricity and natural gas service to its customers at just and reasonable rates. In addition, the proposed CPUC settlement agreement includes a statement of intent that it is fair and in the public interest to allow the Utility to recover prior uncollected costs over a reasonable time and to provide the opportunity for shareholders to earn a reasonable rate of returnratings on the Utility's ~~business. Under~~long-term unsecured debt obligations following the ~~proposed CPUC settlement agreement,~~release date would at least equal the ~~Utility would release claims against the CPUC that the Utility or PG&E Corporation would have retained under the original plan of reorganization.~~

~~The Utility currently expects to have approximately $9.4 billion in total debt outstanding (excluding the rate reduction bonds)~~initial ratings assigned by Moody's and S&P on the ~~effective date~~First Mortgage Bonds or, if either or both of the Settlement Plan. The actual amount of debt that the Utility would issue will depend upon how certain claims are resolved and the amount of cash on hand at the time the Settlement Plan becomes effective, as well as cash requirements related to closing out any interestthese rating agencies do not then rate ~~hedges and whether all intended reinstated debt will be reinstated.~~

The proposed CPUC settlement agreement is subject to the approval of the Boards of Directors of PG&E Corporation and the Utility, as well as the CPUC. In addition, the proposed CPUC settlement agreement must be executed by all parties on or before December 31, 2003. The CPUC currently is expected to vote on the settlement agreement in late December 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed CPUC settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that was used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. Solicitation of creditor votes ended on September 29, 2003. On October 14, 2003, the Utility filed the voting results with the Bankruptcy Court. All of the creditor classes that voted on the Settlement Plan voted in favor of the Settlement Plan. The confirmation hearing began on November 10, 2003.

~~The principal terms of the proposed CPUC settlement agreement are as follows:~~

~~Regulatory Asset~~

The CPUC would agree to establish a $2.2 billion after-tax regulatory asset (Regulatory Asset), which equates to an approximately $3.7 billion pre-tax regulatory asset, as a new, separate and additional part of the Utility's ~~rate base that would be amortized on a ''mortgage-style'' basis over nine years beginning January 1, 2004. The Regulatory Asset would be fully amortized~~long-term unsecured debt obligations, comparable ratings by the end of 2012. The CPUC also would agree to authorize the Utility to establish a tax tracking account, to be used if the Utility must pay income tax on the Regulatory Asset before it is fully amortized, to record the difference between taxes on the Regulatory Asset plus interest imposed by federalany other nationally recognized rating agency or state tax authorities for earlier recognition and taxes that would have been incurred on account of the Regulatory Asset had it been taxed during the amortization period. The tax tracking account will earn the authorized rate of return and be amortized into rates over the longer of the remaining life of the Regulatory Asset or fi ve years.

The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's PX, ISO, QF, or energy service provider costs during the California energy crisis that the Utility realizes in cash or by offset of creditor claims in its Chapter 11 case will reduce the outstanding balance of the Regulatory Asset, dollar for dollar. Similarly, the net after-tax amounts received in cashagencies selected by the Utility ~~for electricity claims under~~. The First Mortgage Bonds received initial investment grade credit ratings of Baa2 from Moody's and BBB from S&P.
At the ~~master settlement agreement with El Paso Corporation and certain of its affiliates also would cause a reduction in the outstanding balance and the remaining amortization~~time of the ~~Regulatory Asset.~~

~~The Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent annually for its term and, after the equity component~~closing of the ~~Utility's capital structure reaches 52.00 percent, the authorized equity component~~offering of the ~~Regulatory Asset would be no less than 52.00 percent for~~First Mortgage Bonds, the ~~remaining term~~Plan of Reorganization was not yet effective. Therefore, the Utility deposited the proceeds of the ~~Regulatory Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.~~

~~Ratemaking Matters~~

The CPUC would agree that the Utility's rate base for its utility retained generation would be deemed just and reasonable and would not be subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and any change in authorized depreciation. This would result in the recording of an additional after-tax regulatory asset of approximately $0.8 billion (or approximately $1.3 billion pre-tax). The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would timely act upon the Utility's applications to collect in rates prudently incurred costs (including return of and return on) of any new and reasonable investment in utility plant and assets. The CPUC also would promptly adjust the Utility's rates consistent with the California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC's 2002 agreement with the California Department of Water Resources (DWR) regarding the establishmentsale of the DWR's revenue requirements to ensure that the Utility's collection of certain charges to service existing rate reduction bonds, regulatory asset amortization and return, and base revenue requirements (e.g., electricity and natural gas distribution, the Utility's rate base for its electricity generation, gas commodity procurement, existing QF contract costs, and associated return) are not impaired. The CPUC would not discriminate against the Utility because of theFirst Mortgage Bonds into an escrow account. See Note 2, "The Utility's Chapter 11 ~~case,~~Filing," for additional information concerning the ~~Utility's pending federal lawsuit against t he CPUC Commissioners to recover its previously incurred costs~~use of ~~providing electric service from ratepayers under~~proceeds of the ~~federal filed rate doctrine,~~sale of the ~~proposed CPUC settlement agreement, the Regulatory Asset, or any other matters addressed in or resolved by the proposed CPUC settlement agreement.~~

~~The CPUC would maintain the Utility's retail electric rates at current levels through December~~First Mortgage Bonds. On March 31, ~~2003. As of January 1,~~ 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed CPUC settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed CPUC settlement agreement includes a statement of intent that under the Settlement Plan, retail electricity rates would be reduced in January 2004, with further reductions expected thereafter.

~~The CPUC would set the Utility's capital structure and authorized ROE~~amount in the ~~Utility's annual cost of capital proceedings~~escrow account was classified as restricted cash in its usual manner. However, from January 1, 2004, until S&P has issued a long-term issuer credit rating for the Utility of at least A- or Moody's has issued an issuer credit rating for the Utility of at least A3, the authorized ROE would be no less than 11.22 percent per year and the authorized equity ratio for ratemaking purposes would be no less than 52.00 percent, except that for 2004 and 2005, the authorized equity ratio would equal the greater of the proportion of equity in the forecast of its average capital structure for calendar years 2004 and 2005 filed in the Utility's cost of capital proceeding and 48.60 percent.

The CPUC also would agree to act promptly on certain of the Utility's pending ratemaking proceedings, including the Utility's pending 2003 General Rate Case (GRC). The outcome of these proceedings may result in the establishment of additional regulatorynon-current assets on the Utility's Consolidated Balance ~~Sheets.~~

Sheet.

~~California Department of Water Resources Contracts~~Repayment Schedule

The ~~Utility would agree to accept an assignment of, or to assume legal and financial responsibility for,~~following table details the ~~DWR contracts that have been allocated to the Utility, but only if:~~

~~After assignment or assumption~~scheduled maturities of the ~~DWR contracts,~~Utility's long-term debt outstanding at March 31, 2004, excluding the ~~Utility receives a long-term issuer~~Utility's first and refunding mortgage bonds and debt subject to compromise that were repaid on the Effective Date.

(in millions)	2004		2005		2006		2007		2008		Thereafter		Total


Long-term debt:
Fixed rate obligations	$	-	$	-	$	-	$	-	$	-	$	5,082	$	5,082
Average interest rate	-%		-%		-%		-%		-%		5.34%		5.34%
Variable rate obligations	-		-		1,600		-		-		-		1,600
Other	4		2		1		-		-		1		8
Rate reduction bonds	216		290		290		290		-		-		1,086
Average interest rate	6.42%		6.42%		6.44%		6.48%		-%		-%		6.44%

Total	$	220	$	292	$	1,891	$	290	$	-	$	5,083	$	7,776

Credit Facilitiesand Short-Term Borrowings

The following table summarizes the Utility's lines of credit ~~rating of at least A from S&P~~ and ~~A2 from Moody's;~~

~~The CPUC first has made a finding that~~short-term borrowings subject to compromise, which were paid and cancelled on the ~~DWR contracts being assumed are just~~Effective Date, and ~~reasonable; and~~

~~The CPUC has acted to ensure~~credit facilities that the Utility ~~receives full~~ and ~~timely recovery in~~ its ~~retail electricity rates of all costs~~consolidated subsidiaries entered into on March 5, 2004. PG&E Corporation does not maintain credit facilities or short-term borrowings.

	Balance At

	April 12,		March 31,		December 31,
(in millions)	2004		2004		2003


Credit facilities subject to compromise:
5-year revolving credit facility	$	-	$	938	$	938

Total lines of credit subject to compromise		-		938	938

Short-term borrowings subject to compromise:
Bank borrowings - letters of credit for accelerated pollution control agreement	-		454		454
Floating rate notes		-		1,240	1,240
Commercial paper		-		873	873

Total short-term borrowings subject to compromise		-		2,567	2,567

Total credit facilities and short-term borrowings subject to compromise	$	-	$	3,505	$	3,505



Credit facilities:
Accounts receivable financing	$	350	$	-	$	-
Pollution control bonds reimbursement agreements		620		-	-
Pollution control bonds term loans		345		-	-
Amended and restated reimbursement agreements		454		-	-

Total credit facilities	$	1,769	$	-	$	-

On March 5, 2004, the Utility and its consolidated subsidiaries entered into credit facility agreements totaling approximately $2.9 billion. The credit facilities consist of the ~~DWR contracts without further review.~~

following:

~~Under~~Accounts Receivable Financing

On March 5, 2004, the ~~proposed CPUC settlement agreement,~~Utility entered into certain agreements providing for the ~~CPUC retains and, after any assignment or assumption~~continuous sale of ~~the DWR contracts, would retain the right to review the prudence~~a portion of the Utility's ~~administration~~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 will sell 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. Unless extended, the credit facility will terminate on March 5, 2007. The credit facility may be extended for additional periods under the agreement of all parties. The Utility began selling accounts receivables to PG&E ARC on the Effective Date and ~~dispatch~~used approximately $350 million that was received from the sale of the ~~DWR contracts consistent~~accounts receivable in connection with ~~applicable law.~~

~~Headroom~~

~~The CPUC would agree and acknowledge that~~this credit facility to pay allowed claims on the ~~headroom, surcharge, and base revenues accrued or collected by~~Effective Date. While PG&E ARC is a wholly owned conso lidated subsidiary of the Utility, ~~through~~PG&E ARC is legally separate from the Utility. The assets of PG&E ARC (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. For the purposes of financial reporting, the facility is accounted for as a secured financing.

The accounts receivable facility includes customary covenants on the Utility's part and on the part of PG&E ARC, including ~~December 31, 2003,~~covenants related to:

·	Servicing of the accounts receivables in accordance with the Utility's credit and collection policy;
·	Protecting the interests of the purchasers of the accounts receivable;
·	Maintenance of any governmental authorization or approval necessary in connection with the operation of the Utility's business; and
·	Indemnification of the purchasers.

Pollution Control Bonds Reimbursement Agreements

On March 5, 2004, the Utility entered into four separate reimbursement agreements under which the issuing lender issued, on the Effective Date, approximately $620 million in new letters of credit to support approximately $614 million aggregate principal amount of pollution control bonds that were previously issued for the benefit of the Utility.

The covenants under the pollution control bond reimbursement agreements are substantially the ~~property~~same as those of the working capital facility, as described below. On the Effective Date, the Utility secured its obligation under the four separate reimbursement agreements with First Mortgage Bonds.

Pollution Control Bonds Term Loans

On March 5, 2004, the Utility entered into a term loan facility of $345 million that was used to fund the purchase, in lieu of redemption, of certain pollution control bonds on the Effective Date, which is due and payable on June 5, 2005. At the Utility's request and at the sole discretion of each lender, the term loan facility may be extended for additional periods.

The covenants under the term loan facility are substantially the same as those of the working capital facility, as described below. On the Effective Date, the Utility secured its obligation under the term loan facility with First Mortgage Bonds.

Amended and Restated Reimbursement Agreements

During the course of the Utility's Chapter 11 ~~estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11~~ proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported under GAAP, less earnings from operations, (as has been historically define d by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

~~Dismissal of Filed Rate Case, Other Litigation, and Regulatory Proceedings~~

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice its case against the CPUC Commissioners asserting the "filed rate doctrine," withdraw the original plan of reorganization, and dismiss other pending proceedings. In exchange, on or before January 1, 2004, the CPUC would establish and authorize the collection of the Regulatory Asset and the Utility's rate base for its electricity generation, and on or as soon as practicable after the effective date, resolve phase 2 of the pending Annual Transition Cost Proceeding in which the CPUC is reviewing the reasonableness of the Utility's procurement costs incurred during the energy crisis with no adverse impact on the Utility's cost recovery as filed.

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, PG&E Corporation, the Utility, and the CPUC would execute mutual releases and dismissals with prejudice of specified claims, actions, or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).

~~Environmental Measures~~

~~The Utility would agree to implement three environmental enhancement measures:~~

~~The Utility would encumber with conservation easements or donate~~ approximately ~~140,000 acres of land to public agencies or non-profit conservation organizations;~~

~~The Utility would establish a California non-profit corporation to oversee the environmental enhancements associated with these lands and fund it with $70~~$454 million in ~~cash over 10 years, although the Utility would be entitled to recover these payments in rates; and~~

The Utility would create a non-profit corporation funded with $15 million payable by the Utility over five years dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory.

Of the approximately 140,000 acres referred to in the first bullet, approximately 45,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements.

~~Waiver of Sovereign Immunity~~

The CPUC would agree to waive all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Bankruptcy Court's order confirming the Settlement Plan (Confirmation Order). The CPUC also would consent to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the Bankruptcy Court. The CPUC's waiver would be irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off, or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order. The proposed CPUC settlement agreement contemplates tha t neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order.

~~Term and Enforceability~~

The proposed CPUC settlement agreement generally would terminate nine years after the effective date of the Settlement Plan, except that the rights of the parties to the proposed CPUC settlement agreement that vest on or before termination, including any rights arising from any default under the proposed CPUC settlement agreement, would survive termination for the purpose of enforcement. The parties would agree that the Bankruptcy Court would have jurisdiction over the parties for all purposes relating to enforcement of the proposed CPUC settlement agreement, the Settlement Plan, and the Confirmation Order. The parties also would agree that the proposed CPUC settlement agreement, the Settlement Plan, or any order entered by the Bankruptcy Court contemplated or required to implement the proposed CPUC settlement agreement or the Settlement Plan would be irrevocable and binding on the parties and enforceable under federal law, notwithstanding any contrary state law or future decisions or orders of the CPUC.

~~Fees and Expenses~~

The proposed CPUC settlement agreement would require the Utility to reimburse PG&E Corporation and the CPUC for their respective professional fees and expenses incurred in connection with the Chapter 11 proceeding once the Settlement Plan is confirmed. Of such amounts, the amounts reimbursed to the CPUC (but not to PG&E Corporation) would be recovered from ratepayers over a reasonable time of up to four years. As of September 30, 2003, PG&E Corporation has incurred expenses of approximately $128 million on the Utility's Chapter 11 proceeding.

~~Conditions of the Effectiveness of the Settlement Plan~~

~~The Settlement Plan provides that it would not be confirmed by the Bankruptcy Court unless and until the following conditions are satisfied or waived:~~

~~The Bankruptcy Court enters an order or orders:~~

Approving the Settlement Plan, authorizing the Utility to execute, enter into, and deliver the Settlement Plan, and to execute, implement, and take all actions necessary or appropriate to give effect to the transactions contemplated by the Settlement Plan;

~~Approving and authorizing the execution of, and finding reasonable the terms and conditions of, the proposed CPUC settlement agreement; and~~

~~The Confirmation Order is, in form and substance, reasonably satisfactory to PG&E Corporation, the Utility, the OCC, and the CPUC and specifically includes certain matters.~~

~~The Settlement Plan also provides that it would not become effective unless and until the following conditions are satisfied or waived:~~

~~The effective date occurs on or before March 31, 2004;~~

~~All actions, documents, and agreements necessary to implement the Settlement Plan are effected or executed;~~

PG&E Corporation and the Utility have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions, or documents that they deem necessary to implement the Settlement Plan;

~~The Settlement Plan has not been modified in a material way since the date of confirmation;~~

~~The Utility has consummated the sale of the debt securities contemplated by the Settlement Plan;~~

~~S&P has issued a long-term issuer credit rating for the Utility of not less than BBB- and Moody's has issued an issuer rating for the Utility of not less than Baa3;~~

~~S&P and Moody's have issued credit ratings for the debt securities to be offered by the Utility of not less than BBB- and Baa3, respectively;~~

~~The CPUC has given final nonappealable approval of the proposed CPUC settlement agreement on behalf of the CPUC;~~

~~Each of the parties to the proposed CPUC settlement agreement has executed and delivered the settlement agreement;~~

~~The CPUC has given final nonappealable approval for all of the financings, securities, and accounts receivable programs provided for in the Settlement Plan; and~~

~~The CPUC has given final nonappealable approval for all rates, tariffs, and agreements necessary to implement the Settlement Plan.~~

~~The last six conditions cannot be waived, except that PG&E Corporation and the Utility can waive the right to the finality provisions regarding CPUC approvals.~~

PG&E Corporation and the Utility are unable to predict whether and when the proposed CPUC settlement agreement will become effective or whether the Settlement Plan will be confirmed or implemented. If the Settlement Plan is not confirmed, or if the CPUC does not approve the proposed CPUC settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed CPUC settlement agreement in pending regulatory proceedings associated with the recovery of transition costs and surcharge revenues, or the allocation of DWR electricity to customers of investor-owned utilities (IOUs), as detailed in Note 6 below, then the Utility's financial condition and results of operations could be materially adversely affected.

~~NOTE 3: DEBT~~

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6⅞ percent Senior Secured Notes due 2008 (Notes). The net proceeds of the offering of approximately $582 million, together with cash on hand, were used to repay the principal balance outstanding under PG&E Corporation's existing credit agreement of approximately $735 million. A pre-tax loss of approximately $89 million was recorded in the third quarter of 2003 to reflect the write-off of unamortized loan fees, loan discount, and prepayment costs. The payment resulted in the termination of PG&E Corporation's existing credit agreement and the release of liens on PG&E Corporation's shares of NEGT, Inc., as well as the prior lien on approximately 94 percent of the outstanding common stock of the Utility.

~~The following description is a summary of the material provisions of the indenture.~~

~~Principal, Maturity, and Interest~~

The Notes mature on July 15, 2008. Interest on the Notes accrues at the rate of 6⅞ percent per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2004.

~~Additional Notes~~

The indenture governing the Notes permits PG&E Corporation to issue additional notes from time to time after this offering. Any such offering of additional notes will be subject to limitations as set forth in the covenants of the indenture and further discussed below.

~~Security~~

The Notes are secured by a perfected first-priority security interest in approximately 94 percent of the outstanding common stock of the Utility that is owned by PG&E Corporation. With respect to 35 percent of such common stock pledged for the benefit of the lenders, the holders have customary rights of a pledge of common stock, provided that certain regulatory approvals may be required in connection with any foreclosure on and any exercise of the right to vote such stock. With respect to the remaining 65 percent, such common stock has been pledged for the benefit of the holders, but the holders have no ability to control such common stock under any circumstances and do not have any of the typical rights and remedies of a secured creditor. However, the holders do have the right to receive any cash distributions associated with such common stock.

The Notes are effectively subordinated to all indebtedness and other obligations (including trade payables) of PG&E Corporation's subsidiaries. In the event of a bankruptcy, liquidation or reorganization of any of PG&E Corporation's subsidiaries, such subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to PG&E Corporation.

~~Redemption~~

~~At any time prior to July 15, 2006, PG&E Corporation may on one or more occasions redeem up to 35 percent of~~ the aggregate principal amount of pollution control bonds, which were issued for the ~~Notes issued under~~Utility's benefit, were redeemed through draws on letters of credit, giving rise to an obligation to reimburse the ~~indenture at a redemption price~~issuers of ~~106.875 percent~~these letters of credit or their respective assignees for the amounts drawn. On the Effective Date, the Utility amended the four separate reimbursement agreements and restated them after the lenders had purchased the $454 million in reimbursement obligations owed to the issuers of the ~~principal amount, plus accrued and unpaid interest and additional interest, if any,~~drawn letters of credit or their respective assignees. The Utility expects to repay the ~~redemption date, with the net cash proceeds of one or more public sales of capital stock for cash by PG&E Corporation after the issue date of the Notes, providedthat:~~

At least 65 percent of the aggregate principal amount of the Notes issued under the indenture remains outstanding immediately after the occurrence of each such redemption (excluding Notes held by PG&E Corporation and its subsidiaries); and

~~Any such redemption occurs within 120 days of the date of the closing of such sale of capital stock.~~

At any time prior to July 15, 2006, PG&E Corporation may, at its option, redeem all or a portion of the Notes at the make-whole price, specified in the indenture, plus accrued and unpaid interest to the redemption date. Except as described in the preceding paragraphs, the Notes will not be redeemable at PG&E Corporation's option prior to July 15, 2006.

On and after July 15, 2006, PG&E Corporation may redeem all or a part of the Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and additional interest, if any, on the Notes redeemed, if redeemed during the 12-month period beginning on July 15 of the years indicated below:

Year

Percentage
2006

103.438%
2007

101.719%

PG&E Corporation is not required to make mandatory redemption or sinking fund payments with respect to the Notes. In the case of a change of control, spin-off, or reorganization event, PG&E Corporation is required to offer to repurchase the Notes.

~~Restrictions~~

PG&E Corporation and its restricted subsidiaries, as defined in the indenture, are subject to the restrictive covenants of the indenture. PG&E Corporation's principal subsidiaries, the Utility and NEGT, Inc., are defined as unrestricted subsidiaries and are not subject to many of the restrictive covenants in the indenture. The Notes contain limitations, among other restrictions, on the ability of PG&E Corporation and its restricted subsidiaries to grant liens, consolidate, merge, sell assets, declare or pay dividends, incur indebtedness, and perform certain affiliate transactions.

~~Dividends~~

~~The Note indenture prohibits PG&E Corporation from declaring or paying dividends unless, as specified in the indenture, it has either met certain financial criteria, and no default is~~amounts outstanding under the ~~indenture~~amended and restated reimbursement agreements through the issuance of new refunding pollution control bonds or ~~would result from~~otherwise. The outstanding balance of $454 million under the ~~payment~~amended and restated reimbursement agreements is due and payable on June 5, 2005. At the Utility's request and at the sole discretion of such dividends or a specified exception applies. These specified exceptions include circumstances in which: (1) PG&E Corporation achieves an investment grade credit rating, or (2) following the implementationeach lender, each amended and restated reimbursement agreement may be extended for additional periods.

The covenants under each amended and restated reimbursement agreement are substantially identical to those of the working capital facility, as described below. On the Effective Date, the Utility secured its obligations under the amended and restated reimbursement agreements with First Mortgage Bonds.

Working Capital Facility

On March 5, 2004, the Utility entered into an $850 million revolving credit facility, or working capital facility, with a syndicate of banks. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash flows. 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. The working capital facility has a term of three years and all outstanding amounts will be due and payable on March 5, 2007. At the Utility's ~~Settlement Plan, PG&E Corporation pays any dividend~~request and at the sole discretion of each lender, the working capital facility may be extended for additional periods. On the Effective Date, the Utility secured its obligation under the working capital facility with First Mortgage Bonds. On the Effective Date, approximately $206 million of letters of credit from a cash c ollateralized $400 million letter of credit facility was transferred to the ~~proceeds of cash distributions to PG&E Corporation from the Utility. Certain of these exceptions also include the requirement that~~working capital facility with no ~~default is~~loans outstanding under the ~~indenture or would result from the payment~~working capital facility.

The working capital facility includes customary covenants, including covenants related to:

·	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;
·	Prohibition on the disposition of assets, other than dispositions of inventory and obsolete property in the ordinary course, in excess of 25% of the aggregate book value of the Utility's and the Utility's significant subsidiaries' assets at December 31, 2003;
·	A limitation on liens no more restrictive than the limitation on liens that becomes effective under the indenture from and after the release date;
·	Limitation on mergers and sales of all or substantially all of the Utility's assets; and
·	Maintenance of any governmental authorization or approval necessary in connection with the operation of the Utility's business.

Cash Collateralized Letter of ~~such dividends.~~

~~Covenant Termination~~Credit

Upon the first date the Notes are rated BBB- or better by S&P and Baa3 or better by Moody's and no material default has occurred and is continuing under the indenture, PG&E Corporation and its restricted subsidiaries will cease to be subject to certain restrictive covenants of the indenture, such as restrictions on dividends, payments, asset sales, and affiliate transactions. In addition ~~after~~to the ~~conditions are satisfied, PG&E Corporation may secure additional indebtedness using~~$2.9 billion in credit facilities, 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 ~~common stock as collateral in an amount up to 15 percent~~preexisting and new natural gas procurement activities and related purchases of ~~its consolidated tangible assets, defined as its total consolidated assets less goodwill~~natural gas transportation services. This credit facility was terminated on the Effective Date, and ~~intangible assets.~~

~~Events~~the outstanding balance of ~~Default~~

~~The Notes contain certain events~~approximately $206 million of ~~default, including PG&E Corporation's failure to pay any indebtedness~~letters of ~~$50 million or more. Upon certain events of default, the Notes will become due and payable immediately.~~

~~Registration Rights, Additional Interest~~

~~Pursuant to a Registration Rights Agreement, PG&E Corporation has agreed to file an exchange offer registration statement with the SEC with respect~~credit outstanding was transferred to the Notes by April 27, 2004, and must use its best efforts to cause such registration statement to be declared effective by June 26, 2004. If PG&E Corporation does not register the Notes in accordance with the Registration Rights Agreement, PG&E Corporation will be required to pay additional interest of up to approximately 1 percent annually, until the Notes have been registered.$850 million working capital facility.

NOTE 4: DISCONTINUED OPERATIONS

On July 7, 2003, PG&E Corporation's representatives who previously served on the NEGT, Inc. Board of Directors resigned and were replaced with Board members who are not affiliated with PG&E Corporation. Subsequently, on July 8, 2003, NEGT, Inc. and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On July 29, 2003, two additional subsidiaries of NEGT, Inc. also filed voluntary Chapter 11 petitions. Pursuant to Chapter 11, NEGT, Inc. and those subsidiaries retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On July 8, 2003, NEGT ~~Inc. also~~ filed a ~~proposed plan~~voluntary petition for relief under Chapter 11. The combination of ~~reorganization with~~ the ~~Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest~~decline in wholesale electricity prices, the financial commitments related to NEGT's construction program, the decline of NEGT's credit rating to below investment grade, and the lack of market liquidity created severe financial distress and ultimately caused NEGT ~~Inc. On October 3, 2003, the Bankruptcy Co urt authorized PG&E NEG~~ to ~~change its name to NEGT, Inc. The change reflects NEGT, Inc.'s pending separation from PG&E Corporation.~~

seek protection under Chapter 11. As a result of ~~NEGT, Inc.'s~~NEGT's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the NEGT, Inc. Board of Directors, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT, Inc. PG&E Corporation anticipates that the Bankruptcy Court will approve NEGT, Inc.'s proposed plan of reorganization, or a plan with similar equity loss provisions for PG&E Corporation. Therefore, as of July 8, 2003, PG&E Corporation has classified NEGT, Inc. as a discontinued operation, deconsolidated the operations of NEGT, Inc. and has reflected its ownership interest in NEGT, Inc. utilizing the cost method of accounting.

~~As a result of NEGT, Inc.'s Chapter 11 filing on July 8, 2003, and the proposed loss~~elimination of equity ownership provided for in ~~NEGT, Inc.'s~~NEGT's plan of reorganization, PG&E Corporation considers its investment in NEGT ~~Inc.~~ to be an abandoned asset and has accounted for NEGT ~~Inc.~~ as a discontinued ~~operation~~operations in accordance with SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT ~~Inc.~~ and its subsidiaries are reported as discontinued operations in the Consolidated Statements of ~~Income~~Operations through July 7, 2003 and for all prior ~~periods reported. In addition, all prior period assets~~periods.

Effective July 8, 2003, NEGT and ~~liabilities of NEGT, Inc., shown for comparative purposes,~~its subsidiaries are ~~classified as discontinued operations.~~

~~NEGT, Inc. is~~ no longer consolidated by PG&E Corporation in its ~~consolidated financial statements.~~Consolidated Financial Statements. The accompanying ~~September 30, 2003,~~March 31, 2004 Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of ~~NEGT, Inc.;~~NEGT; rather, a liability of approximately $1.2 billion is reflected, which represents the losses of NEGT ~~Inc.~~ recognized by PG&E Corporation in excess of its investment in and advances to ~~NEGT, Inc.~~NEGT. In addition, accumulated ~~OCI~~other comprehensive income includes a net ~~debit~~charge of approximately $77 million at ~~September 30,~~December 31, 2003 related to ~~NEGT, Inc.~~NEGT. The accompanying Consolidated Statements of ~~Income~~Operations of PG&E Corporation for the ~~three- and nine-month periods~~three months ended ~~September 30,~~March 31, 2003 ~~and 2002~~ present the operations of NEGT ~~Inc. through July 7, 2003~~ as discontinued operations. PG&E Corporation's investment in NEGT ~~Inc.~~ will not be affected by changes in ~~NEGT, Inc.'s~~NEGT's future financial results, other than (1) ~~investments~~inv estments in or dividends from NEGT, ~~Inc.,~~ or (2) income ~~tax es~~taxes PG&E Corporation may be required to pay if the ~~Internal Revenue Service~~IRS disallows certain deductions or tax credits ~~attributable~~related to NEGT ~~Inc. and~~or its subsidiaries for past tax years that are incorporated into PG&E Corporation's consolidated tax returns.

Upon implementation of ~~NEGT, Inc.'s~~NEGT's plan of reorganization, ~~that eliminates PG&E Corporation's equity in NEGT, Inc.,~~ PG&E Corporation will reverse its investment in NEGT ~~Inc.~~ and the related amounts included in deferred income taxes and in accumulated ~~OCI~~other comprehensive income and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations. ~~Any unrealized~~This amount will be reduced by any potential liability for NEGT claims related to contractual obligations, if any. The deferred tax assets ~~relating to~~arising from the losses ofrelated to NEGT ~~Inc.~~or its subsidiaries that have been recognized through July 7, 2003 will reverse at the time PG&E Corporation releases its ownership interest in ~~NEGT, Inc.~~NEGT. This reversal of deferred tax assets will partially offset any one-time gain recognized when PG&E Corporation ~~writes off~~recognizes the gain related to its net investment in ~~NEGT, Inc.~~NEGT. On May 3, 2004, NEGT's plan of reorganization was confirmed by the bankruptcy court. The plan of reorganization is expected to become effective during the second quarter of 2004. The effective date is contingent upon certain conditions being met within 90 days following the plan confirmation.

NEGT ~~Inc.~~ Operating Results

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

Seven days
ended July 7,
Three months ended
September 30,
188 Days
ended July 7,
Nine months ended
September 30,
(in millions)
2003
2002
2003
2002
Operating Revenues
$
35
$
524
$
786
$
1,390
Loss Before Income Taxes
(8)
(98)
(595)
(413)

~~Prior to the abandonment of NEGT, Inc. by~~

		Three Months Ended
(in millions)		March 31, 2003


Operating revenues⁽¹⁾		$	664
Loss before income taxes⁽¹⁾		(421)
Net income⁽¹⁾		(271)



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

Before PG&E Corporation began accounting for NEGT ~~Inc.~~as discontinued operations, 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 ~~July 7,~~March 31, 2003 and the other previously discontinued operations through the respective disposal dates. ~~NEGT, Inc.'s~~The first quarter 2003 pre-tax loss of NEGT and its subsidiaries includes the following gains and losses on disposal of those subsidiaries: a pre-tax gain of approximately $19 million ~~pre-tax gain~~ 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 ~~pre-tax loss~~ on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003. Also included in the first quarter 2003 ~~and a $9 million~~ pre-tax loss ~~on disposal related to the sale of certain Ohio generating plants and related equipment in the second quarter of 2003.~~

During the second quarter of 2003, NEGT, Inc. determined that its historical financial reporting presentation of revenues and expenses related to hedging and certain ISO purchase and sales transactions had not been consistent. Certain types of transactions had been reported on a net basis (whereby revenues had been offset by the related expense item)are impairments, write-offs, and other ~~types~~charges of transactions had been reported on a gross basis. In order to provide a consistent reporting of its trading and hedging transactions, NEGT, Inc. adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of presentation is preferable under the circumstances. Adopting this change reduced previously reported revenues and expenses of NEGT, Inc. by $643 million for the nine months ended September 30, 2002, and $381 million for the three months ended September 30, 2002. In addition, adjustments were made principally for the effects of transactions that had not previously been eliminated in conso lidation by NEGT, Inc. Such adjustments decreased previously reported revenues and expenses by $339million for the nine months ended September 30, 2002, and $166million for the three months ended September 30, 2002. These changes did not result in any change in the consolidated operating income or net income, the Consolidated Balance Sheets, or the Consolidated Statements of Cash Flows.

In October 2002, the EITF rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133 continue to be accounted for at fair value under SFAS No. 133. Contracts that previously were marked to market as trading activities under EITF 98-10 and that did not meet the definition of a derivative are accounted for at cost. For PG&E Corporation, the majority of trading contracts are derivative instruments as defined in SFAS No. 133. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133. The reporting requirements associated with the rescission of EITF 98-10 were applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002, although the number of energy trading contracts subject to the prospective implementation was considered immaterial.

~~NEGT, Inc. Balance Sheet Information~~

The following table reflects the condensed assets and liabilities of NEGT, Inc. as reflected in current and noncurrent assets and liabilities in the accompanying Consolidated Balance Sheet of PG&E Corporation at December 31, 2002:

~~Balance at~~
~~(in millions)~~
~~December 31,~~
~~2002~~
~~Assets~~
~~Total current assets~~
$
~~3,029~~
~~Net property, plant and equipment~~
~~2,939~~
~~Total other non-current assets~~
~~1,944~~
~~Total assets~~
~~7,912~~
~~Liabilities~~
  ~~Debt in default~~
~~4,230~~
  ~~Long-term debt, classified as current~~
17
  ~~Other current liabilities~~
~~2,410~~
~~Total current liabilities~~
~~6,657~~
  ~~Long-term debt~~
~~630~~
  ~~Price risk management~~
~~305~~
  ~~Other non-current liabilities and deferred credits~~
~~972~~
~~Total non-current liabilities~~
~~1,907~~
~~Total liabilities~~
~~8,564~~
~~Excess of liabilities over assets~~
$
~~(652)~~
approximately $199 mill ion.

Commitments and Contingencies of NEGT ~~Inc.~~

With its Chapter 11 filings, NEGT ~~Inc. was~~affiliates defaulted on numerous agreements. The amounts due as a result of these defaults will be determined and resolved in ~~default under various debt agreements and guaranteed equity commitments totaling approximately $5.6 billion,~~the context of ~~which approximately $2.8 billion was debt that is non-recourse to~~ NEGT ~~Inc. At July 8, 2003, NEGT, Inc. did not have sufficient cash to meet its financial obligations and ceased making payments on its debt and equity commitments.~~Chapter 11 filings. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

NEGT ET, a NEGT, Inc. subsidiary, entered into tolling agreements with several counterparties under which, at its discretion, NEGT ET supplied the fuel to power plants and then sold the plant's output in the competitive market. On July 8, 2003, NEGT ET petitioned the Bankruptcy Court to reject all remaining tolling agreements. On August 6, 2003, the Bankruptcy Court approved NEGT ET's motion. Although each tolling agreement allows for the determination of a termination payment, PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

NEGT, Inc. and certain subsidiaries have provided guarantees in support of NEGT ET's energy trading and non-trading activities related to NEGT, Inc.'s merchant energy operations. With its Chapter 11 filing on July 8, 2003, NEGT ET defaulted on numerous trading agreements. The amounts due as a result of these defaults will be determined and resolved in the context of NEGT ET's Chapter 11 filing. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

NOTE 5: PRICE RISK MANAGEMENT

As discussed in Note 4, NEGT ~~Inc.~~ financial results are no longer consolidated inwith those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of ~~NEGT, Inc. NEGT, Inc.'s~~NEGT. NEGT's financial results through July 7, 2003 are reflected in ~~Discontinued Operations. Subsequent to July 7, 2003,~~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.

Convertible Subordinated Notes

PG&E Corporation currently has outstanding $280 million of Convertible Notes, that are scheduled to mature on June 30, 2010. These Convertible Notes may be converted into 18,558,655 shares of common stock of PG&E Corporation. In addition, the terms of the Convertible Notes also entitle the note holders to participate in any dividend payments (non-cumulative) based on their equity conversion value.

In accordance with SFAS No. 133, the above dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be marked-to-market through earnings and its fair value must be reflected on the balance sheet. At March 31, 2004, the estimated fair value of the dividend participation rights component was $19million (net of taxes), which was reflected in PG&E Corporation's Consolidated Statement of Operations as a non-operating expense and as a noncurrent liability (Other Liabilities) on PG&E Corporation's Consolidated Balance Sheet. In the periods leading up to March 31, 2004, the fair value of the dividend participation rights component was immaterial.

Non-Trading Activities

~~At September 30, 2003,~~ On the ~~Utility had $8 million of~~Utility's Consolidated Balance Sheets, cash flow hedges associated with ~~natural gas commodity price~~interest rate risk ~~the longest of which extend through March 2004. These contracts~~ are presented at fair value ~~on PG&E Corporation's and the Utility's Consolidated Balance Sheets~~ in other current ~~assets~~assets. For hedges associated with regulated operations and ~~regulatory liabilities.The fair value~~subject to the provisions of ~~these hedges is~~SFAS No. 71, the effective and ineffective portions are recorded in regulatory ~~liabilities because the hedges are recoverable through rates.~~assets. At ~~September 30, 2002,~~March 31, 2003, the Utility did not have any cash flow hedges.

~~There were no ineffective portions of changes in amounts of the Utility's cash flow hedges for the three- and nine-month periods ended September 30, 2003, and 2002.~~

The Utility has certain non-trading ~~contracts~~derivative instruments for the purchase of electricity, and natural gas transportation and storage that are either exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception or are not derivative instruments and, ~~thus~~therefore, have no mark-to-market effect on earnings. Additionally, the Utility ~~has~~holds other non-trading derivative ~~contracts~~instruments that do not qualify for cash flow hedge accounting or the normal purchase and sales exception to SFAS No. 133. ~~These derivatives are reported~~The fair value of these derivative instruments is recorded in ~~earnings on a mark-to-market basis.~~other current assets or liabilities offset by regulatory liabilities or assets.

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. These obligations are reflected as Accounts Receivable - Customers, net and notes receivable included in Other Noncurrent Assets - Other on the Consolidated Balance Sheets of PG&E Corporation and the Utility.

PG&E Corporation had gross accounts receivable of ~~$1.9~~approximately $2.1 billion at ~~September 30, 2003~~March 31, 2004 and ~~$2.0~~approximately $2.5 billion at December 31, ~~2002.~~2003. 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 ~~$60~~approximately $61 million at ~~September 30, 2003,~~March 31, 2004 and ~~$59~~approximately $68 million at December 31, ~~2002,~~2003 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~~northern and central California. However, ~~the risk of~~ material loss due to non-performance from ~~these~~thes e 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 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 three months of 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At March 31, 2004, there were three counterparties that represented greater than 10% of the Utility's net credit exposure. The Utility had three investment grade counterparties that represented a total of approximately 53% of the Utility's net credit exposure.

The Utility conducts business with ~~customers or vendors primarily~~wholesale counterparties mainly in the energy industry, including other California ~~IOUs,~~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.

The Utility manages credit risk for its largest customers (counterparties) by assigning credit limits to counterparties based on an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Each counterparty's credit limit and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure is calculated daily, and in the event that exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure, or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require the counterparty to post 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 counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty's credit collateral. During the nine-month period ended September 30, 2003, the Utility recognized no losses due to contract defaults or bankruptcies of counterparties. At September 30, 2003, the Utility had two investment grade counterparties that represented 33 percent of the Utility's net credit exposure and two below-investment grade counterparties that represented 24 percent of the Utility's net credit exposure.

The schedule below summarizes the Utility's net asset credit risk exposure, ~~to counterparties that are in a net asset position,~~ as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than ~~10 percent~~10% net credit exposure, at ~~September 30, 2003,~~March 31, 2004 and December 31, ~~2002:~~2003.

(in millions)
Gross Credit
Exposure Before
Credit Collateral⁽¹⁾

Credit
Collateral

Net Credit
Exposure⁽²⁾

Number of
Counterparties
>10 percent

Net Exposure of
Counterparties
>10 percent

September 30, 2003 ⁽³⁾
$
141
$
8
$
133
4
$
76
December 31, 2002
288
113
175
2
55
(1)
Gross credit exposure equals mark-to-market value, notes receivable, and net (payables) receivables where netting is 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 incurred prior to the Utility's Chapter 11 filing 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.
(3)
Excludes post-petition exposures to Enron.

(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%


March 31, 2004		$	160	$	16	$	144	3	$	77
December 31, 2003		165		11		154		3	68



(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 incurred prior to the Utility's Chapter 11 filing 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.

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, 2003,~~March 31, 2004 and December 31, ~~2002.~~2003:

Credit Quality⁽¹⁾
Net Credit
Exposure⁽²⁾
Percentage of Net
Credit Exposure
(in millions)
September 30, 2003
   Investment grade⁽³⁾
$
98
74%
   Non-investment grade
35
26%
Total
$
133
100%
December 31, 2002
   Investment grade⁽³⁾
$
111
63%
   Non-investment grade
64
37%
Total
$
175
100%
(1)
Credit ratings are determined by using publicly available credit ratings of the counterparty. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the rating determination is based on the rating of its 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.
(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 quality.

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


Credit Quality⁽¹⁾

March 31, 2004
Investment grade⁽³⁾		$	138	96%
Non-investment grade		6		4%

Total		$	144	100%




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

Total		$	154	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.
(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.
(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.

NOTE 6: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility's operating activities. PG&E ~~Corporation has limited financial commitments relating to NEGT, Inc.'s operating activities. These~~Corporation's and the Utility's commitments are discussed more fully in ~~PG&E Corporation's and~~their combined 2003 Annual Report filed with the ~~Utility's combined 2002 Annual~~Current Report on Form ~~10-K, as amended.~~8-K dated March 2, 2004. The following summarizes PG&E Corporation's and the Utility's material contingencies and canceled, new, and significantly modified commitments since the combined ~~2002~~2003 Annual Report filed with the Current Report on Form ~~10-K, as amended,~~8-K dated March 2, 2004, was filed.

Commitments

Utility

Power Purchase Agreements

During the first quarter of 2004, the Utility entered into various agreements to purchase energy. Under these agreements, the Utility is committed to make energy payments of approximately $52 million and capacity payments of approximately $19 million in 2004.

Natural Gas Supply and Transportation ~~Commitments-~~Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United ~~States.~~States to serve its core customers. The ~~composition~~contract lengths and natural gas sources of the Utility's portfolio of natural gas procurement contracts ~~has~~have fluctuated generally based on market conditions.

~~The Utility also has long-term gas transportation service agreements with various Canadian and interstate pipeline companies. These companies are responsible for transporting~~ As a result of the Utility's gas to the California border. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges thatChapter 11 filing and its credit rating being below investment grade, the Utility ~~will pay each year may change due~~had used several different credit arrangements to ~~changes in regulated tariff rates.~~purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. On March 2, 2004, these pledge facilities were replaced with a $400 million limited cash collateralized letter of credit facility, or gas procurement letter of credit facility. The gas customer accounts receivable program terminated effective March 29, 2004. At March 31, 2004, amounts secured by this gas procurement letter of credit facility totaled approximately $203 million. Upon emergence from Chapter 11 the Utility canceled this gas procurement letter of credit facility and transferred the outstanding balance to an $850 million revolving credit facility backed by the Utility's new credit faciliti es.

At ~~September 30, 2003,~~March 31, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2003	$	247
2004		478	$	678
2005		89	168
2006		26	26
2007		7	7
2008			-
Thereafter		-	-

Total	$	847	$	879

The Utility provides a $10 million standby letter of credit and a pledge of its natural gas customer accounts receivable as security for its purchases of natural gas from certain suppliers. The Utility's natural gas inventory also may be pledged, but only if the Utility's natural gas customer accounts receivable are less than the amount that the Utility owes to the natural gas suppliers secured by the pledge. To date, the accounts receivable pledge has been sufficient. The pledge amounts were $198 million at September 30, 2003, and $513 million at December 31, 2002. The CPUC authorized the Utility to pledge its natural gas customer accounts receivable and natural gas inventory, if necessary, until the earlier of:

~~May 1, 2004;~~

~~15 days after an upgrade of the credit rating of the Utility's mortgage bonds to at least BBB- by S&P or Baa3 by Moody's;~~

~~The effective date of a plan of reorganization; or~~

~~The dismissal or conversion of the Utility's Chapter 11 proceeding.~~

Transmission Control ~~Agreement-~~Agreement

The Utility ~~entered into~~is a party to a Transmission Control Agreement, ~~(TCA)~~or TCA, with the ISO and other participating transmission owners. As a transmission owner, the Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, ~~(SCE) and~~or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their ~~electric~~electricity transmission systems to the ISO. In addition, as a party to the TCA, the Utility is responsible for a share of the costs of ~~Reliability Must-Run (RMR)~~reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, ~~(RMR Plants).~~or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO's demand.

At ~~September 30, 2003,~~March 31, 2004, the ISO ~~has~~had RMR agreements ~~that obligate~~for which the Utility ~~for approximately $868~~could be obligated to pay the ISO an estimated $666 million in net costs during the period ~~October~~April 1, ~~2003,~~2004, to ~~September 30, 2005.~~March 31, 2006. These costs are recoverable under 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 (ALJ)~~ALJ issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of ~~the~~ Mirant Corporation, ~~(Mirant)~~or 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 $340 million, including interest, for ~~the~~ availability of Mirant's ~~generating facilities~~RMR Plants under ~~the RMR~~these agreements. ~~If the FERC were to affirm the ALJ's initial decision, the Utility would expect refunds of approximately $300 million, including interest. On~~However, on July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 ofand on December 15, 2003, the ~~Bankruptcy Code.~~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 on this issue, what ~~that~~the FERC's decision will be, and the amount of any refunds, ~~the Utility will ultimately receive,~~ which may be impacted by ~~Mirant's~~Miran t's Chapter 11 filing. ~~Any refunds received~~It is uncertain how the resolution of this matter would be ~~used to reduce previously under-collected transition and procurement costs or to lower RMR costs depending on the time period covered by the refunds.~~reflected in rates.

Irrigation Districts and Water Agencies - The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any energy is supplied (subject to the supplier's retention of the FERC's authorization), and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031.Enron Settlement

~~At September 30,~~ On December 23, 2003, ~~the undiscounted future expected irrigation districts and water agencies payments were as follows:~~

(in millions)
Operations
& Maintenance
Debt Service
2003
$
11
$
7
2004
41
28
2005
35
26
2006
31
26
2007
30
27
Thereafter
214
168
Total
$
362
$
282

Tri-Valley Project - The Tri-Valley project is a multi-year project to site and construct electric transmission and distribution facilities to serve electric load growth in the area of Livermore, San Ramon, Pleasanton and the adjacent areas. The Bankruptcy Court approved the capital expenditure of $135.9 million, which includes Utility labor and supplier equipment, in February 2002. At September 30, 2003, the Utility's total commitments for third-party services and equipment for the project were approximately $21 million, payable through 2005.

Electricity Purchases to Meet Demand- On January 1, 2003, the Utility resumed the function of procuring electricity to meet the portion of its customers' needs that is not covered by the combination of the allocation of electricity from existing DWR contracts and the Utility's own electric generation resources and contracts. To meet this requirement, the Utility entered into ~~contracts for fuel supply, capacity, and transmission rights. In order to enter into these contracts,~~a settlement agreement with five subsidiaries of Enron Corporation, or Enron, settling certain claims between the Utility ~~has posted collateral with~~and Enron, or the ~~California ISO~~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 ~~several~~uses of funds table in Note 2. As a result of the Enron Settlement, the Utility will receive an after-tax credit of approximately $114 million that will reduce the Settlement Regulatory Asset and other ~~counterparties. These contracts, with terms of one year or less, did not have a material impact~~regulatory balancing accounts. In the rate design settlement approved by the CPUC on February 26, 2004, the Utility's ~~commitments previously disclosed in its 2002 Annual Report on Form 10-K, as amended.~~

~~In August 2003, the Utility filed an application requesting that the CPUC approve the Utility's 2004 Energy Resource Recovery Account (ERRA) forecast~~ revenue requirement of $1.5 billion associated with the Utility's 2004 short-term procurement plan and approve as reasonable the Utility's ERRA recorded costs for the period from January 2003 through May 2003. The CPUC's review of the Utility's procurement activities will examine the Utility's least-cost dispatch of the resource portfolio, fuel expenses for the Utility's electricity generation, contract administration, including administration of the DWR allocated contracts, the Utility's existing QF contracts and other power purchase agreements, renewable energy contracts, and the decision to engage in market transactions in the context of the Utility's overall prudent contract administration and least-cost dispatch of generation resources. The Utility has also asked the CPUC to approve its proposed revenue requirement of $840 million to recover the 2004 costs related to the ~~above-market generation and procurement costs and certain other generation-related costs.~~

~~In June 2003,~~amortization of the Settlement Regulatory Asset has been reduced to reflect an estimate of the after-tax credit included in the Enron Settlement. The CPUC ~~issued a~~ decision ~~pursuant~~approving the rate design settlement provides for regulatory balancing account treatment to SB 1078 that adopts the framework for implementing a Renewable Portfolio Standard (RPS) program. The decision requires the Utility to increase procurement of renewable energy by at least 1 percent of its retail sales per year. By the end of 2017, the Utility must be procuring at least 20 percent of its total electricity from renewable resources. Under SB 1078, the Utility is not obligated to purchase additional renewable energy until it received an investment grade credit rating. However, under subsequently enacted SB 67, the Utility may be required to purchase additional renewable energy once it is able to do so on reasonable terms and the renewable energy contracts will not impair the restoration of its creditworthiness. Until that time, the Utility will accumulate an annual procurement target (APT) based on 1 percent of annual retail sales. When the Utility receives an investment grade credit rating or the CPUC determinesensure that the ~~SB 67 require ments are satisfied,~~amount of the ~~Utility expects~~revenue requirement reduction is adjusted to ~~enter into purchase contracts for renewable energy to meet its accumulated APT.~~

~~Although~~reflect the Utility cannot predict what the terms, including price, of such contracts would be, the decision requires that the procurement price under such contracts be at or below a market price benchmark established by the CPUC after the bids have been received. If the Utility exceeds its APT, it can apply the excess to meet the APT in future years. For under-procurement, the decision allows IOUs to carry over an annual deficit of 25 percent to the next three years without explanation. Failure to meet minimum APTs without prior CPUC approval would result in an automatic penalty of $0.05 per kWh, subject to an annual penalty cap of $25 million. The Utility currently estimates that the annual 1 percent increase in renewable resource electricity in its portfolio will initially require between 80 and 100 megawatts (MW) of additional renewable capacity to be added per year.

~~The CPUC approved offers submitted~~net after-tax amounts actually received by the Utility ~~that were sufficient to meet the Utility's 2003 renewable~~under settlements with energy requirement in December 2002. In September 2003, the Utility submitted to the CPUC for approval several renewable contracts pursuant to an assigned commissioner ruling in August 2003 that permitted bilateral negotiations with renewable suppliers, ~~prior to the implementation of renewable energy portfolio standard requirements. The CPUC approved the contracts in October 2003.~~including Enron.

Contingencies

The Utility has significant gain and loss contingencies, which are discussed below.

~~Surcharge Revenues~~

In January 2001, the CPUC increased electric rates by $0.01 per kWh, in March 2001 by another $0.03 per kWh, and in May 2001 by an additional $0.005 per kWh. The use of these surcharge revenues was restricted to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. Based on these CPUC decisions and an agreement between the CPUC and SCE, another IOU, in which SCE was allowed to use its $0.005 per kWh surcharge to offset its DWR revenue requirement, the Utility has continued to recognize revenues related to the $0.01 per kWh, $0.03 per kWh, and $0.005 per kWh surcharges after the statutory end of the retail electric rate freeze, which was March 31, 2002, even without considering the proposed settlement agreement in the Utility' s Chapter 11 proceeding (discussed in Note 2). As such, the Utility has not recorded a regulatory liability or a reserve for the potential refund of these surcharge revenues, or any portion thereof, as of September 30, 2003. From January 2001 to September 30, 2003, the Utility recognized total surcharge revenues of approximately $7.5billion, pre-tax.

Under the proposed settlement agreement discussed in Note 2, the CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement agreement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported unde r GAAP, less earnings from operations (as has been historically defined by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

In July 2003, a CPUC Commissioner issued a proposed decision finding that the retail electric rate freeze ended on January 18, 2001. The proposed decision also provides that the CPUC would determine in a separate proceeding the extent and disposition of costs previously defined as uneconomic, transition, or stranded. The proposed decision contemplates that the separate proceeding would also determine whether the recovery of these costs has been fully addressed or resolved in the Utility's Chapter 11 proceeding or in other CPUC proceedings. The Utility has filed comments suggesting that the CPUC defer its decision on these issues pending the CPUC's consideration of the proposed CPUC settlement agreement and the implementation of the Settlement Plan. The Utility cannot predict the ultimate outcome of this proceeding.

In August 2003, the California Supreme Court issued a decision on questions certified to it by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) regarding the validity of a settlement agreement between the CPUC and SCE. The decision concluded that the CPUC had the authority to enter into a settlement agreement with SCE that allowed SCE to recover under-collected purchased power and generation-related transition costs beyond the end of the rate freeze in light of the provisions of AB 1890, which prohibited post-freeze recovery of transition and procurement costs, and that the settlement agreement did not violate California law. This matter has now been returned to the Ninth Circuit for final disposition. In October 2003, the California Supreme Court denied a petition for rehearing of its decision that had been filed by The Utility Reform Network (TURN).

The Utility's ability to retain its surcharge revenues may be adversely affected if the proposed CPUC settlement agreement and Settlement Plan are not implemented or if, either in response to certain judicial decisions or on its own initiative, the CPUC changes its interpretation of law or otherwise seeks to change the Utility's overall retail electric rates retroactively. If the proposed CPUC settlement agreement is not approved and the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially adversely affected.

2003 General Rate Case

In On April 6, 2004, a proposed decision was issued in the Utility's 2003 GRC pending at the ~~CPUC will determine~~CPUC. The 2003 GRC determines the amount of authorized base revenues the Utility can collect from ~~ratepayers~~customers to recover its basic business and operational costs for electricity and natural gas distribution operations and ~~electric distribution~~for electricity generation operations for 2003 and succeeding years. ~~In addition,~~The ALJ's proposed decision, excluding changes in attrition rate adjustments, would approve essentially all of the ~~CPUC also will determine~~provisions contained in ~~this~~the July 2003 ~~GRC the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business~~ and ~~operational costs for the Utility's retained generation.~~

In September 2003 settlement agreements reached among the Utility and various ~~intervenors (TURN,~~consumer groups to set the Utility's 2003 revenue requirements for its electricity generation and electricity and natural gas distribution operations.

If the proposed decision is adopted by the CPUC, the Utility's total 2003 revenue requirements, as provided in the settlement agreements, would be set at approximately:

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

In addition, under the proposed decision, if the Utility forecasts a second refueling outage at the Diablo Canyon nuclear power plant 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 Consumer Price Index, or CPI, in the manner described in the proposed decision. The only forecasted second refueling outage will occur in 2004.

The proposed decision would reject the Utility's request for approximately $75 million in additional revenue requirements to fund a pension contribution. If adopted, the proposed decision would be retroactive to January 1, 2003.

Because the CPUC has not yet issued a final decision on the Utility's 2003 GRC, the Utility has not included the natural gas distribution revenue requirement increase in its 2003 or 2004 results of operations. If the CPUC approves a 2003 revenue requirement increase in 2004, the Utility would record both the 2003 and 2004 natural gas distribution revenue requirement increase in its 2004 results of operations.

The proposed decision is scheduled to be considered by the CPUC on May 6, 2004. A final decision is expected in the second quarter of 2004. If the proposed decision is approved, as written in the second quarter, the Utility would record regulatory assets and liabilities associated with the revenue requirement increases (including attrition), recovery of unfunded taxes, depreciation, and decommissioning. The net impact of these items is anticipated to result in pre-tax earnings of approximately $400 million.

Also, on April 6, 2004, the CPUC issued a separate proposed decision to address an agreement between the Utility and the CPUC's Office of Ratepayer Advocates, (ORA), Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council, and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of a settlement agreement these parties entered into inor ORA, relating to the Utility's 2003 GRC proceeding (2003 GRC settlement agreement), also filed with the CPUC. The parties reached agreement on all disputed economic issues related to the electricity and natural gas distribution revenue requirement of the 2003 GRC, with the exception of the Utility's request that the CPUC include the costs of a pension contribution in the Utility's revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, based upon briefs submitted on September 17, 2003, and reply briefs submitted on October 8, 2003, in its final decision and the Utility's GRC revenue requirements will be adjusted appropriately.

The 2003 GRC settlement agreement proposes that the Utility would receive a total 2003 revenue requirement of approximately $2.5 billion for electric distribution operations, representing a $236 million increase in the Utility's electric distribution revenue requirements over the current authorized amount. The settlement agreement provides that the amount of electricity distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be $7.7 billion, based on recorded 2002 plant and including net weighted average capital additions for 2003 of $292 million. The 2003 GRC settlement agreement also provides that the Utility will implement a new balancing account, effective January 1, 2004, to ensure that the Utility recovers its authorized electric distribution revenue requirements regardless of the level of sales.

The 2003 GRC settlement agreement also would result in total 2003 revenue requirement of approximately $927 million for the Utility's natural gas distribution operations, representing a $52 million increase in the Utility's natural gas distribution revenue requirement over the current authorized amount. The settlement agreement also provides that the amount of natural gas distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be $2.1 billion, based on recorded 2002 plant, and including weighted average capital additions for 2003 of approximately $89 million.

If the Utility prevails on the pension contribution issue, an additional revenue requirement of approximately $75 million would be allocated among electric distribution, gas distribution, and electric generation operations.

~~The parties have agreed that the Utility's next GRC will be to determine rates for test year 2007.~~

Only one party, the DWR, filed comments on the settlement agreement. The parties responded to these comments on October 7, 2003. Depending on the CPUC's review of these comments, a hearing may be held regarding the settlement. PG&E Corporation and the Utility are unable to predict the outcome of this matter.

~~In another phase of the GRC addressing how the Utility responds~~response to storm outages and other reliability issues and an agreement the Utility reached an agreement with ORA that would allow the Utility to recover up to $9 million in 2003, with a lower cap of up to $2.3 million in each of the years 2004, 2005, and 2006. The Utility also reached an agreement with the California Coalition of Utility Employees that ~~proposes~~proposed a reliability performance incentive mechanism for the Utility beginning in 2004 and continuing through 2009. ~~Under~~Among other things, the CPUC accepted the reliability standards proposed by the Utility and ORA and approved certain reliability improvement initiatives as well as the funding for these initiatives, but rejected the proposed incentive ~~mechanism,~~mechanism.

PG&E Corporation and the Utility would receive a maximum reward or penalty of $42 million each year depending on whether it met the improvement targets on its outage duration and frequency performance. In order to provide the Utility the opportunity to achieve the improvement targets, the agreement provides for up to $27 million in additional revenues each year of the incentive mechanism (to be recorded in a one-way balancing account) to be spent exclusively on reliability improvement activities . Both of these agreements are ~~pending CPUC approval.~~

In December 2002, the CPUC ordered that the 2003 GRC be effective January 1, 2003. The parties have requested that the CPUC issue a final decision approving the settlement agreement and resolve all remaining issues on or before February 5, 2004.

~~If the 2003 GRC settlement agreement is not approved by the CPUC, and if the Utility is~~ unable to ~~conform to the base revenue amounts~~predict whether these proposed decisions will be adopted by the CPUC. If the CPUC ~~while maintaining safety and system reliability standards,~~does not approve the ~~ability of~~settlement agreements, the ~~Utility~~Utility's ability to earn its authorized rate of return for the years until the next GRC would be adversely affected. As previously discussed, the rate changes implemented during the first quarter of 2004 contemplated approval for the 2003 GRC consistent with the settlement agreements. To the extent that the final GRC is different from the settlement agreements, rates will be trued-up.

PX Block-Forward Contracts

~~Allocation of DWR Electricity to Customers~~ 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 ~~IOUs~~

~~In September 2002,~~state, acting under California's Emergency Services Act. The block-forward contracts had an estimated unrealized gain of up to $243 million at the ~~CPUC issued a decision to allocate~~time the ~~electricity provided under existing DWR contracts to~~state of California seized them. The Utility, the ~~customers~~PX, and some of the ~~IOUs.~~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 plaintiff's valuations. The ~~DWR retains legal and financial responsibility for these contracts.~~

~~Under~~estimated value of the ~~proposed CPUC settlement agreement~~seized contracts has been fully reserved in the Utility's ~~Chapter 11 proceeding, the CPUC could require the Utility to accept assignment of, or assume legal and~~ financial ~~responsibility for, the DWR allocated contracts for which the Utility currently acts as billing and collection agent, but only if:~~

~~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 contracts being assumed are just and reasonable; and~~

~~The CPUC has acted to ensure full and timely recovery in the Utility's retail electricity rates of all contract costs without further review.~~

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC retains, and after any assignment or assumption of DWR contracts, the CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.statements. This state court litigation is pending.

Nuclear Insurance

The Utility has several types of nuclear insurance for its Diablo Canyon ~~Power Plant~~power plant and Humboldt Bay ~~Power Plant.~~Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, ~~(NEIL).~~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 additional ~~annual~~ premiums of up to ~~$36.7~~$40.2 million.

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, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

Under the Price-Anderson Act, ~~(Act),~~ public liability claims from a nuclear incident are limited to ~~$10.9~~$10.8 billion. As required by the Price-Anderson Act, the Utility ~~has~~ purchased the maximum available public liability insurance of $300 million for the Diablo Canyon ~~Power Plant.~~power plant. The balance of the ~~$10.9~~$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 reactors 100 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. Since the Diablo Canyon ~~Power Plant~~power plant has two nuclear reactors over 100 MW, ~~the~~t he Utility may be assessed up to $201.2 million per incident, with ~~payment s~~payments in each year limited to a maximum of $20 million per incident. ~~In February~~Although the Price-Anderson Act expired on December 31, 2003, ~~a provision extending~~coverage continues to be provided to all licensees, including the ~~Act through the end of 2003 was adopted by the U.S. Congress. No other material terms~~Diablo Canyon power plant, which had coverage before December 31, 2003. Congress may address renewal of the Price-Anderson Act ~~changed as a result of the provision.~~in future energy legislation.

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

Workers' Compensation Security

The Utility is self-insured for workers' compensation. The Utility must deposit collateral with the California Department of Industrial Relations, ~~(DIR)~~or DIR, to maintain its status as a self-insurer for workers' compensation claims made against the Utility. Acceptable forms of collateral include surety bonds, letters of credit, cash and securities. At ~~September 30, 2003,~~March 31, 2004, the Utility provided collateral in the form of ~~approximately $365~~$305 million in surety ~~bonds.~~bonds and approximately $43 million in a cash deposit.

In February 2001, several surety companies provided cancellation notices because of the Utility's financial situation. The cancellation of these bonds has not impacted the Utility's self-insured status under California law. The DIR has not agreed to release the canceling sureties from their obligations for claims occurring ~~prior to~~before the cancellation and has continued to apply the canceled bond amounts, totaling $185 million, toward the ~~$365~~$348 million collateral requirement. At ~~September 30, 2003, three additional~~March 31, 2004, the Utility's $348 million in collateral consisted of the $185 million in cancelled bonds, $120 million in active surety bonds totaling $180 million make up the Utility's collateral. On October 10, 2003, the Utility replaced one active $60 million surety bond with a cash deposit of $43 million. Total collateral at October 10, 2003, is $348 million, which consists of $305 million in surety bonds and approximately $43 million in cash. PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with these surety bonds and the Utility's underlying obligation to pay ~~worke rs'~~workers' compensation claims.

On emergence from Chapter 11, PG&E expects to be eligible to participate in the Alternative Security Program, or ASP, administered by California's Self-Insurers' Security Fund, or SISF. PG&E was ineligible to participate in the ASP while in Chapter 11. The ASP is a program that allows the SISF to arrange a composite deposit for eligible self-insureds on a portfolio basis, rather than individual self-insurers arranging their deposits individually. SISF arranges portfolio security to be delivered to DIR for the aggregate self-insured workers' compensation liabilities for participating self-insurers. The Utility's participation in the ASP will result in the release of the $348 million collateral that existed at March 31, 2004.

~~Balancing Account Reserves~~El Paso Settlement

In ~~2002,~~June 2003, the Utility, along with SCE, the state of California and a number of other parties, entered into the El Paso settlement, 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 period from September 1996 to March 2003. Under the El Paso settlement, El Paso will pay approximately $1.5 billion in cash and non-cash consideration, of which approximately $550 million is now in an escrow account and approximately $875 million will be paid over 15 to 20 years. The Utility's share of the approximately $1.5 billion settlement is approximately $300 million. El Paso also agreed to a reduction of approximately $125 million in El Paso's long-term electricity supply contracts with the California Department of Water Resources, or DWR, to provide pipeline capacity to California and to ensure specific reserve capacity for the Utility, if needed. In October 2003, the CPUC ~~ordered~~approved an allocation of these refunds, under which the Utility's natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $216 million. The net-after-tax amount of any consideration that the Utility ~~to create certain electric balancing accounts to track specific electric-related amounts, including revenue shortfalls from baseline allowance increases and costs~~actually receives in cash related to the ~~self-generation incentive program,~~electricity refunds will reduce the outstanding balance of the Settlement Regulatory Asset. The settlement was approved by the FERC in November 2003 and by the San Diego Superior Court in December 2003. An appeal of the attorney's fees award to class action plaintiffs' counsel in the litigation is pending, but that appeal will not affect the effectiveness of the settlement. The Superior Court's approval of the settlement is now final and is no longer subject to appeal. The refunds will be released from the escrow account when the settlement becomes effective according to its terms. The Utility believes it is probabl e that all conditions precedent to the effectiveness of the settlement will be satisfied soon.

Williams Settlement

On February 24, 2004, the Utility and SCE entered into a settlement agreement with The Williams Companies, or Williams settlement, settling certain pre-petition claims in the Utility's Chapter 11 proceeding. In order for the settlement to become effective, it must first be approved by the CPUC as to SCE, and the FERC. If the Williams settlement is approved, the Utility will receive an after-tax credit of approximately $41 millionthat will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. Certain settlement issues are still being resolved and could impact the amount the Utility ultimately receives.The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements with en ergy suppliers, including The Williams Companies.

Dynegy Settlement

In April 2004, the Utility, along with SCE, San Diego Gas and 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. In order for this settlement to become effective, it must first be approved by the CPUC and the FERC. If the Dynegy 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 below under "FERC Prospective Price Mitigation Relief" below. The CPUC decision appr oving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements with energy suppliers, including Dynegy.

FERC Prospective Price Mitigation Relief

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. In December 2002, a FERC ALJ issued an initial decision 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 (the only time period for which the ~~CPUC has not yet determined specific recovery methods. In~~FERC permitted refund claims), but that California buyers still owe the ~~decisions ordering~~power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

During 2003, the ~~creation~~FERC confirmed most of ~~these balancing accounts,~~ the ~~CPUC~~ALJ's findings, 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 ~~recovery method for these~~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 ~~would~~owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by November 2004. The PX cannot make its compliance filing until after the ISO makes its filing. The actual refunds will not be determined until the FERC issues a final decision, following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in ~~the future. Because the Utility cannot conclude that the amounts in these balancing accounts are considered probable of recovery in~~this proceeding, after which appell ate review is expected. In addition, future ~~rates, the Utility has reserved these balances by recording a charge against earnings. As of September 30, 2003, the reserve associated with these balancing accounts was approximately $262 million.~~

~~DWR Revenue Requirement~~

~~In 2001,~~refunds could increase or decrease as a result of an alternative calculation proposed by the ~~California energy crisis,~~ISO, which incorporates revised data provided by the ~~State~~Utility and other entities. The FERC has indicated that it does not have the power to direct refunds for the period before October 2, 2000, but has engaged in an investigation of market manipulation and sought through settlement or hearings disgorgement of profits for any tariff violations during this period. Unless settled among the various entities, this conclusion will also be subject to judicial review.

Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the state of California ~~authorized~~in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the ~~DWR~~Utility's ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding will reduce the balance of the Settlement Regulatory Asset.

The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to ~~purchase electricity~~compromise. This amount is subject to ~~satisfy~~a pre-petition offset of approximately $200 million, reducing the ~~difference between~~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 filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the ALJ's initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further redu ce 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.

DWR Contracts

The DWR provided approximately 24% of the electricity delivered to the Utility's customers for the three-month period ended March 31, 2004. 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 ~~the~~a utility's customers, ~~of the IOUs and the electricity those utilities had available for delivery~~plus applicable reserve margins, not satisfied from ~~their~~that utility's own generation facilities and ~~power purchase arrangements. California's AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of~~existing electricity ~~and to issue revenue bonds to finance electricity purchases.~~contracts. The DWR isremains legally and financially responsible for the ~~long-term~~electricity procurement contracts.

The 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 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.

The DWR has stated publicly that it ~~entered into before December 31, 2002. It pays~~intends to transfer full legal title to, and responsibility for, ~~its costs~~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 ~~purchasing electricity from a revenue requirement collected from~~ the ~~Utility's electricity customers through a charge, called a~~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 ~~charge. Because~~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 ~~the~~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.

~~In December 2002, the CPUC issued a decision allocating approximately $2 billion~~ Because of this pass-through nature of amounts collected on behalf of the ~~DWR's 2003 $4.5 billion total statewide power charge-related revenue requirement to the Utility's customers. This revenue requirement includes the forecasted costs associated with the~~ DWR, ~~allocated contracts during 2003. A December 2002 operating order required~~and because the Utility ~~to perform the operational, dispatch, and administrative functions for the DWR allocated contracts beginning~~is on ~~January 1, 2003. In April 2003, the Utility and the DWR entered into a CPUC-approved operating agreement that supersedes the December 2002 operating order.~~

~~In July 2003, the DWR submitted a supplemental 2003 revenue requirement to the CPUC that reduced the amount~~cost of the total 2003 statewide power charge-related revenue the DWR was requesting by approximately $1 billion. In September 2003, the CPUC issued a decision that allocated this $1 billion reduction among the customers of the three California IOUs. The decision allocated approximately $444 million of the reduction to the customers of the Utility and required the Utility to provide a one-time bill credit to the Utility's customers to pass through the revenue requirement reduction. Prior ambiguities in the formula that determines the calculation of the Utility's collections payable to the DWR resulted in the Utility's underpayment of amounts the Utility paid the DWR through June 30, 2003. These ambiguities were resolved by the CPUC in a decision issued in September 2003. As of June 30, 2003, the Utility had accrued a $516 million reserve based on the Utility's estimate of underpayments. During Sept ember 2003, the Utility paid the DWR $77 million (which equals the $521 million shortfall ultimately determined to be due to the DWR, less the Utility's $444 million share of the DWR's $1 billion statewide revenue reduction). This $444 million share of the statewide revenue reduction has been returned to the Utility's customers in the form of bill credits issued in September and October 2003. The September 2003 decision also reduces the Utility's DWR power charge base remittance rate (before adjusting for direct access remittances for DWR power) from $0.105 per kWh to $0.095 per kWh effective immediately. This reduction in the remittance rate is in addition to the $444 million reduction described above. In September 2003, the Utility filed an advice letter proposing to further reduce the rate from $0.095 to $0.085 effective October 1, 2003, to account for amounts collected and remitted from direct access customers. This advice letter is currently pending before the CPUC.

The CPUC's allocation of the DWR's revenue requirement for the 2001-2002 period among the three California IOUs is subject to true-up adjustments based on the actual amount of power purchased by the DWR for the respective IOU's customers during the 2001-2002 period. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from the IOUs' electricity customers through a power charge and a bond charge. The CPUC originally allocated approximately 48.3 percent of the adopted DWR power charge revenue requirement for the 2001-2002 period, or about $4.4 billion, to the Utility.

In testimony submitted to the CPUC on October 15 and 22, 2003, the Utility estimated that it over-remitted $107 million in power charges to the DWR for the 2001-2002 period based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. The Utility also proposed that the CPUC use a different allocation methodology under which the Utility estimates it over-remitted $211 million. Testimony submitted by SCE and other parties includes varying estimates of the Utility's true-up adjustment depending on the allocation methodology proposed. SCE calculated that the Utility over-remitted approximately $101 million in power charges to the DWR based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. However, SCE also has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requirement to allocate the bond pr oceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

The Utility has proposed to include any true-up adjustments to the DWR's 2001-2002 revenue requirement in each IOU's allocation of the 2004 DWR revenue requirement to be collected through the 2004 DWR remittance rate. SCE supports this proposal, but San Diego Gas & Electric Company has proposed that any under-remittance that an IOU is determined to owe should be paid by the IOU immediately. CPUC hearings began on October 27, 2003, and the CPUC is expected to issue a decision on the 2001-2002 adjustments (as well as the 2004 DWR revenue requirement) in January 2004.

~~PG&E Corporation and the Utility expect that any amounts determined by the CPUC to have been under-remitted or over-remitted to the DWR by the Utility for the 2001-2002 period will be included~~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

NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT's Board of Directors in ~~2004~~NEGT's Chapter 11 proceeding, asserting, among other claims, that NEGT is entitled to be compensated under an alleged implied tax sharing agreement between PG&E Corporation and ~~subsequent periods,~~NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and ~~collected~~deductions related to NEGT or ~~refunded on~~its subsidiaries in PG&E Corporation's consolidated federal income tax return. In May 2003, PG&E Corporation received a ~~going-forward basis~~return of $533 million from the ~~Utility's customers. However,~~IRS for an overpayment of 2002 estimated federal income taxes. In November 2003, NEGT and its creditors amended their complaint to add additional causes of action arising out of or related to the filing by PG&E Corporation of its 2002 federal consolidated tax return and certai n restructuring negotiations that occurred between PG&E Corporation and certain of NEGT's creditors prior to NEGT's Chapter 11 proceeding, including claims for breach of contract, breach of fiduciary duty, violation of the automatic stay, turnover, an accounting, unjust enrichment, fraudulent transfer, constructive trust, breach of standstill agreement, deceit, equitable subordination and indemnification. NEGT and the creditors' committees seek a declaration that an implied tax sharing agreement exists between PG&E Corporation and NEGT as well as injunctive relief prohibiting PG&E Corporation from taking certain tax positions on its consolidated tax returns in the future. The complaint also alleges a cause of action for breach of fiduciary duty against two PG&E Corporation officers who previously served on NEGT's Board of Directors.

NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporation and are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (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 seek punitive damages against PG&E Corporation and the ~~Utility are unable~~former NEGT directors for breach of fiduciary duty and seek punitive damages against PG&E Corporation for deceit as well as interest, costs of suit, and reasonable attorney's fees.

On April 6, 2004, in response to ~~predict~~defendants' motion to dismiss many of the plaintiffs' claims, the bankruptcy court entered a memorandum decision, dismissing the following claims: (1) violation of the automatic stay, (2) turnover of property, (3) an accounting, (4) injunctive relief, (5) constructive trust, (6) equitable subordination, and (7) indemnification. The bankruptcy court denied the motion to the extent that it sought dismissal of plaintiffs' claims for breach of fiduciary duty, declaratory judgment, unjust enrichment, fraudulent conveyance, breach of standstill agreement, and deceit. Accepting plaintiffs' allegations as true, as the court is required to do on a motion to dismiss, the bankruptcy court concluded that plaintiffs stated a claim or that factual issues existed with respect to these claims that precluded dismissal at this stage of the proceeding.

Defendants filed a motion in the U.S. District Court of Maryland seeking to transfer the litigation from the bankruptcy court to the District Court. On April 22, 2004, the District Court approved the motion to transfer, and set a trial date for March 2005.

PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses, deductions or tax credits related to NEGT or its subsidiaries into PG&E Corporation's consolidated federal tax returns, as required under the Internal Revenue Code. Until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash. PG&E Corporation anticipates continuing to incorporate losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation's consolidated income tax return, until it is no longer consolidated for federal income tax purposes. NEGT and its creditors have asserted that NEGT should be compensated for any such tax savings.

PG&E Corporation does not expect that the outcome of this ~~matter. If the CPUC retroactively determines that the Utility has under-remitted~~matter will have a material ~~amount to the DWR and orders the Utility to make a one-time true-up payment from cash~~adverse effect on ~~hand rather than collect the under-remitted amount from customers on a going-forward basis, the Utility's financial condition and~~its results of operations, ~~would be materially adversely affected.~~

In October 2003, in connection with the Utility's prior lawsuit against the DWR, a California court of appeal issued a decision finding that the DWR is required by law to conduct a review to determine whether its revenue requirements are just and reasonable, but also finding that the California Administrative Procedure Act did not require the DWR to hold public hearings as part of its determination. If some of the DWR's costs are ultimately determined not to have been reasonably incurred and therefore disallowed from recovery from the Utility's customers, then the DWR's charges for these costs to ratepayers may be reduced within the Utility's service territory. The Utility cannot predict the ultimate outcome of this matter.

~~PG&E Corporation~~

~~As discussed above, PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with certain surety bonds and the Utility's obligations to pay workers' compensation claims.~~financial position or liquidity.

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, ~~(CERCLA),~~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 ~~(1)~~ current technology, ~~(2)~~ enacted laws and regulations, ~~(3)~~ experience gained at similar sites and ~~(4)~~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 occu r 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 ~~$323~~approximately $337 million at ~~September 30, 2003,~~March 31, 2004 and ~~$331~~approximately $314 million at December 31, ~~2002.~~2003. During the first ~~three quarters~~quarter of ~~2003,~~2004, the liability ~~was reduced~~increased by $8approximately $23 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The ~~$323~~approximately $337 million accrued at ~~September 30, 2003,~~March 31, 2004 includes ~~(1) $105~~approximately $103 million related to the pre-closing remediation liability associated with divested generation facilities and ~~(2) $218~~approximately $234 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third party disposal sites and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas ~~plant~~pla nt sites. Of the ~~$323~~approximately $337 million environmental remediation liability, approximately $146 million has been included in prior rate setting proceedings and the Utility ~~has recovered $152~~expects that approximately $136 million ~~and expects to recover approximate ly $114 million of the balance~~will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever ~~it is~~ possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to ~~refunds~~refund to ratepayers.

The cost of the hazardous substance remediation is difficult to estimate. The estimate depends on a number of uncertainties, including the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, which is based upon a range of reasonably possible outcomes. The Utility's undiscounted future costs could increase to as much as ~~$418~~$454 million if ~~(1)~~ the other potentially responsible parties are not financially able to contribute to these costs, ~~(2)~~or the extent of contamination or necessary remediation is greater than ~~anticipated,~~anticipated. The approximately $454 million amount does not include an estimate for the cost of remediation at known sites owned or ~~(3)~~operated in the past by the Utility's predecessor corporations for which the Utility ~~is found~~has not been able to ~~be responsible for clean-up costs at additional sites.~~determine whether liability exists.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the ~~clean-up.~~clean up. Other sites identified in the California Attorney General's claims may not, in fact, require remediation or clean-up actions. ~~Since the~~The Utility's ~~proposed plan~~Plan of ~~reorganization~~Reorganization provides that the Utility ~~intends to~~will respond to these types of claims in the ~~regular~~ordinary course of business, and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General's claims seeking specific cash recoveries are ~~unenforcea ble.~~

Diablo Canyon - The Utility's Diablo Canyon Power Plant employs a "once-through" cooling water system, which is regulated under a National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). This permit allows the Diablo Canyon Power Plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon Power Plant's discharge was not protective of beneficial uses.

In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon Power Plant protects beneficial uses and that the intake technology reflects the "best technology available," as definedunenforceable. Environmental claims in the ~~Federal Clean Water Act. As part~~ordinary course of the Central Coast Board settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On June 17, 2003, the settlement was fully executed by the Utility, the Central Coast Board, and the Attorney General's Office. In order for the Central Coast Board settlement agreement to become effective, among other things, the Central Coast Board must renew the Diablo Canyon Power Plant's NPDES permit. However, at its July 10, 2003, meeting, the Central Coast Bo ard didbusiness were not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

~~The California Attorney General has filed a claim~~discharged in the Utility's Chapter 11 proceeding ~~on behalf~~and have passed through the Chapter 11 proceeding unimpaired.

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.

Chromium Litigation

There are 14 civil suits pending against the Utility in several California state courts. 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 with the bankruptcy court, most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants filed claims for an "unknown amount." Pursuant to the Plan of Reorganization, these claims have passed through the Utility's Chapter 11 proceeding unimpaired and will be satisfied by the Utility in the ordinary course of business.

In general, plaintiffs and claimants 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 death, or other injury and seek related damages. On the effective date of the ~~Central Coast Board seeking unspecified penalties and other~~Plan of Reorganization, 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 ~~in connection with~~from the ~~Diablo Canyon Power Plant's operation of its cooling water system.~~stay can proceed.

The Utility is ~~seeking withdrawal of this claim.~~

responding to the suits in which it has been served and is asserting affirmative defenses. The Utility ~~believes~~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 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 court began hearing argument on two of the motions in February 2004, but no rulings have been issued. Although the trial date had previously been scheduled to begin in March 2004, the court vacated the trial date and no new trial date has been set.

The Utility has recorded a $160 million reserve in its financial statements for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at March 31, 2004, the ultimate outcome of this matter will not have a material adverse impact on ~~its consolidated~~PG&E Corporation's or the Utility's financial ~~position~~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.

The provision for legal matters is included in PG&E Corporation's and the Utility's ~~Other Noncurrent Liabilities~~other noncurrent liabilities in the Consolidated Balance Sheets, and totaled ~~$209~~$191 million (which includes the $160 million reserve discussed above) at ~~September 30, 2003,~~March 31, 2004 and ~~$202~~$205 million at December 31, ~~2002.~~

~~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. The Utility's Chapter 11 filing on April 6, 2001, discussed in Note 2, automatically stayed the litigation described below against the Utility, except as otherwise noted.

~~Chromium Litigation~~

There are 14 civil suits pending against the Utility in several California state courts. 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 have filed proofs of claims with the Bankruptcy Court, most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an "unknown amount."

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 test trial has been scheduled to begin in March 2004. The Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs. Two of the 13 summary judgment motions are scheduled for hearing in December 2003, and two are scheduled for hearing in January 2004. The Utility also has filed a motion to dismiss the complaint in one of the cases that is scheduled to be heard on November 14, 2003.

The Utility has recorded a $160 million reserve in its financial statements for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at September 30, 2003, 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.

~~Natural Gas Royalties Litigation~~

This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America, against more than 330 defendants, including the Utility. The cases were consolidated for pretrial purposes in the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

Under procedures established by the False Claims Act, the United States of America, acting through the U.S. Department of Justice (DOJ), is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.

The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) incorrectly measured the volume and heat content of natural gas produced from federal or Native American leases. As a result, it is alleged that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties, and expenses associated with the litigation.

~~The relator has filed a claim in the Utility's Chapter 11 case for $2.5 billion, $2 billion of which is based upon the plaintiff's calculation of penalties sought against the Utility.~~

PG&E Corporation and the Utility believe the allegations to be without merit and intend to present a vigorous defense. PG&E Corporation and the Utility believe that the ultimate outcome of the litigation will not have a material adverse effect on their financial condition or results of operations.

~~Order Instituting Investigation into Holding Company Activities~~

On April 3, 2001, the CPUC issued an order instituting investigation into whether the California IOUs, including the Utility, have complied with past CPUC decisions, rules, orders, or applicable statutes authorizing their holding company formations and/or governing affiliate transactions. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including during times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies' action to "ringfence" their unregulated subsidiaries. The CPUC also will determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the ho lding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate.

On January 9, 2002, the CPUC issued an interim decision and order interpreting the "first priority condition" adopted in the CPUC's holding company decision. This condition requires that the capital requirements of the utility, as determined to be necessary and prudent to meet the utility's obligation to serve or to operate the utility in a prudent and efficient manner, be given first priority by the board of directors of the holding company. In the interim order, the CPUC stated, "the first priority condition does not preclude the requirement that the holding company infuse all types of capital into their respective utility subsidiaries where necessary to fulfill the utility's obligation to serve." The three major California IOUs and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years' understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. The utilities' applications for rehearing were denied on July 17, 2002.

In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility's original proposed plan of reorganization would violate the first priority condition. The utilities' applications for rehearing were denied on July 17, 2002.

~~The holding companies' petitions for review of these CPUC decisions are pending before the California Court of Appeals for the First Appellate District in San Francisco, California.~~

The proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding provides that on or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the proposed CPUC settlement agreement is final and nonappealable, the Utility and PG&E Corporation, on the one hand, and the CPUC, on the other, will execute full mutual releases and dismissals with prejudice of certain claims, actions, or regulatory proceedings, as specified in the settlement agreement, arising out of or related in any way to the California energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the energy crisis (but only as to past actions, not prospective matters).

PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation, however, can predict what the outcome of the CPUC's investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition.

~~William Ahern, et al. v. Pacific Gas and Electric Company~~

On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately $0.035 per kWh in allegedly excessive electric rates and a refund of alleged recent over-collections in electric revenue since September 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power (surcharges that increased the average electric rate by $0.04 per kWh) became excessive later in 2001. The only alleged over-collection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. On April 2, 2002, the Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as an impermissible collateral action and on the basis that the alleged facts, even if assumed to be true, do not establish that currently authorized electric rates are not reasonable.

On May 10, 2002, the Utility filed a motion to dismiss the complaint. The CPUC has not yet issued a decision. However, in November 2002, the CPUC issued a decision jointly in this complaint case and in the rate stabilization proceedings modifying the restrictions on use of revenues generated by the surcharges to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. After the CPUC determines when the AB 1890 rate freeze ended, the CPUC will determine the extent and disposition of the Utility's under-collected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected. Under the proposed CPU C settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would acknowledge and agree that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund.

~~Income Tax Refund Litigation~~

~~NEGT, Inc.~~ ~~and its creditors have brought~~ ~~litigation against PG&E Corporation inNEGT, Inc.'s~~ Chapter 11 proceeding pending in the U.S. Bankruptcy Court for the District of Maryland, asserting that NEGT, Inc. is entitled to be compensated for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and deductions of NEGT, Inc. and its subsidiaries in PG&E Corporation's consolidated federal tax return under an alleged implied tax sharing agreement betwee n PG&E Corporation and NEGT, Inc. or otherwise. In May 2003, PG&E Corporation received a return of $533 million from the Internal Revenue Service for an overpayment of 2002 estimated federal income taxes resulting from losses and deductions incurred at PG&E Corporation, the Utility, and NEGT, Inc. and its subsidiaries, of which approximately $361.5 million was obtained by offsetting losses and deductions of NEGT, Inc. and its subsidiaries against income of PG&E Corporation and the Utility in PG&E Corporation's 2002 consolidated federal income tax return.

~~NEGT, Inc. and its creditors have asserted that it has a direct interest and is entitled to be paidapproximately $414~~ ~~million of the funds received by PG&E Corporation~~ ($361.5 million achieved by the incorporation of losses and deductions of NEGT, Inc. or its subsidiaries and $53 million which NEGT, Inc. and its creditors allege was achieved by the incorporation of certain tax credits generated by NEGT, Inc.'s subsidiaries). NEGT, Inc. and its creditors allege, in part,that an implied tax sharing agreement exists between PG&E Corporation and NEGT, Inc. PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT, Inc. for the incorporation of its or its subsidiaries' losses and deductions into PG&E Corporation's consolidated federal tax returns, as required under the Internal Revenue Code. The dispute will be resolved in the pending litigation . Consequently, until the dispute is resolved, PG&E Corporation is treating $361.5 million of the amount received by PG&E Corporation as restricted cash.

In October 2003, PG&E Corporation reached an agreement with NEGT, Inc. and its creditors under which (1) NEGT, Inc. and its creditors agreed to the dissolution of a temporary restraining order (TRO) that NEGT, Inc. previously had obtained, without prior notice to PG&E Corporation, that temporarily prohibited PG&E Corporation from using the $361.5 million in

funds, (2) NEGT, Inc. agreed to withdraw its motion for a preliminary injunction that would continue to prohibit PG&E Corporation from using such funds, and (3) PG&E Corporation agreed to provide NEGT, Inc. 10 business days advance notice before voluntarily allowing the cash balance in its institutional money market accounts to drop below $361.5 million or otherwise pledging such amount. On October 10, 2003, NEGT, Inc. withdrew its motion for a preliminary injunction and the Bankruptcy Court signed an order dissolving the TRO.

~~On November~~7, ~~2003, an amended complaint was filed in the Bankruptcy Court~~by ~~NEGT, Inc.~~ ~~as plaintiff,~~ ~~andits two~~ ~~creditors' committees,as plaintiffs-intervenors,against PG&E Corporation allegingadditionalcauses of actionarising out of or related to the filing by PG&E Corporation of its 2002 federal consolidated tax return, including claims~~for breach of contract, breach of fiduciary duty, violation of the automatic stay, turnover, an accounting, unjust enrichment, fraudulent transfer, constructive trust, equitable subordination, and indemnification. In addition, NEGT, Inc. and the creditors' committees seek a declaration that an implied tax sharing agreement exists between PG&E Corporation and NEGT, Inc. as well as injunctive relief prohibiting PG&E Corporation from taking certain tax positions on its consolidat ed tax returns in the future. The complaint also alleges a cause of action for breach of fiduciary duty against two PG&E Corporation officers who previously served on NEGT, Inc.'s Board of Directors. The plaintiffs seek at least $414 million in damages, plus interest, costs of suit, and reasonable attorney's fees. In addition, plaintiffs seek punitive damages against PG&E Corporation and the former NEGT, Inc. directors for breach of fiduciary duty and seek punitive damages against PG&E Corporation for deceit.

~~The Bankruptcy Court has set a trial schedule in the litigation thatcurrently calls for a trial to begin in July~~2004; however, PG&E Corporation has filed a motion with the U.S. District Court for the District of Maryland (District Court) seeking withdrawal of the reference to the Bankruptcy Court, in part, on the grounds that the Bankruptcy Court cannot render final findings of fact or conclusions of law on the claims asserted in the litigation or conduct a jury trial without PG&E Corporation's consent. If the motion is successful, the litigation will be transferred to the District Court, which will preside over any trial in this litigation and will establish its own trial schedule.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations. As described in Notes 1 and 4 above, effective July 8, 2003, PG&E Corporation no longer consolidates NEGT, Inc.'s financial results and is accounting for its investment in NEGT, Inc. using the cost method with all periods presented as discontinued operations.

~~NOTE 7: SEGMENT INFORMATION~~

~~PG&E Corporation has one reportable operating segment.~~

~~Segment information for the three- and nine-month periods ended September 30, 2003, and 2002, was as follows:~~

(in millions)

Utility
PG&E
Corporation,
Eliminations
and Other⁽¹⁾

Total
Three months ended September 30, 2003
Operating revenues
$
3,103
$
-
$
3,103
Intersegment revenues
-
-
-
Total operating revenues
3,103
-
3,103
Income (Loss) from continuing operations⁽²⁾
583
(75)
508
Net income (loss)⁽³⁾
583
(73)
510
Three months ended September 30, 2002
Operating revenues
2,947
-
2,947
Intersegment revenues
2
(2)
-
Total operating revenues
2,949
(2)
2,947
Income (Loss) from continuing operations⁽²⁾
520
(41)
479
Net income (loss)⁽³⁾
520
(54)
466
Nine months ended September 30, 2003
Operating revenues
7,897
-
7,897
Intersegment revenues
3
(3)
-
Total operating revenues
7,900
(3)
7,897
Income (Loss) from continuing operations⁽²⁾
844
(90)
754
Net income (loss)⁽³⁾
843
(460)
383
Nine months ended September 30, 2002
Operating revenues
8,108
-
8,108
Intersegment revenues
8
(8)
-
Total operating revenues
8,116
(8)
8,108
Income (Loss) from continuing operations⁽²⁾
1,573
(41)
1,532
Net income (loss)⁽³⁾
1,573
(258)
1,315
Total assets at September 30, 2003
$
26,850
$
910
$
27,760
Total assets at September 30, 2002
$
24,942
$
11,693
$
36,635
(1)
Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries. PG&E Corporation's net income (loss) includes the results of NEGT, Inc.'s discontinued operations through July 7, 2003, and the elimination of $160 million for the nine-month period ended September 30, 2003, of deferred tax asset valuation reserves recorded at NEGT, Inc. PG&E Corporation believes it is more likely than not that it will be able to realize these deferred tax assets on a consolidated basis.
(2)
Corresponds to the Utility's Income Available for Common Stock excluding Cumulative Effect of a Change in Accounting Principle.
(3)
Corresponds to the Utility's Income Available for Common Stock.

~~NOTE 8: EMPLOYEE BENEFIT PLANS~~

On May 28, 2003, two of the Utility's unions ratified new contracts, which provide for, among other items, an increase in benefits provided under the Utility's defined benefit pension plan (Retirement Plan). As a result of the ratifications, the Utility remeasured the assets and liabilities of the Retirement Plan at May 28, 2003. In connection with the remeasurement, which reflected a reduction in the current discount rate from the Retirement Plan's previous actuarial valuation, the Utility recorded a minimum pension obligation of $478 million, the amount by which the accumulated benefit obligation exceeded the fair market value of plan assets, and reduced its pension asset from $887 million to $353 million. The Utility has previously recognized a regulatory liability for timing differences between recognition of pension costs in accordance with GAAP and ratemaking purposes. As a result of the remeasurement, the Utility has reduced this regulatory liability by $911 million. The remaining amount of $6 0 million, net of income tax benefit of $41 million, has been recorded as a component of shareholders' equity in OCI in the Consolidated Balance Sheets. The charge to OCI does not affect earnings or cash flow, and could be reversed in future periods if the fair value of plan assets exceeds the accumulated benefit obligation.

On September 23, 2003, the last of the Utility's three unions also ratified new contracts with an increase in benefits provided under the Retirement Plan. The Utility did not remeasure the assets and liabilities of the Retirement Plan at September 23, 2003, as there was no significant change to pension expense as a result of the plan change. The Utility's defined benefit pension plan currently exceeds the minimum funding requirements of the Employee Retirement Income Security Act of 1974.

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 ~~headquartered in San Francisco, California;~~that conducts its ~~principal subsidiary,~~business principally through Pacific Gas and Electric Company, ~~(Utility), is an operating~~or the Utility, a public utility ~~engaged~~operating in northern and central California. The Utility engages primarily in the ~~business~~businesses of ~~providing~~ electricity and natural gas distribution, electricity generation, electricity transmission, and ~~transmission services throughout most~~natural gas transportation and storage. PG&E Corporation became the holding company of ~~Northern~~the Utility and ~~Central California.~~its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. PG&E Corporation also owns 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 U.S.

The Utility

The Utility served approximately 4.8 million electricity distribution customers and approximately 4.0 million natural gas distribution customers at March 31, 2004. The Utility had approximately $41.0 billion in assets at March 31, 2004 and generated revenues of approximately $2.7 billion in the three months ended March 31, 2004. The Utility's revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

The discussion of the Utility's Chapter 11 proceedings below should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements of PG&E Corporation's and the Utility's combined 2003 Annual Report filed with the Current Report on Form 8-K dated March 2, 2004.

Emergence From Chapter 11

On April ~~6, 2001,~~12, 2004, the ~~Utility filed a voluntary petition for relief~~Utility's plan of reorganization, or Plan of Reorganization, under Chapter 11 of the ~~federal~~U.S. Bankruptcy Code ~~(Bankruptcy Code)~~became effective. The Plan of Reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. Although the Utility's operations will no longer be subject to the oversight of the bankruptcy court, the bankruptcy court will retain jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the Plan of Reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the Plan of Reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

In anticipation of its emergence from Chapter 11, the Utility consummated its public offering of $6.7 billion in first mortgage bonds, or First Mortgage Bonds, on March 23, 2004. Upon the effectiveness of the Plan of Reorganization, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds for these transactions:

(in millions)
Sources			Uses


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

Account 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

Appeals of the bankruptcy court's order confirming the Plan of Reorganization are still pending in the U.S. ~~Bankruptcy~~District Court for the Northern District of California, ~~(referred~~or the District Court. These appeals were filed by the two CPUC commissioners who did not vote to asapprove the ~~Bankruptcy~~Settlement Agreement, or the dissenting commissioners, and a municipality. The District Court ~~in this report's discussion~~will set a schedule for briefing and argument of the ~~Utility's Chapter 11 filing). Pursuant to Chapter 11~~appeals at a later date. 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 the California Court of Appeal seeking review of the ~~Bankruptcy Code,~~CPUC's December 18, 2003 decision approving the ~~Utility retains control~~Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its ~~assets~~December 18, 2003 decision. CCSF and ~~is authorized~~Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF r equests the appellate court to ~~operate its business as a debtor-in-possession while being subject to~~hear and review the ~~jurisdiction of~~CPUC's decisions approving the ~~Bankruptcy Court. The factors~~Settlement Agreement and Aglet requests that ~~caused~~ the Utility to take this action are discussed in this Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and in Note 2 of the Notes to the Condensed Consolidated Financial Statements.

PG&E National Energy Group, Inc. (PG&E NEG), another subsidiary of PG&E Corporation, is a company with subsidiaries currently engaged in electricity generation and natural gas transmission in the United States of America. On July 8, 2003, PG&E NEG and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division (referred to as the Bankruptcy Court in this report's discussion of PG&E NEG's Chapter 11 filing). Pursuant to Chapter 11 of the Bankruptcy Code, PG&E NEG and those subsidiaries retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors that caused PG&E NEG to take this action are discussed in this MD&A and in Note 4 of the Notes to the Consolidated Financial Statements. On October 3, 2003, the Bankruptcy C ourt authorized PG&E NEG to change its name to National Energy and Gas Transmission, Inc. (NEGT, Inc.). The change reflects NEGT, Inc.'s pending separation from PG&E Corporation. Consequently, for the remaining MD&A, any references to PG&E NEG, including its Chapter 11 filing and its plan of reorganization, willCPUC's decisions be ~~referred to as NEGT, Inc.~~

The Consolidated Financial Statements of PG&E Corporation and of the Utility have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and repayment of liabilities in the ordinary course of business. However, as a result of the Utility's Chapter 11 filing as further discussed below, such realization of assets and liquidation of liabilities are subject to uncertainty.

~~This MD&A explains the general financial condition and the results of operations of PG&E Corporation and its subsidiaries, including:~~

~~Factors that affect each business;~~

~~A comparison of revenues and expenses and why they changed between periods;~~

~~The sources and uses of cash between periods; and~~

~~Other matters including commitments and contingencies that affect overall financial condition.~~

~~This is a combined Quarterly Report on Form 10-Q of~~overturned. PG&E Corporation and the Utility believe the petitions are without merit and ~~includes separate Consolidated Financial Statements~~should be denied. The Utility's answer in opposition to the petitions for ~~each~~review is due May 19, 2004.

Under applicable federal precedent, once the Plan of ~~these two entities. The Consolidated Financial Statements~~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 Corporation ~~reflect~~and the ~~accounts~~Utility's financial condition and results of operations could be materially adversely affected and PG&E Corporation the Utility, and other wholly owned and controlled subsidiaries. The Consolidated Financial Statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this Quarterly Report should be read in conjunction with PG&E Corporation's and the Utility's ~~Consolidated Financial Statements~~ability to make payments on debt could be materially adversely affected.

The Utility believes that the uncertainty regarding the outcome of the pending appeals and ~~Notes to~~petitions does not alter the ~~Consolidated Financial Statements included~~assessment that the regulatory assets provided under the Settlement Agreement are probable of recovery in ~~their combined 2002 Annual Report on Form 10-K,~~rates as ~~amended.~~discussed below.

Forward-Looking Statements and Risk Factors

This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," "could," "should," "would," "may," 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 factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

~~Outcome~~Whether the Implementation of the Utility's ~~Chapter 11 Case. PG&E Corporation's and the Utility's future results~~Plan of ~~operations and financial conditions may be affected by the pace and outcome of the Utility's Chapter 11 case, which depends upon:~~Reorganization Is Disrupted

·	The timing and resolution of the petitions for review that were filed in 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 denial of applications for rehearing of the December 18, 2003 decision; and
·	The timing and resolution of the pending appeals of the bankruptcy court's order confirming the Plan of Reorganization.

Whether the proposed settlement agreement with the staff of the California Public Utilities Commission (CPUC) that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization submitted in the Utility's Chapter 11 proceeding, and the rates, tariffs, and agreements that it contemplates, are approved by the CPUC after public hearings, the timing of such approval, and whether any such approvals are appealed and, if appealed, the timing and resolution of these appeals;

~~The outcome and the timing of the Bankruptcy Court's proceeding to confirm the Settlement Plan, whether the confirmation order is appealed and, if appealed, the timing and resolution of these appeals;~~

The impact of future ratemaking actions of the CPUC, including those actions that address the amount of the California Department of Water Resources' (DWR) revenue requirements that are allocated to the Utility for collection from the Utility's customers;

~~Whether the required credit ratings to implement the Settlement Plan are obtained;~~

Future equity or debt market conditions, future interest rates, future credit ratings, and other factors that may affect the ability to implement the Settlement Plan or affect the terms, amount, and value of the debt proposed to be issued under the Settlement Plan;

~~Whether a plan of reorganization containing substantially different terms than those contained in the Settlement Plan is confirmed; and~~

~~Whether a plan of reorganization is not confirmed for an extended period of time.~~

Operating ~~Environment.The amount of operating income and cash flows the Utility may record may be influenced by the following:~~Environment

~~Unanticipated changes in operating expenses and capital expenditures;~~

~~The level and volatility of wholesale electricity and natural gas prices and the Utility's ability to manage and respond to this volatility successfully;~~

Weather, storms, earthquakes, fires, other natural disasters, explosions, accidents, mechanical breakdowns, and other events or perils 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;

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;

The Utility's ability to manage the net open position over time, which can be affected by whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR;

The operation and decommissioning of the Utility's Diablo Canyon nuclear power plant, which expose the Utility to potentially significant environmental and capital expenditure risks, 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;

Significant changes in the Utility's relationship with its employees, including the retirement of existing employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur;

~~Acts of terrorism; and~~

~~Actions of credit rating agencies.~~

·	Unanticipated changes in operating expenses or capital expenditures;
·	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;
·	The extent to which the Utility's residual net open position (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the California Department of Water Resources, or DWR, electricity contracts allocated to the Utility's customers) increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of the Utility's or the DWR's power purchase contracts, the reallocation of the DWR power purchase contracts among the California investor-owned electric utilities, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR, the retirement or other closure of the Utility's electricity generation facilities, the performance of the Utility's electricity generation facilities, the extent to which the Utility purchases or builds electricity generation faci lities, and other factors;
·	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;
·	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, which exposes the Utility to potentially significant environmental 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 its Diablo Canyon power plant and purchase electricity from more expensive sources;
·	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.PG&E Corporation's~~Environment and ~~the Utility's business may be impacted by:~~Pending Litigation

~~The possibility that the proposed settlement agreement is not approved by the CPUC or is modified or invalidated on appeal,~~

·	The impact of current and future ratemaking actions of the CPUC, including the outcome of the Utility's 2003 general rate case, or GRC;
·	Whether the conditions to securitizing the $2.21 billion after-tax regulatory asset established under the Settlement Agreement are met, and if iso, the timing and amount of the securitization, and the impact such a securitization would have on the Utility's and PG&E Corporation's earnings;
·	Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, with regard to 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;
·	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 California investor-owned electric utilities;
·	Whether the Utility is 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

Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or service by local public utilities, self-generation by the Utility's customers 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 and the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers or combine to form community choice aggregators.

Financial Summary of the Settlement ~~Plan is not confirmed or implemented, the timing and impact~~Agreement

In light of the ~~end~~satisfaction of ~~the retail electricity rate freeze, the structure of post-rate freeze ratemaking, and whether the Utility is required~~various conditions to ~~refund previously collected revenues to ratepayers;~~

Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, and the Federal Energy Regulatory Commission (FERC), with regard to 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;

~~How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the holding company;~~

Future regulatory proceedings related to whether the Utility has complied with all applicable rules, tariffs, and orders, and the extent to which a finding of non-compliance could result in customer refunds, penalties, or other non-recoverable expenses; and

~~The effect of compliance with existing and future environmental laws, regulations, and policies, including those addressing global climate change.~~

Pending Litigation and Regulatory Proceedings.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by the outcome of pending litigation and regulatory proceedings, including proceedings related to the allocation of the DWR's revenue requirements among the three California investor-owned utilities (IOUs) for future or prior periods, the timing and impact of the end of the retail electric rate freeze, the structure of post-rate freeze ratemaking, whether the Utility is required to refund previously collected revenues to ratepayers, and whether the proposed settlements in the Utility's 2003 General Rate Case (GRC) proceeding are approved by the CPUC.

~~Competition.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by:~~

Increased competition as a result of the takeover by condemnation or municipalization of the Utility's distribution assets, self-generation by its customers 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;

The extent to which the cities and counties in the Utility's service territory become community choice aggregators and the extent to which the Utility's distribution customers can switch between purchasing electricity from the Utility or from alternate energy service providers as direct access customers; and

~~Changes in the level of the direct access customer cost responsibility surcharge, as well as other surcharges related to direct access, and changes to the current suspension of direct access.~~

Accounting and Risk Management.PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by new accounting pronouncements, including significant changes in accounting policies material to PG&E Corporation or the Utility.

~~As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from historical results or outcomes currently sought or expected.~~

~~LIQUIDITY AND FINANCIAL RESOURCES~~

~~Utility~~

On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code due in part to its inability, during the California energy crisis, to recover its procurement costs from customers in its rates. PG&E Corporation and the Utility have incurred, and will continue to incur throughout the reorganization process, legal, accounting, trustee, and other costs associated with the implementation of the ~~proposed CPUC settlement agreement.~~

~~While~~Plan of Reorganization, including the Utility is in Chapter 11 proceedings, the Utility is not allowed to pay liabilities incurred before it filed for its Chapter 11 petition without permission from the Bankruptcy Court. Additionally, the Utility:

~~Does not have access to external funding from capital markets;~~

Is in default under its credit facilities, commercial paper, floating rate notes, senior notes, pollution control loan agreements, mortgage bonds, and medium-term notes as a result of its failure to pay certain of its obligations. However, the event of default under each debt obligation has been stayed in accordance with the Utility's Chapter 11 proceedings; and

~~Has been making capital investments (investments in property, plant and equipment) out of its cash on hand under the supervision~~consummation of the ~~Bankruptcy Court. The Utility anticipates that it will be able to continue making such necessary capital investments in~~public offering of First Mortgage Bonds, the ~~future, subject to Bankruptcy Court approval.~~

Since filing for Chapter 11, the Utility has received permission from the Bankruptcy Court to make payments on (1) pre- and post-petition interest on certain claims, (2) pre-petition amounts payable to qualifying facilities (QFs) and certain other vendors, and (3) matured pre-petition secured debt.

Also, the Utility has been, and will continue, accruing interest on its pre-petition liabilities at the required rates included in the Utility's proposed settlement agreement. However, due to the uncertaintyreceipt of ~~the ultimate outcome of the Utility's Chapter 11 proceedings, the Utility is not able to estimate the amount of interest that will be paid in 2003 and beyond.~~

~~Competing Plans of Reorganization~~

In September 2001, PG&E Corporation and the Utility submitted a proposed plan of reorganization to the Bankruptcy Court (the original plan of reorganization) that proposed to disaggregate the Utility's current business and to refinance the restructured businesses. In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors (OCC), submitted an alternate proposed plan of reorganization with the Bankruptcy Court that did not provide for disaggregation of the Utility's business. In March 2003, the Bankruptcy Court stayed all proceedings relating to the confirmation trial for the competing plans to allow the Utility, the CPUC, and certain other parties to participate in a judicially supervised settlement conference in order to explore the possibility of resolving the differences between the competing plans of reorganization and developing a consensual plan.

~~The Proposed CPUC Settlement Agreement~~

On June 19, 2003, PG&E Corporation, the Utility, and the staff of the CPUC announced a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization. Under the proposed CPUC settlement agreement, PG&E Corporation and the Utility would agree that the Utility remains a vertically integrated utility subject to the CPUC's jurisdiction. The proposed CPUC settlement agreement would permit the Utility to emerge from Chapter 11 as an investment grade ~~rated company (at least BBB- from Standard & Poor's (S&P)~~credit ratings and ~~Baa3 from Moody's Investors Service (Moody's)), and to pay in full all the Utility's valid creditor claims, plus applicable interest.~~

~~The proposed~~final CPUC settlement agreement contains a statement of intent that it is in the public interest to restore the Utility to financial health and to maintain and improve the Utility's financial condition in the future to ensure that the Utility is able to provide safe and reliable electricity and natural gas service to its customers at just and reasonable rates. In addition, the proposed CPUC settlement agreement includes a statement of intent that it is fair and in the public interest to allow the Utility to recover prior uncollected costs over a reasonable time and to provide the opportunity for shareholders to earn a reasonable rate of return on the Utility's business. Under the proposed CPUC settlement agreement, the Utility would release claims against the CPUC that the Utility or PG&E Corporation would have retained under the original plan of reorganization.

The Utility currently expects to have approximately $9.4 billion in total debt outstanding (excluding the rate reduction bonds) on the effective date of the Settlement Plan. The actual amount of debt that the Utility would issue will depend upon how certain claims are resolved and the amount of cash on hand at the time the Settlement Plan becomes effective, as well as cash requirements related to closing out any interest rate hedges and whether all intended reinstated debt will be reinstated.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed CPUC settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that was used to solicit approval of the Settlement ~~Plan from creditors entitled~~Agreement, the accounting probability standard required to ~~vote on~~be met under Statement of Financial Accounting Standards, or SFAS, No. 71 in order for the Utility to recognize the regulatory assets provided under the Settlement ~~Plan. Solicitation~~Agreement (as described below) was met as of ~~creditor votes ended on September 29, 2003. On October 14, 2003,~~March 31, 2004. Therefore, the Utility filed the voting results with the Bankruptcy Court. All of the creditor classes that voted on the Settlement Plan voted in favor of the Settlement Plan. The confirmation hearing began on November 10, 2003.

~~The principal terms of the proposed CPUC settlement agreement are as follows:~~

~~Regulatory Asset~~

~~The CPUC would agree to establish~~recorded a $2.2 billion, after-tax, regulatory asset ~~(Regulatory Asset), which equates~~established under the Settlement Agreement, or Settlement Regulatory Asset, and a $700 million, after-tax, regulatory asset for the Utility retained generation 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
Less: amortization from January 1 to March 31	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
Less: offsets of supplier settlements, after tax	8			-		8

Net, March 31, 2004	$	2,168		$	728	$	2,896

SettlementRegulatory 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,~~asset), as a new, separate and additional part of the Utility's rate base that ~~would be~~is being amortized on a ''mortgage-style'' basis over nine years beginning January 1, 2004. ~~The~~Under this amortization methodology, annual after-tax collections of the Settlement Regulatory Asset ~~would~~are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012. The Settlement Regulatory Asset will be fully amortized by the end of 2012. ~~The CPUC also would agree to authorize the Utility to establish a tax tracking account, to be used if the Utility must pay income tax on the~~This after-tax Settlement Regulatory Asset ~~before it is fully amortized, to record the difference between taxes on the Regulatory Asset plus interest imposed by federal or state tax authorities~~will be reduced for earlier recognition, and taxes that would have been incurred on account of the Regulatory Asset had it been taxed during the amortization period. The tax tracking account will earn the authorized rate of return and be amortized into rates over the longer of the remaining life of the Regulatory Asset or f ive years.

~~The net after-tax amount of~~ any refunds, claim offsets or other credits the Utility receives from ~~generators or other~~ energy suppliers relating to ~~the Utility's PX, ISO, QF, or energy service provider~~specified electricity procurement costs incurred during the California energy crisis, ~~that~~including those arising f rom the settlement of CPUC litigation against El Paso Natural Gas Company. As of March 31, 2004, the Utility ~~realizes in cash or by offset~~recognized a one-time non-cash gain of ~~creditor claims in its Chapter 11 case will reduce~~$3.7 billion, pre-tax, for the ~~outstanding~~Settlement Regulatory Asset.
The unamortized balance of the Settlement Regulatory Asset dollar for dollar. Similarly, the net after-tax amounts received in cash by the Utility for electricity claims under the master settlement agreement with El Paso Corporation and certain of its affiliates (El Paso) also would cause a reduction in the outstanding balance and the remaining amortization of the Regulatory Asset.

~~The Regulatory Asset would~~will earn a rate of return on its equity ~~(ROE)~~component of ~~at least 11.22 percent~~no less than 11.22% annually for its nine-year term and, after the equity component of the Utility's capital structure reaches ~~52.00 percent,~~52%, the authorized equity component of the Settlement Regulatory Asset ~~would~~will be no less than ~~52.00 percent~~52% for the remaining ~~term~~term. If the Utility completes a refinancing of the Settlement Regulatory ~~Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.~~

~~Ratemaking Matters~~

~~The CPUC would agree that~~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 ~~for its utility retained generation (URG) would~~in a 2002 proceeding to be ~~deemed~~ just and reasonable and ~~would~~ not be subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and ~~any change~~changes in authorized depreciation. ~~This would result in~~Accordingly, as of March 31, 2004, the ~~recording of an additional after-tax regulatory asset~~Utility recognized a one-time non-cash gain of approximately ~~$0.8~~$1.2 billion, ~~(or approximately $1.3 billion pre-tax).~~ pre-tax, for the retained generation regulatory assets.The ~~Utility would record this regulatory asset when events that meet applicable accounting rules occur.~~

The CPUC would timely act upon the Utility's applications to collect in rates prudently incurred costs (including return of and return on) of any new and reasonable investment in utility plant and assets. The CPUC also would promptly adjust the Utility's rates consistent with the California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC's 2002 agreement with the DWR regarding the establishmentindividual components of the ~~DWR's revenue requirements to ensure that~~regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years.
Ratemaking Matters - In the Utility's collection of certain charges to service existing rate reduction bonds, regulatory asset amortization and return, and base revenue requirements (e.g., electricity and natural gas distribution, the Utility's rate base for its electricity generation, gas commodity procurement, existing QF contract costs, and associated return) are not impaired. The CPUC would not discriminate against the Utility because of the Utility's Chapter 11 case, the Utility's pending federal lawsuit againstSettlement Agreement, the CPUC ~~Commissioners~~agreed to recover its previo usly incurred costs of providing electric service from ratepayers under the federal filed rate doctrine, the proposed CPUC settlement agreement, the Regulatory Asset, or any other matters addressed in or resolved by the proposed CPUC settlement agreement.

The CPUC would maintain the Utility's retail electric rates at current levels through December 31, 2003. As of January 1, 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed CPUC settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed CPUC settlement agreement includes a statement of intent that under the Settlement Plan, retail electricity rates would be reduced in January 2004, with further reductions expected thereafter.

~~The CPUC would set~~ the Utility's capital structure and authorized ~~ROE~~return on equity in ~~the Utility's~~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 ~~at least~~not less than A- ~~or Moody's has issued an issuer credit rating for~~, the ~~Utility of at least A3, the~~Utility's authorized ~~ROE would~~return on equity will be no less than ~~11.22 percent~~11.22% per year and ~~the~~its authorized equity ratio for ratemaking purposes ~~would~~will be no less than ~~52.00 percent, except that~~52%. However, for 2004 and 2005, the Utility's authorized equity ratio ~~would equal~~will be the greater of the proportion of equity approved in the ~~forecast of its average capital structure for calendar years~~Utility's 2004 and 2005 ~~filed in the Utility's~~ cost of capital ~~proceeding and 48.60 percent.~~

proceedings, or 48.6%.
The CPUC also ~~would agree~~agreed to act promptly on certain of the Utility's pending ratemaking proceedings, including the Utility's pending 2003 GRC. The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility's Consolidated Balance Sheets.

~~California Department of Water Resources Contracts~~

~~The Utility would agree to accept an assignment of, or to assume legal and financial responsibility for,~~Environmental Measures -In the ~~DWR contracts that have been allocated to~~Settlement Agreement, the Utility ~~but only if:~~

~~After assignment or assumption of the DWR contracts, the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's;~~

~~The CPUC first has made a finding that the DWR contracts being assumed are just and reasonable; and~~

~~The CPUC has acted~~agreed to ~~ensure that the Utility receives full and timely recovery in its retail electricity rates of all costs of the DWR contracts without further review.~~

Under the proposed CPUC settlement agreement, the CPUC retains and, after any assignment or assumption of the DWR contracts, would retain the right to review the prudence of the Utility's administration and dispatch of the DWR contracts consistent with applicable law.

~~Headroom~~

The CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported under accounting principles generally accepted in the United States of Amer ica (GAAP), less earnings from operations, (as has been historically defined by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

~~Dismissal of Filed Rate Case, Other Litigation, and Regulatory Proceedings~~

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice its case against the CPUC Commissioners asserting the "filed rate doctrine," withdraw the original plan of reorganization, and dismiss other pending proceedings. In exchange, on or before January 1, 2004, the CPUC would establish and authorize the collection of the Regulatory Asset and the Utility's rate base for its electricity generation, and on or as soon as practicable after the effective date, resolve phase 2 of the pending Annual Transition Cost Proceeding in which the CPUC is reviewing the reasonableness of the Utility's procurement costs incurred during the energy crisis with no adverse impact on the Utility's cost recovery as filed.

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, PG&E Corporation, the Utility, and the CPUC would execute mutual releases and dismissals with prejudice of specified claims, actions, or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).

~~Environmental Measures~~

~~The Utility would agree to implement three environmental enhancement measures:~~

~~The Utility would~~ encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation ~~organizations;~~

organizations.
The Utility ~~would establish~~has established PG&E Environmental Enhancement Corporation as a California non-profit corporation to oversee the environmental enhancements associated with these ~~lands and~~lands. The Utility has agreed to fund itthe corporation with ~~$70~~$100 million in cash over 10ten years, although the Utility ~~would~~will be entitled to recover these payments in ~~rates;~~rates. At March 31, 2004, the Utility recorded an $83 million regulatory asset and

associated liability based on the discounted present value of future cash payments. On April 12, 2004, the Utility made its first $10 million installment payment to this corporation.
The Utility ~~would create~~has also agreed to establish a California non-profit corporation ~~funded with $15 million payable by the Utility over five years~~ dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory.

The Utility has agreed to fund this corporation with $30 million payable over five years beginning in January 2005. These contributions may not be recovered in rates. At March 31, 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 ~~in the first bullet,~~above, approximately ~~45,000~~44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the ~~Utility~~Utility's or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements.

~~Waiver of Sovereign Immunity~~

~~The CPUC would agree~~ At March 31, 2004, the Utility recorded a $1 million pre-tax charge to ~~waive all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection~~earnings associated with ~~any action or proceeding concerning~~ the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Bankruptcy Court's order confirming the Settlement Plan (Confirmation Order). The CPUC also would consent to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the Bankruptcy Court. The CPUC's waiver would be irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off, or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order. The proposed CPUC settlement agreement contemplates tha t neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order.

~~Term and Enforceability~~

Fees and Expenses

The ~~proposed CPUC settlement agreement would require~~Settlement Agreement requires the Utility to reimburse ~~PG&E Corporation and~~ the CPUC for ~~their respective~~its professional fees and expenses incurred in connection with the Chapter 11 ~~proceeding once the Settlement Plan is confirmed. Of such~~proceeding. These amounts ~~the amounts reimbursed to the CPUC (but not to PG&E Corporation) would~~will be recovered from ~~ratepayers~~customers over a reasonable time of up to four years. AsAt March 31, 2004, the Utility recorded a regulatory asset and associated liability of ~~September 30, 2003,~~approximately $30 million for the CPUC reimbursable fees and expenses. On March 31, 2004, PG&E Corporation ~~has incurred expenses of approximately $128 million on~~recorded the ~~Utility's Chapter 11 proceeding.~~

~~Conditions of the Effectiveness~~impact of the Settlement ~~Plan~~

~~The Settlement Plan provides that it would not be confirmed by~~Agreement. One of the ~~Bankruptcy Court unless and until the following conditions are satisfied or waived:~~

~~The Bankruptcy Court enters an order or orders:~~

~~Approving~~terms of the Settlement ~~Plan, authorizing~~Agreement precluded the Utility ~~to execute, enter into,~~from reimbursing PG&E Corporation for certain Chapter 11-related costs. As such, PG&E Corporation reduced its receivable from the Utility, and ~~deliver~~ the ~~Settlement Plan, and to execute, implement, and take all actions necessary or appropriate to give effect to the transactions contemplated by the Settlement Plan;~~

~~Approving and authorizing the execution of, and finding reasonable the terms and conditions of, the proposed CPUC settlement agreement; and~~

~~The Confirmation Order is, in form and substance, reasonably satisfactory~~Utility reduced its payable to PG&E Corporation, by $128 million. The transactions were recorded as a contribution to the Utility by PG&E Corporation, net of taxes, and an increase to additional paid-in capital by the ~~OCC, and the CPUC and specifically includes certain matters.~~

Utility.

~~The Settlement Plan also provides that it would not become effective unless and until the following conditions are satisfied or waived:~~Refinancing Supported by a Dedicated Rate Component

~~The effective date occurs on or before March 31, 2004;~~

~~All actions, documents, and agreements necessary to implement~~
Under the Settlement ~~Plan are effected or executed;~~

Agreement, PG&E Corporation and the Utility ~~have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions, or documents that they deem necessary~~agreed to ~~implement~~seek to refinance the remaining unamortized pre-tax balance of the Settlement ~~Plan;~~

~~The Settlement Plan has not been modified in~~Regulatory Asset and related federal, state and franchise taxes, up to a ~~material way since~~total of $3.0 billion, as expeditiously as practicable after the effective date of ~~confirmation;~~

the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided the following conditions are met:

·	Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the Settlement Regulatory Asset and associated federal and state income and franchise taxes and providing for the collection in the Utility's rates of any portion of the associated tax amounts not securitized;
·	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 IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

The Utility ~~has consummated~~would be permitted to complete the ~~sale~~refinancing in up to two tranches up to one year apart. Upon refinancing with securitization, the equity and debt components of the ~~debt securities contemplated~~Utility's rate of return on the Settlement Regulatory Asset would be eliminated. Instead the Utility would collect from customers amounts sufficient to service the securitized debt. 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.

~~S&P has issued a long-term issuer credit rating for~~Governor as soon as the ~~Utility~~end of ~~not less than BBB- and Moody's has issued an issuer rating for the Utility of not less than Baa3;~~

~~S&P and Moody's have issued credit ratings for the debt securities to be offered by the Utility of not less than BBB- and Baa3, respectively;~~

~~The CPUC has given final nonappealable approval of the proposed CPUC settlement agreement on behalf of the CPUC;~~

~~Each of the parties to the proposed CPUC settlement agreement has executed and delivered the settlement agreement;~~

~~The CPUC has given final nonappealable approval for all of the financings, securities, and accounts receivable programs provided for in the Settlement Plan; and~~

~~The CPUC has given final nonappealable approval for all rates, tariffs, and agreements necessary to implement the Settlement Plan.~~

~~The last six conditions cannot be waived, except that PG&E Corporation and the Utility can waive the right to the finality provisions regarding CPUC approvals.~~

PG&E Corporation and the Utility are unable to predict whether and when the proposed CPUC settlement agreement will become effective or whether the Settlement Plan will be confirmed or implemented. If the Settlement Plan is not confirmed, or if the CPUC does not approve the proposed CPUC settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed CPUC settlement agreement in pending regulatory proceedings associated with the recovery of transition costs and surcharge revenues, or the allocation of DWR electricity to customers of IOUs, as detailed in Note 6 of the Notes to the Consolidated Financial Statements, then the Utility's financial condition and results of operations could be materially adversely affected.May 2004.

NEGT ~~Inc.~~

NEGT's Chapter 11 Filing

On July 8, 2003 NEGT ~~Inc.~~ filed a voluntary petition for relief under ~~the provisions of~~ Chapter 1111. The combination of the ~~Bankruptcy Code. In addition, on July 8, 2003,~~decline in wholesale electricity prices, the financial commitments related to NEGT's construction program, the decline of NEGT's credit rating to below investment grade and the lack of market liquidity created severe financial distress and ultimately caused NEGT Energy Trading Holdings Corporation (NEGT ET), formerly known as PG&E Energy Trading Holdings Corporation, PG&E Energy Trading - Power, L.P., and PG&E Energy Trading - Gas Corporation (collectively, the ET Companies) voluntarily filed petitions forto seek protection under Chapter 1111. In anticipation of ~~the Bankruptcy Code. USGen New England, Inc. (USGenNE) also filed its own petition for~~NEGT's Chapter 11 ~~relief. On July 29, 2003, two other subsidiaries, Quantum Ventures and Energy Services Ventures, Inc., formerly known~~filing, PG&E Corporation's representatives, who previously served as ~~PG&E Energy Services Ventures, Inc., each filed voluntary Chapter 11 petitions. The Chapter 11 case of USGenNE is being administered separately from those~~directors of NEGT, ~~Inc. and the other subsidiaries.~~

Pursuant to Chapter 11 of the Bankruptcy Code, NEGT, Inc. and these subsidiaries retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the Bankruptcy Court. Additionally,resigned on July 8,7, 2003 ~~NEGT, Inc. filed~~and were replaced with directors who are not affiliated with PG&E Corporation. As a plan of reorganization after reaching an agreement in principle as to the plan's key terms with an informal group of creditors that included major creditors, several bondholders, and agents under certain unsecured credit facilities acting in their individual capacities. NEGT, Inc.'s proposed plan of reorganization would not restructure the indebtedness of any of the debtors, other than NEGT, Inc. If NEGT, Inc.'s plan of reorganization is confirmed by the Bankruptcy Court and implemented,result, PG&E Corporation no longer ~~would have any~~retains significant influence over NEGT. On May 3, 2004, NEGT's plan of reorganization, which eliminates PG&E Corporation's equity ~~interest in NEGT, Inc. or any of its subsidiaries. It is anticipated that~~ownership, was confirmed by the ~~Chapter 11 plans for USGenNE and the ET Companies will be filed at a later date.~~bankruptcy court.

As a result of ~~NEGT, Inc.'s~~NEGT's Chapter 11 filing ~~on July 8, 2003~~ and the ~~proposed loss~~elimination of equity ownership provided for in ~~NEGT, Inc.'s~~NEGT's proposed plan of reorganization, PG&E Corporation considers its investment in NEGT ~~Inc.~~ to be an abandoned asset and has accounted for NEGT ~~Inc.~~ as a discontinued ~~operation~~operations in accordance with ~~Statement of Financial Accounting Standards (SFAS)~~SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived ~~Assets" (SFAS~~Assets," or SFAS No. ~~144).~~144. Under the provisions of SFAS No. 144, the operating results of NEGT ~~Inc.~~ and its subsidiaries through July 7, 2003 and for all prior periods are reported as discontinued operations in the Consolidated Statements of Income for all periods reported. In addition, all prior period assets and liabilities of NEGT, Inc., shown for comparative purposes, are classified as discontinued operations in the Consolidated Statements of Income for all periods reported. As ofOperations. At July 8, 2003, PG&E Corporation accounts for NEGT ~~Inc.~~ using the cost ~~method. As~~method and NEGT ~~Inc.~~ is no longer consolidated by PG&E ~~Corpor ation, the~~Corporation for financial reporting purposes. The accompanying ~~September 30, 2003,~~March 31, 2004 Consolidated Balance ~~Sheet~~Sheets of PG&E Corporation does not reflect the separate assets and liabilities of ~~NEGT, Inc.;~~NEGT; rather, a liability of approximately $1.2 billion is reflected, which represents the losses recognized by PG&E Corporation in excess of its investment in and advances to ~~NEGT, Inc.~~NEGT. PG&E Corporation's investment in NEGT ~~Inc.~~ will not be affected by changes in ~~NEGT, Inc.'s~~NEGT's future financial results, other than (1) investments in or dividends from NEGT, Inc., or (2) income taxes that PG&E Corporation may be required to pay if the Internal Revenue Service disallows certain deductions or tax credits attributable to NEGT, Inc. and its subsidiaries for past tax years that are incorporated into PG&E Corporation's consolidated tax returns.results.

~~Upon implementation of NEGT, Inc.'s~~ When NEGT's plan of reorganization ~~that eliminates PG&E Corporation's equity in NEGT, Inc.,~~is implemented, PG&E Corporation will reverse its investment in NEGT ~~Inc.~~ and ~~the~~related amounts included in deferred income taxes and accumulated other comprehensive income ~~(OCI) and deferred taxes,~~ and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations. Upon the effective date of the plan of reorganization, which is anticipated to occur during the second quarter of 2004, PG&E Corporation will record this reversal of its investment in NEGT and recognize a one-time gain. The effective date is contingent upon certain conditions being met within 90 days following the plan confirmation.

NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT's Board of Directors asserting, among other claims, that NEGT is entitled to be compensated under an alleged implied tax-sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of losses and deductions related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal income tax return. In May 2003, PG&E Corporation received $533 million from the IRS for an overpayment of 2002 estimated federal income taxes. NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporationand are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (approximately $361.5 million ach ieved 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). Consequently, until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash. PG&E Corporation anticipates continuing to incorporate losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal tax return, until it is no longer consolidated for federal income tax purposes. NEGT and its creditors similarly assert that NEGT is entitled to be compensated for any tax savings resulting from inclusion of these losses in PG&E Corporation's federal tax return. PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses and deductions related to NEGT or its subsidiaries into PG&E Corporation's consolidated federal tax returns.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations, financial position or liquidity.

RESULTS OF OPERATIONS

~~In this section, PG&E Corporation discusses earnings and the factors affecting them.~~ The table below details certain items from the accompanying Consolidated Statements of ~~Income~~Operations for the ~~three-~~three-month period ended March 31, 2004 and ~~nine-month periods ended September 30, 2003, and 2002.~~2003.

(in millions)

Utility
PG&E
Corporation,
Eliminations
and
Other⁽¹⁾

Total
Three months ended September 30, 2003
Operating revenues
$
3,103
$
-
$
3,103
Operating expenses
1,908
22
1,930
Operating income (loss)
$
1,195
$
(22)
1,173
Interest income
15
Interest expense
(342)
Other income (expenses), net
(5)
Income before income taxes
841
Income taxes
333
Income from continuing operations
508
Net income
$
510
Three months ended September 30, 2002⁽²⁾
Operating revenues
$
2,949
$
(2)
$
2,947
Operating expenses
1,890
(12)
1,878
Operating income
$
1,059
$
10
1,069
Interest income
20
Interest expense
(371)
Other income, net
60
Income before income taxes
778
Income taxes
299
Income from continuing operations
479
Net income
$
466
Nine months ended September 30, 2003⁽²⁾
Operating revenues
$
7,900
$
(3)
$
7,897
Operating expenses
5,901
(30)
5,871
Operating income
$
1,999
$
27
2,026
Interest income
49
Interest expense
(857)
Other income (expenses), net
(10)
Income before income taxes
1,208
Income taxes
454
Income from continuing operations
754
Net income
$
383
Nine months ended September 30, 2002⁽²⁾
Operating revenues
$
8,116
$
(8)
$
8,108
Operating expenses
4,750
(54)
4,696
Operating income
$
3,366
$
46
3,412
Interest income
60
Interest expense
(971)
Other income, net
59
Income before income taxes
2,560
Income taxes
1,028
Income from continuing operations
1,532
Net income
$
1,315
(1)
PG&E Corporation eliminates all inter-segment transactions in consolidation.
(2)
Prior period amounts of NEGT, Inc. have been reclassified to discontinued operations.

~~PG&E Corporation - Consolidated~~

		Three Months Ended March 31,

(in millions)		2004		2003


Utility
Electric operating revenue		$	1,791		$	1,305
Natural gas operating revenue			931		830
Cost of electricity			561		554
Cost of natural gas			578		486
Operating and maintenance			808		712
Recognition of regulatory assets			(4,900)		-
Depreciation, amortization and decommissioning			311		310
Reorganization professional fees and expenses			2		35

Operating income			5,362		38
Interest income			11		11
Interest expense			(213)		(220)
Other expense, net⁽¹⁾			5		9

Income (loss) before income taxes			5,165		(162)
Income tax benefit (provision)			2,099		(84)

Income (loss) before cumulative effect of a change in accounting principle			3,066		(78)
Cumulative effect of a change in accounting principle			-		(1)

Income (loss) available for (allocated to) common stock		$	3,066		$	(79)



PG&E Corporation, Eliminations and Other⁽²⁾⁽³⁾
Operating revenues		$	-		$	(2)
Operating expenses			9		(26)

Operating income			(9)		24
Interest income			3		1
Interest expense			(18)		(35)
Other income (expense), net⁽¹⁾			(32)		(1)

Loss before income taxes			(56)		(11)
Income tax benefit			(23)		(6)

Loss from continuing operations			(33)		(5)
Discontinued operations			-			(265)
Cumulative effect of changes in accounting principles			-			(5)

Net loss		$	(33)		$	(275)



Consolidated Total⁽³⁾
Operating revenues		$	2,722		$	2,133
Operating expenses (gain)			(2,631)		2,071

Operating income			5,353		62
Interest income			14		12
Interest expense			(231)		(255)
Other income (expenses), net⁽¹⁾			(27)		8

Income (loss) before income taxes			5,109		(173)
Income tax provision (benefit)			2,076		(90)

Income (loss) from continuing operations			3,033		(83)
Discontinued operations			-			(265)
Cumulative effect of changes in accounting principles			-			(6)

Net income (loss)		$	3,033		$	(354)





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

~~Overall Results~~

PG&E Corporation's net income for the three months ended September 30, 2003, was $510 million compared to $466 million for the same period in 2002. PG&E Corporation's net income for the nine months ended September 30, 2003, was $383 million compared to $1,315 million for the same period in 2002.

The significant increases (decreases) in income from continuing operations for the three- and nine-month periods ended September 30, 2003 compared to the same periods in 2002, are summarized in the table below:

Three months
ended
Nine months
ended
(in millions)
September 30
September 30
PG&E Corporation
Interest expense
$
44
$
33
Utility
Electric revenues
41
(631)
Natural gas revenues
113
415
Cost of electricity
(124)
(841)
Cost of natural gas
(114)
(407)
Operating and maintenance expenses
191
174
Depreciation, amortization and decommissioning
4
(36)
Reorganization professional fees and expenses
25
(41)
Interest and other income, net
(5)
(2)
Interest expense
(16)
86

~~Interest Expense~~

PG&E Corporation's interest expense decreased for both the three months and nine months ended September 30, 2003, compared to the same periods in 2002. The decrease in interest expense is primarily due to the reduction in interest rates and outstanding long-term debt balances during 2003, compared to 2002. During the third quarter of 2002, PG&E Corporation recognized a write-off of approximately $68 million of deferred charges and unamortized loan discounts in connection with the repayment and modification of PG&E Corporation's amended and restated loan agreement. During the third quarter of 2003, PG&E Corporation recognized 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.

~~Dividends~~

PG&E Corporation did not declare any dividends in the first nine months of 2003 or 2002. PG&E Corporation was prohibited from paying dividends under the terms of its $720 million credit agreement with Lehman Commercial Paper, Inc. until the loans were repaid. On July 2, 2003, amounts outstanding under the credit agreement were repaid through the issuance of $600 million of new 6⅞ percent Senior Secured Notes (Notes). (See Note 3 of the Notes to the Consolidated Financial Statements for further details.) The Note indenture prohibits PG&E Corporation from declaring or paying dividends unless, as specified in the indenture, it has either met certain financial criteria, and no default is outstanding under the indenture or would result from the payment of such dividends or a specified exception applies. These specified exceptions include circumstances in which: (1) PG&E Corporation achieves an investment grade credit rating, or (2) following the implementation of the Utility's Settle ment Plan, PG&E Corporation pays any dividend from the proceeds of cash distributions to PG&E Corporation from the Utility. Certain of these exceptions also include the requirement that no default is outstanding under the indenture or would result from the payment of such dividends.

~~NEGT, Inc. has not declared a dividend since reorganization in 2002 and PG&E Corporation will not receive any distribution under the terms of NEGT, Inc.'s plan of reorganization.~~

While in Chapter 11, the Utility is not allowed to pay dividends without Bankruptcy Court approval. In addition, the proposed CPUC settlement agreement and Settlement Plan would prohibit the Utility from paying dividends to PG&E Corporation before July 1, 2004. Assuming the proposed CPUC settlement agreement is approved and the Settlement Plan implemented, PG&E Corporation does not anticipate paying a dividend until the later part of 2005.

Historically, in determining whether to, and at what level to, declare dividends, PG&E Corporation's Board of Directors has considered a number of financial factors, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk, as well as other factors, including the regulatory and legislative environment, operating performance, and capital and financial resources in general.

Utility

Significant Factors Affecting Results

With the implementation of new electricity balancing accounts, electricity procurement costs and items such as changes in sales volumes no longer have the same impact on the Utility's results of operations that they had in prior years. As a result of CPUC decisions approving the Settlement Agreement and implementing various ratemaking mechanisms, the Utility no longer collects the frozen electric rates and surcharges that it collected in 2003, 2002 and 2001. Instead, the Utility collects cost-of-service based electric rates that are the sum of individual revenue requirement components, including base revenue requirements, revenue requirements for the Settlement Regulatory Asset, electricity procurement costs, and the DWR revenue requirement, among others. The GRC determines the amount of authorized base revenues the Utility can collect from customers to recover its basic business and operational costs for electric ity and natural gas distribution operations and for electricity generation operations. The Utility has filed its 2003 GRC with the CPUC and is awaiting a final decision (See the "Regulatory Matters" section of this MD&A).

Electricity procurement costs historically have impacted the Utility's results of operations and financial condition. California legislation has been enacted which allows the Utility 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, for 2004 and beyond, electricity procurement costs are not expected to have the same impact on the Utility's results of operations that they had during the California energy crisis. However, the level of electricity procurement costs will continue to have an impact on cash flows.

Operating expenses are a key factor in determining whether the Utility earns the rate of return authorized by the CPUC. Many of the Utility's costs, including electricity procurement costs, discussed above, are subject to ratemaking mechanisms that are intended to provide the Utility the opportunity to fully recover these costs. However, there is no ratemaking mechanism for recovery of the Utility's operating and maintenance expenses. As a result, changes in the Utility's operating expenses impact the Utility's results of operations.

The Utility's distribution, generation, transmission and transportation 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 $1.7 billion annually over the next five years. A significant outage at any of these facilities may have a material impact on the Utility's operations. Costs associated with replacement electricity and natural gas or use of alternative facilities during these outages could have an adverse impact on PG&E Corporation's and the Utility's results of operations and liquidity.

The following presents the Utility's operating results for the first quarters of 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.

Electric Operating Revenues

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

Three months ended
Nine months ended
September 30,
September 30,
(in millions)
2003

2002

2003

2002

Residential
$
996

$
1,046

$
2,740

$
2,805
Commercial
1,292

1,468

3,208

3,464
Industrial
381

448

1,037

1,153
Agricultural
204

222

402

443
Miscellaneous
44

112

330

335
Direct access credits
(102)

(95)

(252)

(285)
DWR pass-through revenue
(291)

(718)

(1,642)

(1,461)
Total electric operating revenues
$
2,524

$
2,483

$
5,823

$
6,454

	Three Months Ended
	March 31,

(in millions)	2004		2003


Residential	$	975	$	920
Commercial	866		811
Industrial	267		259
Agricultural	61		68
DWR pass-through revenue	(470)		(757)

Subtotal	1,699		1,301
Miscellaneous	92		4

Total electric operating revenues	$	1,791	$	1,305

~~Electric~~ In the first quarter of 2004, the Utility's electricity operating revenues increased ~~$41~~approximately $486 million, or ~~1.7 percent, for the three months ended September 30, 2003,~~37%, compared to the same period in ~~2002 primarily~~2003 mainly due to the ~~following:~~

Electric sales volume increased by 4 percent for the three months ended September 30, 2003, compared to the same period in 2002, primarily due to warmer weather in the third quarter of 2003. The increase in electric revenues, as a result of the increase in electric sales volume, was offset by a one-time bill credit associated with the reduction in the 2003 DWR revenue requirement discussed below.

Amounts recorded as pass-through revenue to the DWR decreased by $427 million for the three months ended September 30, 2003, compared to the same period in 2002. The Utility passes revenue through to the DWR for electricity provided by the DWR to the Utility's customers. The decrease was primarily due to (1) a reduction in the 2003 DWR revenue requirement, and (2) an adjustment recorded in the third quarter of 2002 to reflect changes to the methodology used to calculate DWR pass-through revenues. These decreases were partially offset by an additional bond charge passed through to the DWR, which began in November 2002, and an increase in the Utility's DWR power charge remittance rate effective January 1, 2003.

The reduction in the DWR's 2003 revenue requirement was due primarily to a September 2003 CPUC decision that reduced the DWR's approved revenue requirement for 2003. This reduction was offset by a corresponding reduction in electric revenues for each customer class, as the decision also required the Utility to pass the benefit of the revenue requirement reduction on to its customers through a separate one-time bill credit. (See the "Regulatory Matters" section of this MD&A.)following factors:

·	Pass-through revenue to the DWR decreased by approximately $287 million, or 38%, in the first quarter of 2004 as compared to the first quarter of 2003. This decrease was mainly due to a decrease in the Utility's DWR power charge remittance rate effective January 1, 2004 and a decrease in volume provided by the DWR contracts due to an increase in the amount of electricity generated by the Utility in the first quarter of 2004 as compared to the same period in 2003. The increase in electricity generated by the Utility in 2004 was mainly due to an extended scheduled outage at the Diablo Canyon power plant in the first quarter of 2003.
	As previously discussed, with the implementation of cost-of-service based rates, changes in the DWR revenue requirements change rates charged to certain of the Utility's customers. As a result, changes in amounts passed through to the DWR no longer affect the Utility's results of operations as they had in prior years.
·	Electric revenue increased by approximately $305 million as compared to the same period in the prior year due to an electric revenue under-collection in the first quarter of 2003 as a result of the lack of a regulatory recovery mechanism. The implementation of the rate design settlement provides the Utility with a regulatory recovery mechanism in 2004.
·	These increases in electric revenues were partially offset by a rate reduction of approximately $130 million in the first quarter of 2004. The rate design settlement, effective January 1, 2004, implemented an annual electricity rate reduction of approximately $799 million.

From January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the Utility's net open position (the amount of electricity needed by retail customers that cannot be met by Utility-owned generation or existing electricity contracts). The Utility resumed purchasing electricity on the open market in January 2003, but still relies on electricity provided by DWR contracts to service a significant portion of its total load. Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Consolidated Statements of Income, reflecting the Utility's role as a billing and collection agent, for which the Utility collects no fees, for the DWR's sales to the Utility's customers.

~~Electric operating revenues decreased $631 million, or 9.8 percent, for the nine months ended September 30, 2003, compared to the same period in 2002 primarily due to the following:~~

Amounts recorded as pass-through revenues to the DWR increased by $181 million for the nine months ended September 30, 2003, compared to the same period in 2002. The Utility passes revenue through to the DWR for electricity provided by the DWR to the Utility's customers. The increase in DWR pass-through revenues was primarily due to (1) an additional bond charge passed through to the DWR, which began in November 2002, (2) an increase in volume supplied by the DWR, and (3) an increase in the Utility's DWR power charge remittance rate effective January 1, 2003. The increase in DWR pass-through revenues was partially offset by the reduction in the 2003 DWR revenue requirement described above.

The average electric sales price decreased during 2003 due to a May 2002 CPUC decision that increased baseline quantity allowances. An increase to a customer's baseline quantity allowance increases the amount of the customer's monthly usage that is covered under the lowest possible rate and is exempt from the three-cent surcharge.

The decrease in electric revenues was partially offset by an increase in electric sales volume due to warmer weather in 2003 and an increase in the amount recorded in 2003 to include an estimate for electricity delivered to customers whose bills have been delayed.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities but excludes costs to operate its generation facilities. The following table shows a breakdown of the Utility's cost of electricity ~~(which includes the cost of fuel used by the Utility owned generation facilities and electricity purchase costs)~~ 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)
2003

2002

2003

2002

Cost of purchased power
$
710

$
529

$
1,856

$
1,415
Proceeds from surplus sales allocated to the Utility
(63)

-

(197)

-
Fuel used in own generation
32

26

76

74
Adjustment to purchased power accruals
-

-

-

(595)
Total Cost of Electricity
$
679

$
555

$
1,735

$
894
Average cost of purchased power per kWh
$
0.071

$
0.075

$
0.074

$
0.074
Total purchased power (GWh)
9,982

7,080

25,230

19,219

	Three Months Ended March 31,

(in millions)	2004		2003


Cost of purchased power	$	582	$	575
Proceeds from surplus sales allocated to the Utility	(64)		(38)
Fuel used in own generation	43		17

Total cost of electricity	$	561	$	554



Average cost of purchased power per kWh	$	0.083	$	0.085

Total purchased power (GWh)	6,997		6,765

~~The~~ In the first quarter of 2004, the Utility's cost of electricity increased ~~$124~~approximately $7 million, or ~~22.3 percent, for the three months ended September 30, 2003, and $841 million, or 94.1 percent, for the nine months ended September 30, 2003,~~1%, compared to the same ~~periods~~period in ~~2002. Increases in the cost of electricity for both periods were primarily~~2003 due to an increase in the ~~total volume~~average cost of fuel used by the Utility's own generation facilities and an increase in the amount of electricity ~~purchased. In~~generated by the Utility. The increase in electricity generated by the Utility was mainly due to an extended scheduled refueling outage at the Diablo Canyon power plant in the first quarter of 2003, the Utility began buying and selling electricity on the open market in accordance with its CPUC-approved electricity procurement plan (see the "Regulatory Matters" section of this MD&A). Based on the CPUC requirement to perform least-cost dispatch, the Utility is required to dispatch all of the generating resources within its portfolio, including DWR contracts assigned to the Utility to administer, in the most cost-effective way. This requirement in certain cases requires the Utility to schedule more electricity than is required to meet its retail load and to sell this additional electricity on the o pen market. This typically occurs when the expected sales proceeds exceed the variable costs to operate a resource or call on a contract.2003.

The increase in ~~total costs~~the cost of fuel was partially offset by ~~proceeds from~~an increase in surplus ~~electricity sales.~~sales as the Utility's scheduled power exceeded customer demand in the first quarter of 2004. 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 electricity.

Increases in the cost of electricity for the nine months ended September 30, 2003, were also due to a net $595 million reduction to the cost of electricity recorded in March 2002 as a result of FERC and CPUC decisions, which allowed the Utility to reverse previously accrued Independent System Operator (ISO) charges and to adjust for the amount previously accrued as payable to the DWR for its 2001 revenue requirement.

Natural Gas Revenues

The following table shows a breakdown of the Utility's natural gas revenues:

Three months ended
September 30,

Nine months ended
September 30,
(in millions)
2003

2002

2003

2002

Bundled gas revenues
$
355

$
237

$
1,840

$
1,382
Transportation service-only revenues
76

87

209

247
Other
148

142

28

33
Total Natural Gas Revenues
$
579

$
466

$
2,077

$
1,662
Average bundled revenue per Mcf of natural gas sold
$
8.88
$
5.64
$
8.89
$
6.40
Total bundled gas sales (in millions of Mcf)
40
42
207
216

~~Bundled~~

	Three Months Ended March 31,

(in millions)	2004		2003


Bundled gas revenues	$	867	$	764
Transportation service-only revenues	64		66

Total natural gas revenues	$	931	$	830



Average bundled revenue per Mcf of natural gas sold	$	7.74	$	7.28

Total bundled gas sales (in millions of Mcf)		112		105

In the first quarter of 2004, the Utility's total natural gas operating revenues increased ~~$118~~approximately $101 million, or ~~49.8 percent, for the three months ended September 30, 2003, and $458 million, or 33.1 percent, for the nine months ended September 30, 2003,~~12%, compared to the same ~~periods~~period in ~~2002. Increases for both periods were primarily a result of~~2003 mainly due to a higher average cost of natural gas, which ~~was passed along~~the Utility is permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per thousand cubic feet, ~~(Mcf)~~or Mcf, of natural gas sold in the first quarter of 2004 increased ~~$3.24,~~$0.46, or ~~57.4 percent, for~~6%, compared to 2003. In addition, the ~~three months ended September 30, 2003, and $2.49, or 38.9 percent, for~~Utility's total volume of bundled gas sales increased in the ~~nine months ended September 30, 2003,~~first quarter of 2004 by approximately 7% compared to the same ~~periods~~period in ~~2002.~~

~~Transportation service-only revenues decreased by $11 million, or 12.6 percent, for the three months ended September 30,~~ 2003 ~~and $38 million, or 15.4 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. These decreases were primarily~~mainly due to ~~a decrease in demand for natural gas transportation services by natural gas-fired electric generators in California.~~

Other natural gas revenues primarily include balancing account revenues. These revenues increased $6 million, or 4.2 percent, for the three months ended September 30, 2003, and decreased $5 million, or 15.2 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. The Utility tracks natural gas revenues and costs in natural gas balancing accounts. Over-collections and under-collections are deferred until they are refunded to or received from the Utility's customers through rate adjustments.colder weather.

Cost of Natural Gas

The Utility's cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate and intrastate pipelines. 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)
2003

2002

2003

2002

Cost of natural gas sold
$
203

$
98

$
941

$
560
Cost of natural gas transportation
30

21

98

72
Total Cost of Natural Gas
$
233

$
119

$
1,039

$
632
Average cost per Mcf of natural gas purchased
$
5.08
$
2.33
$
4.55
$
2.59
Total natural gas purchased (in millions of Mcf)
40
42
207
216

	Three Months Ended March 31,

(in millions)	2004		2003


Cost of natural gas sold	$	542	$	450
Cost of natural gas transportation	36		36

Total Cost of natural gas	$	578	$	486



Average cost per Mcf of natural gas purchased	$	4.84	$	4.29

Total natural gas sold (in millions of Mcf)		112		105

~~The~~ In the first quarter of 2004, the Utility's total cost of natural gas sold increased ~~$105~~approximately $92 million, ~~for the three months ended September 30, 2003, and $381 million for the nine months ended September 30, 2003,~~or 19%, compared to the same ~~periods~~period in ~~2002. Increases for both periods were primarily~~2003 mainly due to an increase in the average cost of natural gas ~~purchased~~sold in 2004 of ~~$2.75~~$0.55 per Mcf, ~~and $1.96 per Mcf for~~or 13%. In addition, the ~~three- and nine-month periods ended September 30, 2003, compared to the same periods in 2002.~~

~~The~~ Utility's ~~cost to transport~~total volume of natural gas ~~to its service area~~sold increased by $9 million, or 42.9 percent, for the three months ended September 30, 2003, and $26 million, or 36.1 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. These increases were primarily due to new pipeline transportation charges paid to the El Paso Natural Gas Company pipeline. The Utility, along with other California utilities, was ordered by the CPUC in July 2002 to enter into long-term contracts to purchase firm transportation services on the El Paso Natural Gas Company pipeline.

~~Operating and Maintenance~~

The Utility's operating and maintenance expenses decreased $191 million, or 22.2 percent, for the three months ended September 30, 2003, and $174 million, or 7.7 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Decreases for both periods were primarily due to the following:

The recording of regulatory liabilities for surcharge revenues during 2002, with no comparable amounts in 2003. In January 2001, the CPUC increased electric rates by various surcharges and restricted the use of these surcharge revenues to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC authorized the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. As a result, the Utility reversed its existing regulatory liabilities related to the surcharge revenues during the fourth quarter of 2002 and no longer reserved these amounts, resulting in a decrease in operating and maintenance expenses in 2003. (See the "Regulatory Matters" section of this MD&A.)

A net increase in deferred electric transmission-related costs compared to 2002. Electric transmission-related costs are included in the cost of electricity and consist primarily of reliability must run charges from the ISO. To the extent the Utility does not receive revenues sufficient to recover electric transmission-related costs, the costs are deferred through a reduction of operating and maintenance expense until recovered through future rates.

The decrease in operating and maintenance expenses was partially offset by higher recorded costs for environmental matters and increases in employee-related expenses, public purpose programs spending, customer-related costs, and maintenance expenses incurred during the scheduled refueling outage at the Diablo Canyon Power Plant in the first quarter of ~~2003.~~

~~Depreciation, Amortization, and Decommissioning~~

Depreciation, amortization, and decommissioning expenses decreased $4 million, or 1.3 percent, for the three months ended September 30, 2003, and increased $36 million, or 4.1 percent, for the nine months ended September 30, 2003, as compared to the same periods in 2002. The increase in depreciation expense for the nine months ended September 30, 2003, was due primarily to an overall increase in the Utility's plant assets and an increase of $12 million in amortization of the rate reduction bond regulatory asset, which began at the end of January 2002.

~~Reorganization Fees and Expenses~~

~~In accordance with the American Institute of Certified Public Accountants' Statement of Position (SOP) 90-7, "Financial Reporting~~2004 by Entities in Reorganization Under the Bankruptcy Code" (SOP 90-7), the Utility reports reorganization fees and expenses separately on its Consolidated Statements of Income. Such costs primarily include professional fees for services in connection with the Utility's Chapter 11 proceedings and totaled $16 million for the three months ended September 30, 2003, and $116 million for the nine months ended September 30, 2003.

~~Interest Income~~

In accordance with SOP 90-7, the Utility reports reorganization interest income separately on its Consolidated Statements of Income. Such income primarily includes interest earned on cash accumulated during the Utility's Chapter 11 proceedings. Interest income, which includes reorganization interest income, decreased $7 million, or 38.9 percent, for the three months ended September 30, 2003, and $17 million, or 28.8 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Decreases for both periods were due primarily to lower average interest rates earned on the Utility's short-term investments.

~~Interest Expense~~

~~The Utility's interest expense increased $16million, or 7.2 percent, for the three months ended September 30, 2003,~~approximately 7% compared to the same period in ~~2002 primarily~~2003 mainly due to colder weather.

Operating and Maintenance

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

In the first quarter of ~~interest payable to~~2004, the DWR. The interest was to compensate the DWR for prior underpayments resulting from ambiguities in the formula that determined the payment. These ambiguities were resolved by the CPUC in a decision issued in September 2003. (See the "Regulatory Matters" section of this MD&A.)

~~The~~ Utility's ~~interest expense decreased $86~~operating and maintenance expenses increased approximately $96 million, or ~~11.2percent, for the nine months ended September 30, 2003,~~13%, compared to the same period in ~~2002~~2003 mainly due to wage increases of approximately $36 million and higher recorded costs of approximately $37 million for environmental matters resulting from reassessments of the estimated liability for various sites. In addition, the Utility incurred approximately $29 million in expenses related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and the donation of land.

Interest Expense

In the first quarter of 2004, the Utility's interest expense decreased approximately $7 million, or 3%, compared to the same period in 2003 mainly due to a lower average amount of unpaid debts accruing interest.

PG&E Corporation, Eliminations and Others

Operating Revenues and Expenses

PG&E Corporation's revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to affiliates. Operating expenses allocated to affiliates are eliminated in consolidation.

In the first quarter of 2004, PG&E Corporation's operating expenses increased by $35 million. This increase was primarily due to increased external legal fees incurred in relation to the Utility and NEGT Chapter 11 proceedings and other administrative expenses in 2004.

Interest Expense

PG&E Corporation's interest expense is not allocated to its affiliates. In the first quarter of 2004, PG&E Corporation's interest expense decreased by approximately $17 million, or 49%, compared to the same period in 2003. The decrease is mainly due to a reduction ~~of interest on rate reduction bonds~~in principal amounts outstanding and a lower ~~level~~interest rate.

Other Expense

In the first quarter of ~~unpaid debts accruing interest. The decrease~~2004, PG&E Corporation's other expense increased by $31 million compared to the same period in 2003. This increase was ~~partially offset~~due to a $32 million pre-tax charge to earnings related to the change in market value of non-cumulative dividend participation rights included within its $280 million of 9.50% Convertible Subordinated Notes.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

At March 31, 2004, PG&E Corporation had approximately $11.3 billion of unrestricted consolidated cash and cash equivalents and restricted cash, of which approximately $7.8 billion was restricted. PG&E Corporation and the Utility maintain separate bank accounts. At March 31, 2004, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $611 million and restricted cash of $361.5 million. At March 31, 2004 the Utility had cash and cash equivalents and restricted cash of approximately $10.3 billion. 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.

Utility

At March 31, 2004, the Utility had approximately $2.9 billion of consolidated cash and cash equivalents, and restricted cash of approximately $7.4 billion. Until March 2004, the Utility's principal source of cash was payments from its customers. Since wholesale electricity prices moderated and electricity surcharges were fully implemented in mid-2001, the cash generated by the ~~recording of interest payable~~Utility's operations exceeded its ongoing cash requirements.

During its Chapter 11 proceeding, the Utility did not have access to the ~~DWR described above.~~

~~Dividends~~capital markets and met all its ongoing cash requirements, including its capital expenditure requirements, with cash generated by its operations. In addition, the Utility paid interest on certain pre-petition liabilities and repaid the principal of maturing mortgage bonds with bankruptcy court approval.

~~While~~ In March 2004, in anticipation of the Utility's emergence from Chapter 11, the Utility ~~is not allowed~~and its consolidated subsidiaries issued $6.7 billion of First Mortgage Bonds and 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 on April 12, 2004, the effective date 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 the First Mortgage Bonds, borrowings of approximately $1.1 billion and approximately $2.4 billion of cash on hand were used on the Effective Date to pay ~~dividends without Bankruptcy Court approval. Under~~allowed creditor claims or deposited into escrow to pay disputed claims when resolved. See Note 3 to the ~~proposed CPUC settlement agreement~~Consolidated Financial Statements for further discussion of the First Mortgage Bonds and the Settlement Plan, there would be no restriction on the ability of the Utility to declare and pay dividends or repurchase common stock, other than the capital structure and stand-alone dividend conditions contained in prior CPUC holding company decisions; provided, however, that the Utility would agree that it would not pay dividends on its common stock before July 1, 2004. Assuming the proposed CPUC settlement agreement is approved and the Settlement Plan implemented, the Utility does not anticipate paying a dividend until the later part of 2005.Ut ility's new credit facilities.

~~CASH FLOWS~~

~~Utility~~

The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004 and ~~2002.~~2003.

Operating Activities

The Utility's cash flows from operating activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2004, and 2003 ~~and 2002~~ were as follows:

Nine months ended
September 30,
(in millions)
2003
2002
Net income
$
861
$
1,592
Non-cash (income) expenses:
  Depreciation, amortization, and decommissioning
916
880
  Net reversal of ISO accrual
-
(970)
Change in accounts payable
350
139
Change in income taxes payable
437
179
Other uses of cash:
  Payments authorized by the Bankruptcy Court on amounts classified as
    Liabilities Subject to Compromise
(83)
(1,180)
Other changes in operating assets and liabilities
58
614
Net cash provided by operating activities
$
2,539
$
1,254

	Three Months Ended March 31,

(in millions)	2004		2003


Net income (loss)	$	3,074	$	(73)
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	311		310
Recognition of regulatory assets, net of tax	(2,904)		-
Change in other working capital	253		24
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(20)		(39)
Other changes in operating assets and liabilities	295		512

Net cash provided by operating activities	$	1,009	$	734

Net cash provided by operating activities increased by ~~$1,285~~approximately $275 million during the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, compared to the same period in ~~2002. This increase was primarily~~2003 mainly due to the ~~following factors:~~

~~Payments on amounts classified as Liabilities Subject to Compromise decreased by $1,097 million~~increase in net income for the ~~nine~~three months ended ~~September 30, 2003, compared to~~March 31, 2004, excluding the ~~same period in 2002, due to significant pre-petition amounts paid to QFs in the nine months ended September 30, 2002, based on Bankruptcy Court-approved settlements;~~

Net income decreased by $731 million in the nine months ended September 30, 2003, compared to the same period in 2002. Net income in the nine months ended September 30, 2002, included a $970 million reduction to costone-time non-cash gain, after-tax, of ~~electricity~~approximately $2.9 billion related to the ~~reversal~~recognition of ~~ISO charges.~~

the Settlement Agreement regulatory assets.

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 the three months ended March 31, 2004. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other damage.

The Utility's cash flows from investing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002~~ were as follows:

Nine months ended
September 30,
(in millions)
2003
2002
Capital expenditures
$
(1,182)
$
(1,156)
Net proceeds from sale of assets
14
8
Other investing activities
(25)
16
Net cash used by investing activities
$
(1,193)
$
(1,132)

	Three Months Ended March 31,

(in millions)	2004		2003


Capital expenditures	$	(342)	$	(371)
Net proceeds from sale of assets	18		5
Increase in restricted cash	(6,917)		-
Other investing activities	(65)		9

Net cash used by investing activities	$	(7,306)	$	(357)

Net cash used by investing activities increased by ~~$61 million~~approximately $6.9 billion during the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, compared to the same period in ~~2002. The~~2003. This increase was ~~primarily attributable~~mainly due to ~~an increase in capital expenditures and other investing activities during~~ the ~~nine months ended September 30, 2003. Cash flows from other investing activities relate primarily to nuclear decommissioning funding and the change in nuclear fuel inventory during the period.~~following factors:

Restricted cash increased approximately $6.9 billion for the three months ended March 31, 2004, compared to the same period in 2003, mainly due to the deposit into an escrow account of the proceeds of the Utility's public offering of approximately $6.7 billion of First Mortgage Bonds issued in March 2004 and redemption premiums and interest of approximately $217 million. As the Utility's Plan of Reorganization was not yet effective at the time of closing the offering, the Utility deposited all First Mortgage Bond proceeds into an escrow account. On the Effective Date approximately $6.9 billion was paid out of the escrow account.

An increase in nuclear decommissioning funding offset by a decrease in capital expenditures. The decrease in capital expenditures related to a decrease in electricity transmission network expenditures and transmission development project costs offset by an increase in electricity distribution network upgrades during the three months ended March 31, 2004, compared to the same period in 2003.

Financing Activities

Prior to the implementation of the Plan of Reorganization and during its Chapter 11 proceeding, the Utility's financing activities were limited to 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 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 for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit.

The Utility's cash flows from financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002~~ were as follows:

Nine months ended
September 30,
(in millions)
2003
2002
Long-term debt issued, matured, redeemed, or repurchased
$
(280)
$
(333)
Rate reduction bonds matured
(213)
(213)
Other financing activities
(1)
-
Net cash used by financing activities
$
(494)
$
(546)

	Three Months Ended March 31,

(in millions)	2004		2003


Net proceeds from issuance of long-term debt	$	6,547	$	-
Long-term debt issued, matured, redeemed or repurchased		(310)		-
Rate reduction bonds matured	(74)		(74)

Net cash provided (used) by financing activities	$	6,163	$	(74)

~~Net~~ For the three months ended March 31, 2004, net cash ~~used~~provided by financing activities ~~decreased~~increased by ~~$52 million during the nine months ended September 30, 2003,~~approximately $6.2 billion compared to the same period in ~~2002. The decrease~~2003. This increase was mainly due to ~~a $53 million decrease in principal repayments on mortgage bonds by order of~~ the ~~Bankruptcy Court during the nine months ended September 30, 2003, compared to the same period in 2002.~~following factors:

·	In March 2004, in connection with the implementation of the Utility's Plan of Reorganization, the Utility consummated a public offering of $6.7 billion in First Mortgage Bonds. In April 2004, the Utility used the net proceeds of approximately $6.5 billion from the offering together with other funds to pay creditor claims and deposit funds into escrow for the payment of disputed claims.
·	The Utility repaid approximately $310 million in principal on its first and refunding mortgage bonds that matured in March 2004.

PG&E Corporation

~~The following section discusses~~ At March 31, 2004, PG&E Corporation's ~~significant~~stand-alone cash ~~flows~~and cash equivalents balance was approximately $611 million. PG&E Corporation's sources of funds are dividends from ~~operating, investing,~~the Utility, issuance of its common stock and ~~financing activities for~~external financing. The Utility did not pay any dividends to PG&E Corporation during the ~~nine months ended September 30, 2003, and 2002.~~first quarter of 2004 or 2003. PG&E Corporation also has $361.5 million of restricted cash that is recorded in noncurrent assets at March 31, 2004. This restricted cash pertains to the tax dispute with NEGT described above.

Operating Activities

PG&E Corporation's cash flows from operating activities consist mainly of billings to its 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 three months ended March 31, 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, 2004 and 2003 ~~and 2002~~ were as follows:

Nine months ended
September 30,
(in millions)
2003
2002
Net income
$
383
$
1,315
Loss from discontinued operations
365
156
Cumulative effect of changes in accounting principles
6
61
Net income from continuing operations
754
1,532
Non-cash (income) expenses:
   Depreciation, amortization, and decommissioning
910
881
   Deferred income taxes and tax credits - net
339
176
   Other deferred charges and noncurrent liabilities
636
(188)
   Loss from retirement of long-term debt
89
153
Other changes in operating assets and liabilities
188
(1,303)
Net cash provided by operating activities
$
2,916
$
1,251

	Three Months Ended March 31,

(in millions)	2004		2003


Net income (loss)	$	3,033	$	(354)
Loss from discontinued operations	-		265
Cumulative effect of changes in accounting principles	-		6

Net income (loss) from continuing operations	3,033		(83)
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	312		310
Recognition of regulatory asset, net of tax	(2,904)		-
Deferred income taxes and tax credits - net	(70)		(15)
Other deferred charges and noncurrent liabilities	237		189
Other changes in operating assets and liabilities	279		532

Net cash provided by operating activities	$	887	$	933

Net cash provided by operating activities ~~increased~~decreased by ~~$1,665~~$46 million during the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, compared to the same period in ~~2002.~~2003. This ~~increase~~decrease was primarily ~~due~~related to ~~the effect of Utility cash flows from operations discussed above, and the following factors:~~

~~A decrease in charges associated with the retirement of long-term debt and the write-off of deferred financing costs.~~

~~An increase~~decreases in other deferred charges and noncurrent liabilities ~~primarily related to deferred tax benefits recognized~~and restricted cash, partially offset by the Utility's increase in ~~respect of NEGT, Inc. losses.~~

net cash provided from operating activities as discussed above.

Investing Activities

PG&E ~~Corporation's cash flows from~~Corporation, on a stand-alone basis, did not have any material investing activities ~~for~~in the ~~nine~~three months ended ~~September 30, 2003, and 2002 were as follows:~~

(in millions)
Nine months ended
September 30,
2003
2002
Capital expenditures
$
(1,183)
$
(1,156)
Net proceeds from sale of assets
14
8
Other, net
(24)
15
Net cash used by investing activities
$
(1,193)
$
(1,133)

Net cash used by investing activities increased by $60 million during the nine months ended September 30, 2003, compared to the same period in 2002. This increase was primarily due to an increase in Utility capital expenditures.March 31, 2004 or 2003.

Financing Activities

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

PG&E Corporation's cash flows from financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2004 and 2003 ~~and 2002~~ were as follows:

(in millions)
Nine months ended
September 30,
2003
2002
Long-term debt issued
582
564
Long-term debt matured, redeemed, or repurchased
(1,067)
(1,241)
Rate reduction bonds matured
(213)
(213)
Common stock issued
120
190
Other, net
(2)
-
Net cash used by financing activities
$
(580)
$
(700)

~~Net~~

	Three Months Ended March 31,

(in millions)	2004		2003


Net proceeds from long-term debt issued	$	6,547	$	-
Long-term debt matured, redeemed or repurchased	(310)		-
Rate reduction bonds matured	(74)		(74)
Common stock issued	58		21

Net cash provided (used) by financing activities	$	6,221	$	(53)

PG&E Corporation's net cash ~~used~~provided by financing activities ~~decreased~~increased by ~~$120 million during~~$6.3 billion for the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, compared to the same period in ~~2002.~~2003. This ~~decrease~~increase was primarily ~~due~~related to ~~a reduction in cash used in~~the Utility's financing activities ~~by the Utility~~ as discussed above, ~~and an~~in addition to the increase in ~~long-term~~cash received from the sale of common stock.

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. At April 12, 2004, approximately $644 million was available for borrowing under the working capital facility and approximately $206 million was allocated to outstanding letters of credit. In addition, the Utility has entered into a $650 million accounts receivable financing. The Utility used $350 million on the Effective Date, leaving $300 million available.

The Utility expects that the cash it retains after its emergence from Chapter 11, 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.

Dividend Policy

Historically, in determining whether to, and at what level to, declare a dividend, PG&E Corporation has considered a number of financial factors, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk, as well as other factors, including the regulatory and legislative environment, operating performance, and capital and financial resources in general. Other than payment in 2001 of the dividend declared in the fourth quarter of 2000, PG&E Corporation has not declared or paid a dividend during the Utility's Chapter 11 proceeding. Further, until the 6 ⅞% Senior Secured Notes issued ~~offset~~ by PG&E Corporation are rated Baa3 or better by Moody's and BBB- or better by S&P, PG&E Corporation is prohibited from declaring or paying dividends or repurchasing its common stock. Notwithstanding this restrictive covenant, PG&E Corporation may decla re a ~~decrease~~dividend if certain financial criteria are met or if PG&E Corporation's regular quarterly dividends are funded from proceeds of cash distributions to PG&E Corporation from the Utility. In addition, notwithstanding the restrictive covenant discussed above, PG&E Corporation may repurchase a portion of its common stock if certain financial criteria are met or, with certain restrictions, may repurchase common stock with proceeds of cash distributions to PG&E Corporation from the Utility. PG&E Corporation can redeem the Senior Secured Notes at any time at its option at a premium.

While in ~~long-term debt matured.~~Chapter 11, the Utility was prohibited from paying any common or preferred dividends without bankruptcy court approval. Terms of the Settlement Agreement prohibit the Utility from paying any dividends before July 1, 2004. The Utility expects to achieve the target capital structure provided for in the Settlement Agreement by the second half of 2005. Assuming the Utility's target capital structure is met by then, PG&E Corporation aspires to resume paying dividends in the second half of 2005.

CAPITAL EXPENDITURES AND COMMITMENTS

Contractual Commitments

~~The Utility has substantial financial commitments in connection with operating, construction, and development activities.~~

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, ~~power purchase agreements (including agreements with QFs, irrigation districts and water agencies, bilateral power purchase contracts, and renewable energy contracts),~~ nuclear fuel agreements, operating leases, and other commitments. ~~The Bankruptcy Court has authorized certain payments and actions necessary for~~In connection with the implementation of the Plan of Reorganization, the Utility ~~to continue its normal business operations while operating as~~issued $6.7 billion in First Mortgage Bonds, entered into $2.9 billion in credit facilities, and obtained a ~~debtor-in-possession.~~

The Utility's commitments under financing arrangements include obligations to repay first and refunding mortgage bonds, senior notes, medium-term notes, pollution-control bond-related agreements, Deferrable Interest Subordinated Debentures, lines$400 million cash collateralized letter of credit ~~letters~~facility. On the Effective Date, the $400 million letter of credit ~~floating rate notes,~~facility was cancelled and ~~commercial paper. These commitments have been stayed by~~ the ~~Bankruptcy Court, although~~outstanding letter of credit balance of approximately $206 million was transferred to the ~~Utility has requested and received permission to make scheduled maturity payments on secured debt as it comes due.~~Utility's $850 million revolving credit facility. In addition, the Utility ~~has been making post-petition interest payments on its financing debt on~~paid approximately $8.4 billion in cash to holders of allowed claims and deposited approximately $1.8 billion int o escrow accounts for the ~~due dates.~~payment of disputed claims.

~~PG&E Funding LLC, a wholly owned subsidiary~~Utility

Power Purchase Agreements

During the first quarter of 2004, the Utility ~~also~~entered into various agreements to purchase energy. Under these agreements, the Utility is ~~obligated~~committed to make ~~scheduled~~energy payments ~~on its rate reduction bonds. These bonds are included as commitments~~ of ~~the Utility.~~approximately $52 million and capacity payments of approximately $19 million in 2004.

Natural Gas Supply and Transportation Commitments

The ~~Utility's contractual commitments~~Utility purchases natural gas directly from producers and ~~obligations are discussed~~marketers in ~~PG&E Corporation's~~both Canada and the ~~Utility's 2002 Annual Report on Form 10-K, as amended, with updates~~United States to ~~such disclosures included in Note 6 of the Notes to the Consolidated Financial Statements.~~

~~REGULATORY MATTERS~~

~~A significant portion~~serve its core customers. The contract lengths and natural gas sources of the Utility's ~~operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, the Utility's revenues and pricing for its regulated services.~~portfolio of natural gas procurement contracts have fluctuated generally based on market conditions.

~~The discussion~~ As a result of ~~these matters below should be read in conjunction with the regulatory matters discussed in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.~~

~~As discussed above, on June 19, 2003, PG&E Corporation, the Utility, and the staff of the CPUC announced a proposed settlement agreement for~~ the Utility's Chapter 11 ~~filing. If the proposed CPUC settlement agreement ultimately is approved, several of the regulatory proceedings discussed~~filing and its credit rating being below would be impacted. The Utility cannot predict the ultimate outcome of the proposed CPUC settlement agreement, including when and whether it will be approved. Regulatory proceedings associated with the Utility's Chapter 11 proceeding and electric industry restructuring are further discussed in Notes 2 and 6 of the Notes to the Consolidated Financial Statements.

~~DWR Revenue Requirement~~

In 2001, as a result of the California energy crisis, the State of California authorized the DWR to purchase electricity to satisfy the difference between the aggregate electricity demand of the customers of the IOUs and the electricity those utilities had available for delivery from their own generation facilities and power purchase arrangements. California's AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The DWR is legally and financially responsible for the long-term contracts it entered into before December 31, 2002. It pays for its costs of purchasing electricity from a revenue requirement collected from the Utility's electricity customers through a charge, called a power charge. Because the Utility acts as the billing and collection agent for the DWR's sales of its electricity to retail customers, amounts collected on behalf of the DWR (related to its revenue requireme nt) are excluded from the Utility's revenues.

In December 2002, the CPUC issued a decision allocating approximately $2 billion of the DWR's 2003 $4.5 billion total statewide power charge-related revenue requirement to the Utility's customers. This revenue requirement includes the forecasted costs associated with the DWR allocated contracts during 2003. A December 2002 operating order required the Utility to perform the operational, dispatch, and administrative functions for the DWR allocated contracts beginning on January 1, 2003. In April 2003, the Utility and the DWR entered into a CPUC-approved operating agreement that supersedes the December 2002 operating order.

In July 2003, the DWR submitted a supplemental 2003 revenue requirement to the CPUC that reduced the amount of the total 2003 statewide power charge-related revenue the DWR was requesting by approximately $1 billion. In September 2003, the CPUC issued a decision that allocated this $1 billion reduction among the customers of the three California IOUs. The decision allocated approximately $444 million of the reduction to the customers of the Utility and required the Utility to provide a one-time bill credit to the Utility's customers to pass through the revenue requirement reduction. Prior ambiguities in the formula that determines the calculation of the Utility's collections payable to the DWR resulted in the Utility's underpayment of amounts the Utility paid the DWR through June 30, 2003. These ambiguities were resolved by the CPUC in a decision issued in September 2003. As of June 30, 2003,investment grade, the Utility had ~~accrued~~used several different credit arrangements to purchase natural gas, including a ~~$516~~$10 million ~~reserve based on~~cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. On March 2, 2004, these pledge facilities were replaced with a $400 million limited cash collateralized letter of credit facility, or gas procurement letter of credit facility. The gas customer accounts receivable program terminated effective March 29, 2004. At March 31, 2004, amounts secured by this gas procurement letter of credit facility totaled approximately $203 million. Upon emergence from Chapter 11 the Utility canceled this gas procurement letter of credit facility and transferred the outstanding balance to an $850 million revolving credit facility backed by the Utility's ~~estimate of underpayments. During Sept ember 2003,~~new credit faciliti es.

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

(in millions)

2004	$	678
2005	168
2006	26
2007	7
2008	-
Thereafter	-

Total	$	879

Transmission Control Agreement

The Utility is a party to a Transmission Control Agreement, or TCA, with the California Independent System Operator, or ISO, and other participating transmission owners. As a transmission owner, the Utility ~~paid the DWR $77 million (which equals the $521 million shortfall ultimately determined~~is required to ~~be due~~give two years notice and receive regulatory approval if it wishes to the DWR, less the Utility's $444 million share of the DWR's $1 billion statewide revenue reduction). This $444 million share of the statewide revenue reduction has been returned to the Utility's customers in the form of bill credits issued in September and October 2003. The September 2003 decision also reduces the Utility's DWR power charge base remittance rate (before adjusting for direct access remittances for DWR power) from $0.105 per kWh to $0.095 per kWh effective immediately. This reduction in the remittance rate is in addition to the $444 million reduction described above. In September 2003, the Utility filed an advice letter proposing to further reduce the rate from $0.095 to $0.085 effective October 1, 2003, to account for amounts collected and remitted from direct access customers. This advice letter is currently pending before the CPUC.

~~The DWR filed its proposed 2004 revenue requirement with the CPUC in September 2003. The DWR proposed a $4.5 billion revenue requirement for power charge-related costs in 2004~~withdraw from the ~~customers of~~TCA. Under this agreement, the three California IOUs. The CPUC is responsible for allocating the proposed 2004 revenue requirement among the customers of the IOUs. The CPUC will allocate the 2004 DWR power charge revenue requirement on an interim basis using the methodology adopted for the allocation of the 2003 DWR power charge revenue requirement. A later phase of this proceeding, with testimony scheduled to be filed in December 2003, will finalize the allocation of the DWR power charge revenue requirement for 2004 and possibly for the remaining years of the DWR contracts.

In testimony submitted to the CPUC on October 15 and 22, 2003, the Utility estimated that it over-remitted $107 million in power charges to the DWR for the 2001- 2002 period based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. The Utilitytransmission owners, which also ~~proposed that the CPUC use a different allocation methodology under which the Utility estimates it over-remitted $211 million. Testimony submitted by~~include Southern California Edison, ~~(SCE) and other parties includes varying estimates of the Utility's true-up adjustment depending on the allocation methodology proposed.~~or SCE, calculated that the Utility over-remitted approximately $101 million in power charges to the DWR based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. However, SCE also has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requi rement to allocate the bond proceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

The Utility has proposed to include any true-up adjustments to the DWR's 2001-2002 revenue requirement in each IOU's allocation of the 2004 DWR revenue requirement to be collected through the 2004 DWR remittance rate. SCE supports this proposal, but San Diego Gas & Electric Company ~~has proposed that any under-remittance that an IOU is determined to owe should be paid by the IOU immediately. CPUC hearings began on October 27, 2003,~~ and ~~the CPUC is expected to issue a decision on the 2001-2002 adjustments (as well as the 2004 DWR revenue requirement) in January 2004.~~

~~PG&E Corporation and the Utility expect that any amounts determined by the CPUC to have been under-remitted or over-remitted~~several municipal utilities, assign operational control of their electricity transmission systems to the ~~DWR by the Utility for the 2001-2002 period will be included in the DWR's revenue requirements in 2004 and subsequent periods, and collected or refunded on~~ISO. In addition, as a going-forward basis from the Utility's customers. However, PG&E Corporation and the Utility are unable to predict the outcome of this matter. If the CPUC retroactively determines that the Utility has under-remitted a material amountparty to the ~~DWR and orders~~TCA, the Utility to make a one-time true-up payment from cash on hand rather than collect the under-remitted amount from customers on a going-forward basis, the Utility's financial condition and results of operations would be materially adversely affected.

~~DWR Bond Charge~~

The DWR completed an $11.3 billion bond financing in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR electricity revenue requirement and to provide the DWR with funds needed to make its electricity purchases. In October 2002, the CPUC issued a decision that, in part, imposes charges to recover the DWR's bond costs from bundled and direct access customers starting November 15, 2002, as described below, although the decision found that the Utility would not need to increase customers' overall rates to incorporate the bond charge. The Utility billed and is passing through approximately $272 million in bond-related charges for the nine months ended September 30, 2003. The Utility expects to bill and pass through DWR bond-related charges of approximately $352 million for 2003. As noted above under "DWR Revenue Requirement," SCE has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requirement to allocate the bond proceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

PG&E Corporation and the Utility expect that any amounts determined by the CPUC to have been under-remitted or over-remitted to the DWR by the Utility for the 2001-2002 period will be included in the DWR's revenue requirements in 2004 and subsequent periods, and collected or refunded on a going-forward basis from the Utility's customers. However, PG&E Corporation and the Utility are unable to predict the outcome of this matter. If the CPUC retroactively determines that the Utility has under-remitted a material amount to the DWR and orders the Utility to make a one-time true-up payment from cash on hand rather than collect the under-remitted amount from customers on a going-forward basis, the Utility's financial condition and results of operations would be materially adversely affected.

The DWR filed its proposed 2004 revenue requirement with the CPUC in September 2003. In this proposed revenue requirement, the DWR states that it expects to collect $873 million for bond-related costs in 2004 from the customers of the three California IOUs. The CPUC is responsible for ~~allocating the proposed 2004 bond charge-related revenue requirement among the customers~~a share of the ~~IOUs. Under~~costs of reliability must-run, or RMR, agreements between the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC has agreed that DWR bond charges allocated to the Utility's customers will be included in rates in a manner that will not affect the Utility's collection of other authorized costs or return on capital.

~~Allocation of DWR Electricity to Customers~~ISO and owners of the ~~IOUs~~

~~In September 2002, the CPUC issued a decision~~power plants subject to ~~allocate the electricity provided under existing DWR contracts to the customers~~RMR agreements, or RMR Plants. The Utility also is an owner of ~~the IOUs. The DWR retains legal and financial responsibility for~~some of these ~~contracts.~~

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC could require the Utility to accept assignment of, or assume legal and financial responsibility for, the DWR allocated contractsRMR Plants for which the Utility ~~currently acts as billing and collection agent, but only if:~~

~~After assumption,~~receives revenue from the ~~Utility's issuer rating~~ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO's demand.
At March 31, 2004, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $666 million in net costs during the period April 1, 2004, to March 31, 2006. These costs are recoverable under 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 ALJ issued an initial decision approving rates that, if affirmed by ~~Moody's will be no less than A2~~the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ~~Utility's long-term issuer credit rating by S&P will be no less than A;~~

~~The CPUC first makes~~ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant's RMR Plants under these agreements. However, on July 14, 2003, Mirant filed a ~~finding that the DWR contracts being assumed are just and reasonable; and~~

~~The CPUC has acted to ensure full and timely recovery in the Utility's retail electricity rates of all contract costs without further review.~~

~~Under the proposed CPUC settlement agreement in the Utility's~~petition for reorganization under Chapter 11 ~~proceeding, the CPUC retains,~~ and ~~after any assignment or assumption of DWR contracts, the CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.~~

~~Electricity Procurement~~

~~In October 2002, the CPUC issued a decision ordering the Utility to resume full procurement of electricity for its residual net open position~~ on January 1, 2003, and to file short- and long-term procurement plans. On January 1, 2003, the Utility, along with the other California IOUs, also became responsible for scheduling and dispatch of the quantities subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. In December 2002, the CPUC adopted a 2003 interim procurement plan for the Utility. The CPUC also authorized the California IOUs to extend their planning into the first quarter of 2004 and directed the Utility to hedge its 2004 first quarter residual net open position with transactions entered into in 2003.

~~The Utility filed its long-term procurement plan (long-term plan), covering the next 20 years, on April~~ 15, 2003. The Utility filed its short-term procurement plan covering 2004 in May 2003. The Utility expects that the CPUC will issue final decisions on both the Utility's long-term procurement plan and its short-term procurement plan in December 2003. In August 2003, the CPUC authorized the Utility to procure up to 50 percent of its non-baseload 2004 short-term procurement needs pending approval of the short-term procurement plan. The Utility conducted a competitive solicitation and submitted its selection criteria to the CPUC for approval.

Under AB 1X, the CPUC has no authority to review the reasonableness of procurement costs in the DWR's contracts, although the Utility's administration of the DWR allocated contracts and the Utility's dispatch of the electricity associated with the DWR allocated contracts may be subject to CPUC review. Under decisions entered in December 2002 and June 2003, the CPUC established a maximum annual procurement disallowance for administration of DWR contracts and least-cost dispatch equal to $36 million. Activities excluded from the disallowance cap include gas procurement activities in support of new Utility contracts, retained generation resources, QF contracts, and certain retained generation expenses. This maximum disallowance amount is subject to audit for the Utility's adopted annual administrative costs of managing procurement activities in the 2003 GRC. The Utility can provide no assurance that the CPUC will not increase or eliminate this maximum annual procurement disallowance in the future.

A central feature of the SB 1976 regulatory framework is its direction to the CPUC to create new electricity procurement balancing accounts to track and allow recovery of the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC must review the revenues and costs associated with an IOU's electricity procurement plan at least semi-annually and adjust rates or order refunds, as appropriate, to properly amortize the balancing accounts. The CPUC must establish the schedule for amortizing the over-collections or under-collections in the electricity procurement balancing accounts so that the aggregate over-collections or under-collections reflected in the accounts do not exceed 5 percent of the IOU's actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. Mandatory semi-annual review and adjustment of the balancing accounts will continue until January 1, 2006. Thereafter, the CPUC is required to condu ct electricity procurement balancing account reviews and adjust retail ratemaking amortization schedules for the balancing accounts as the CPUC deems appropriate and in a manner consistent with the requirements of SB 1976 for timely recovery of electricity procurement costs.

Effective January 1, 2003, the Utility established the Energy Resource Recovery Account (ERRA) to record and recover electricity costs, excluding the DWR's electricity contract costs, associated with the Utility's authorized procurement plan. (The ERRA also excludes the above-market portion of QF and power purchase agreement costs.) In February 2003, the Utility filed ~~its 2003 ERRA forecast application requesting that~~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 on this issue, what the FERC's decision will be, and the amount of any refunds, which may be impacted by Miran t's Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.

REGULATORY MATTERS

The Utility is regulated primarily by the CPUC ~~reset~~and the ~~Utility's 2003 ERRA revenue requirement to $1.4 billion and~~FERC. The FERC is an independent agency within the U.S. Department of Energy, or DOE, that, among other things, regulates the ERRA trigger threshold of $224 million be adopted. (The Utility is authorized to file an application to change retail electricity rates when it reaches the trigger threshold, i.e., when the Utility's forecasts indicate that it will face an under-collectiontransmission of electricity ~~procurement costs in excess of 5 percent of its prior year's generation and procurement revenues, excluding amounts collected for the DWR.) In August 2003, the Utility~~ and the ~~CPUC's Office~~sale for resale of ~~Ratepayer Advocates (ORA) proposed a stipulation to an Administrative Law Judge (ALJ) and the CPUC that would reduce the Utility's 2003 ERRA revenue requirement by $40 million to $1.37 billion.~~electricity in interstate commerce. The CPUC ~~issued a decision adopting~~has jurisdiction to, among other things, set the ~~stipulation in October 2003.~~

~~In August 2003, the Utility filed an application requesting that the CPUC approve the Utility's 2004 ERRA forecast revenue requirement~~rates, terms and conditions of $1.5 billion associated with the Utility's 2004 short-term procurement plan and approve as reasonable the Utility's ERRA recorded costs for the period from January 2003 through May 2003. The CPUC's review of the Utility's procurement activities will examine the Utility's least-cost dispatch of the resource portfolio, fuel expensesservice for the Utility's electricity generation, ~~contract administration, including administration~~procurement and distribution, natural gas distribution and natural gas transportation and storage services in California.

Transition from Frozen Rates to Cost of ~~the DWR allocated contracts, the Utility's existing QF contracts and other power purchase agreements, renewable energy contracts, and the decision~~Service Ratemaking

Frozen electricity rates, which began on January 1, 1998, were designed to engage in market transactions in the context of the Utility's overall prudent contract administration and least-cost dispatch of generation resources. The Utility has also asked the CPUC to approve its proposed revenue requirement of $840 million to recover the 2004 costs related to the above-market g eneration and procurement costs and certain other generation-related costs.

In June 2003, the CPUC issued a decision pursuant to SB 1078 that adopts the framework for implementing a Renewable Portfolio Standard (RPS) program. The decision requires the Utility to increase procurement of renewable energy by at least 1 percent of its retail sales per year. By the end of 2017, the Utility must be procuring at least 20 percent of its total electricity from renewable resources. Under SB 1078, the Utility was not obligated to purchase additional renewable energy until it received an investment grade credit rating. However, under subsequently enacted SB 67, the Utility may be required to purchase additional renewable energy once it is able to do so on reasonable terms and the renewable energy contracts will not impair the restoration of its creditworthiness. Until that time, the Utility will accumulate an annual procurement target (APT) based on 1 percent of annual retail sales. When the Utility receives an investment grade credit rating or the CPUC determines that the SB 67 requir ements are satisfied, the Utility expects to enter into purchase contracts for renewable energy to meet its accumulated APT.

Although the Utility cannot predict what the terms, including price, of such contracts would be, the decision requires that the procurement price under such contracts to be at or below a market price benchmark established by the CPUC after the bids have been received. If the Utility exceeds its APT, it can apply the excess to meet the APT in future years. For under-procurement, the decision allows IOUs to carry over an annual deficit of 25 percent to the next three years without explanation. Failure to meet minimum APTs without prior CPUC approval would result in an automatic penalty of $0.05 per kWh, subject to an annual penalty cap of $25 million. The Utility currently estimates that the annual 1 percent increase in renewable resource electricity in its portfolio will initially require between 80 and 100 megawatts (MW) of additional renewable capacity to be added per year.

The CPUC approved offers the Utility submitted that were sufficient to meet the Utility's 2003 renewable energy requirement in December 2002. In September 2003, the Utility submitted to the CPUC for approval several renewable contracts pursuant to an assigned commissioner ruling in August 2003 that permitted bilateral negotiations with renewable suppliers prior to the implementation of renewable energy portfolio standard requirements. The CPUC approved the contracts in October 2003.

~~2001 Annual Transition Cost Proceeding: Review of Reasonableness of Electricity Procurement~~

In April 2003, the ORA issued a report regarding the Utility's procurement activities for the period July 1, 2000, through June 30, 2001, recommending that the CPUC disallow recovery of $434 million of the Utility's procurement costs based on an allegation that the Utility's market purchases during the period were imprudent due to a failure to develop and execute a reasonable hedging strategy. The ORA recommendation does not take into account any FERC-ordered refunds of the Utility's procurement costs during this period, which refunds could effectively reduce the amount of the recommended disallowance. In the Utility's response to the ORA's report, the Utility indicated that the ORA recommendation is unlawful, contrary to prior CPUC decisions, and factually unsupported. Subsequently, the procedural schedule in this proceeding was suspended, pending the outcome of the proposed settlement agreement in the Utility's Chapter 11 proceeding.

Under the proposed CPUC settlement agreement, the CPUC would agree to act promptly to resolve this proceeding, with no adverse impact on the Utility's cost recovery, as soon as practicable after the Settlement Plan becomes effective.

~~Retained Generation Revenue Requirement~~

~~In April 2002, the CPUC issued a decision authorizing~~allow the Utility to recover ~~reasonable~~its authorized utility costs ~~incurred~~and to the extent frozen rates generated revenues in ~~2002 for its own retained electric generation, subject~~excess of these costs, to ~~reasonableness review~~recover the Utility's costs of transitioning to a competitive market. Although the surcharges implemented in 2001 effectively increased the actual rate under the frozen rate structure, increases in the Utility's ~~2003 GRC or other proceedings. In May 2003, the CPUC issued a resolution approving~~authorized costs and revenue requirements did not increase the Utility's ~~proposed tariff revisions and its request to establish various balancing and memorandum accounts with modifications in compliance with the CPUC's April 2002 decision.~~

revenues. In July 2003, the Utility reached an agreement (the "generation settlement agreement") with various intervenors that would set a 2003 generation revenue requirement of $955 million and filed a motion for approval with the CPUC. This generation revenue requirement excludes fuel expense, the cost of electricity purchases, theaddition, DWR revenue requirements ~~and nuclear decommissioning revenue requirements. If approved by~~reduced the ~~CPUC,~~Utility's revenues under the ~~generation settlement agreement would resolve all generation-specific issues, but would not resolve various tax methodology issues or the amount~~frozen rate structure. As a result of ~~administrative and general expenses and common plant to allocate to generation.~~

~~The "2003 GRC settlement agreement"~~revised electricity rates discussed below ~~would resolve these remaining issues. If the generation settlement agreement~~ and ~~the 2003 GRC settlement agreement are approved by the~~a January 2004 CPUC the Utility's revenue requirement for its electricity generation operations would be set at $912 million for 2003, an increase of $38 million over the currently authorized amount. In addition, the 2003 GRC settlement agreement provides for a new balancing account, effective January 1, 2004, to ensuredecision determining that the ~~Utility recovers its authorized electricity generation revenue requirement regardless of the level of sales.~~

In addition to the two settlement agreements discussed above, under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the Utility's adopted 2003 retained generation rate base of $1.6 billion would be deemed just and reasonable by the CPUC and not subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of the Utility's electricity generation rate base would allow recognition of an after-tax regulatory asset of approximately $0.8 billion (or $1.3 billion pre-tax).

~~Direct Access Suspension and Cost Responsibility Surcharge~~

Until September 2001, California utility customers could choose to buy their electricity from the utility (bundled customers) or from an alternative power supplier through "direct access" service. Direct access customers receive distribution and transmission service from the utility, but purchase electricity (generation) from their alternative provider. In September 2001, the CPUC, pursuant to AB 1X, suspended the right of retail end-use customers to choose direct access service, thereby preventing additional customers from entering into contracts to purchase electricity from alternative providers. Customers that entered into direct access contracts on or before September 20, 2001, were permitted to remain on direct access.

In a November 2002 decision, the CPUC established a cost responsibility surcharge (CRS) mechanism to implement utility-specific non-bypassable charges on direct access customers for their shares of the bond costs and electricity costs incurred by the DWR and the above-market cost related to the Utility's generation resources and electricity purchase contracts. The November 2002 decision imposed a cap on the CRS of $0.027 per kWh. The Utility implemented this capped surcharge on January 1, 2003. A July 2003 decision ordered that the CRS funds be applied to recover (in the following order) the DWR bond charges, the Utility's ongoing above-market costs related to its generation resources and electricity purchase contracts, and the DWR power charges.

The July 2003 decision found that, subject to prospective adjustment in the annual DWR revenue requirement proceeding, the CRS cap of $0.027 per kWh, plus interest on the direct access CRS under-collection, will be sufficient to repay any shortfall to customers who receive bundled service by the time the DWR allocated contracts terminate. The CPUC has also held in April and July 2003 decisions that certain customers reducing or terminating the Utility's electricity service after February 2001 should be responsible for payment of the CRS, subject to specific exemptions.

To the extent the CRS cap results in an under-collection of DWR charges, the Utility would have to remit the shortfall to the DWR from bundled customers' funds. Since DWR pass-through revenues are determined based upon a fixed revenue requirement, to the extent that the Utility remits additional CRS amounts to the DWR, those remittances reduce the amount of revenues it must pass through for bundled customers. The Utility expects to collect approximately $110 million per year more in 2003 than in 2002 from direct access customers due to the CRS.

The Utility does not expect that the CPUC's implementation of this decision or the level of the CRS cap as detailed above to have a material adverse effect on its results of operations or financial condition.

~~Community Choice Aggregators~~

In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, the Utility would continue to provide distribution, metering, and billing services to the community choice aggregators' customers and be those customers' provider of electricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator would pay an appropriate share of DWR costs and certain of that utility's costs that are fixed and unavoidable.

~~One-Cent, Three-Cent, and Half-Cent Surcharge Revenues~~

In January 2001, the CPUC increased electric rates by $0.01 per kWh, in March 2001 by another $0.03 per kWh, and in May 2001 by an additional $0.005 per kWh. The use of these surcharge revenues was restricted to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. Based on these decisions and an agreement between the CPUC and SCE, in which SCE was allowed to use its $0.005 per kWh surcharge to offset its DWR revenue requirement, the Utility has continued to recognize revenues related to the $0.01 per kWh, $0.03 per kWh, and $0.005 per kWh surcharges after the statutory end of the retail electric rate freeze, which was March 31, 2002, even without considering the proposed CPUC settlement agreement in the Utility's Chapter 11 proceed ing. (See further discussion in Note 2 of the Notes to the Consolidated Financial Statements.) As such, the Utility has not recorded a regulatory liability or a reserve for the potential refund of these surcharge revenues, or any portion thereof, as of September 30, 2003. From January 2001 to September 30, 2003, the Utility recognized total surcharge revenues of approximately $7.5 billion, pre-tax.

~~In July 2003, a CPUC Commissioner issued a proposed decision finding that the retail electric~~ rate freeze ended on January 18, 2001. The proposed decision also provides that the CPUC would determine in a separate proceeding the extent and disposition of costs previously defined as uneconomic, transition, or stranded. The proposed decision contemplates that the separate proceeding would also determine whether the recovery of these costs has been fully addressed or resolved in2001, effective January 1, 2004, the Utility's ~~Chapter 11 proceeding or~~rates are intended to reflect cost of service whereby the Utility's rates are based on the sum of individual components. Chang es in ~~other CPUC proceedings. The Utility has filed comments suggesting that~~any individual revenue requirement will change customers' electricity rates.

In February 2004, the CPUC defer its decision on these issues pending the CPUC's consideration of the proposed CPUC settlement agreement and the implementation of the Settlement Plan. The Utility cannot predict the ultimate outcome of this proceeding.

~~In August 2003, the California Supreme Court~~ issued a decision approving a rate design settlement to implement an annual electricity rate reduction of approximately $799 million. Because the Utility's customers' bills did not reflect the rate reduction until March 1, 2004, the Utility will return to customers an estimated $100 million of revenues received during January and February in excess of those revenues that would have been charged had the rate reduction been implemented on ~~questions certified to it~~January 1, 2004. The Utility accrued $100 million at March 31, 2004 for this refund obligation. However, the revised rates approved by the ~~U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) regarding the validity of a settlement agreement between~~CPUC are based on forecast revenue requirements. Ultimately, rates will be adjusted to collect authorized revenue requirements approved by the CPUC and ~~SCE. The decision concluded that~~ the ~~CPUC had the authority to enter into a settlement agreement with SCE that allowed SCE to recover under-collected purchased power and generation-related transition costs beyond the end~~FERC in various pending proceedings regardless of the forecast revenue requirements used to set rates approved in February, the refund discussed above, or the rate ~~freeze in light of the provisions of AB 1890, which prohibited post-freeze recovery of transition~~levels charged. These pending proceedings are discussed below and procurement costs, and that the settlement agreement did not violate California law. This matter has now been returned to the Ninth Circuit for final disposition. In October 2003, the California Supreme Court denied a petition for rehearing of its decision that had been filed by The Utility Reform Network (TURN).include:

The Utility's ability to retain its surcharge revenues may be adversely affected if the proposed CPUC settlement agreement and Settlement Plan are not implemented or if, either in response to certain judicial decisions or on its own initiative, the CPUC changes its interpretation of law or otherwise seeks to change the Utility's overall retail electric rates retroactively. (See further discussion in "Surcharge Revenues" in Note 6 of the Notes to the Consolidated Financial Statements.)

·	The Utility's 2003 GRC and 2004 attrition adjustment request;
·	The Utility's cost of capital application;
·	Electric transmission rate cases;
·	Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement;
·	The calculation of any over-collection of the surcharge revenues for 2003; and
·	The allocation of the DWR's 2004 revenue requirements. Because the Utility is on cost-of-service ratemaking and because amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues, changes in the DWR's revenue requirements are not expected to have a material impact on the Utility's results of operations.

Under the proposed CPUC settlement agreement, the CPUC would acknowledge and would agree that the revenues related to the surcharges described above are the property of the Utility's Chapter 11 estate and are not subject to refund. If the proposed CPUC settlement agreement is not approved and the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially adversely affected.

2003 General Rate Case

In On April 6, 2004, a proposed decision was issued in the Utility's 2003 GRC pending at the ~~CPUC will determine~~CPUC. The 2003 GRC determines the amount of authorized base revenues the Utility can collect from ~~ratepayers~~customers to recover its basic business and operational costs for electricity and natural gas distribution operations and ~~electric distribution~~for electricity generation operations for 2003 and succeeding years. AsThe administrative law judge's, or ALJ's, proposed decision, excluding changes in attrition rate adjustments discussed ~~above under "Retained Generation Revenue Requirement,"~~below, would approve essentially all of the ~~CPUC will also determine~~provisions contained in ~~this~~the July 2003 ~~GRC the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business~~ and ~~operational costs for the Utility's retained generation.~~

In September 2003 settlement agreements reached among the Utility and various ~~intervenors (TURN,~~consumer groups to set the ~~CPUC's ORA, Aglet Consumer Alliance,~~Utility's 2003 revenue requirements for its electricity generation and electricity and natural gas distribution operations.

If the ~~Modesto Irrigation District, the Natural Resources Defense Council, and the Agricultural Energy Consumers Association) filed a joint motion with~~proposed decision is adopted by the CPUC, ~~seeking approval~~the Utility's total 2003 revenue requirements, as provided in the settlement agreements, would be set at approximately:

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

In 2003, the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure. The amount of electricity revenue subject to refund pursuant to the rate design settlement ~~agreement these parties entered into~~in 2003 was $123 million, which incorporated the impact of the electric portion of the GRC settlement. The Utility has recorded a regulatory liability for the refund obligation. If the 2003 revenue requirement that is ultimately approved in the Utility's 2003 GRC ~~proceeding (2003~~is lower than the amounts described above, the regulatory liability would increase. In 2004, the Utility began recording its base revenue requirements under a cost of service ratemaking structure. In the first quarter of 2004, the Utility collected less than its currently authorized base revenue requirements as approved in its 1999 GRC ~~settlement agreement), also filed with~~and 2001 attrition filings. The Utility has recorded the ~~CPUC.~~difference between its current base revenue requirement a nd the amount it has collected through cost of service rates in newly established electricity balancing accounts. The ~~parties reached agreement on all disputed economic issues related to~~Utility has not included the impact of the electricity ~~and natural gas~~ distribution revenue requirement increases in its results of operations for the ~~2003 GRC, with the exception~~first quarter of ~~the Utility's request that~~2004. If the CPUC ~~include the costs of~~approves a ~~pension contribution~~revenue requirement increase in the Utility's revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, based upon briefs submitted on September 17, 2003, and reply briefs submitted on October 8, 2003, in its final decision and the Utility's GRC revenue requirements will be adjusted ap propriately.

~~The 2003 GRC settlement agreement proposes that~~2004, the Utility would ~~receive a total 2003 revenue requirement of approximately $2.5 billion for electric distribution operations, representing a $236 million~~record the increase in the ~~Utility's electric distribution revenue requirements over~~results of operations for 2004.

The proposed decision is scheduled to be considered by the ~~current authorized amount. The settlement agreement provides that~~CPUC on May 6, 2004. A final decision is expected in the ~~amount~~second quarter of ~~electricity distribution rate base on which~~2004. If the proposed decision is approved as written in the second quarter, the Utility would ~~be entitled~~record regulatory assets and liabilities associated with the revenue requirement increases (including attrition), recovery of unfunded taxes, depreciation, and decommissioning. The net impact of these items is anticipated to ~~earn~~result in pre-tax earnings of approximately $400 million.

Also, on April 6, 2004, the CPUC issued a separate proposed decision to address an ~~authorized rate of return would be $7.7 billion, based on recorded 2002 plant and including net weighted average capital additions for 2003 of $292 million. The 2003 GRC settlement~~ agreement ~~also provides that~~between the Utility ~~will implement a new balancing account, effective January 1, 2004,~~and the CPUC's Office of Ratepayer Advocates, or ORA, relating to ~~ensure that the Utility recovers its authorized electric distribution revenue requirements regardless of the level of sales.~~

~~The 2003 GRC settlement agreement also would result in a total 2003 revenue requirement of approximately $927 million for~~ the Utility's natural gas distribution operations, representing a $52 million increase in the Utility's natural gas distribution revenue requirement over the current authorized amount. The settlement agreement also provides that the amount of natural gas distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be $2.1 billion, based on recorded 2002 plant, and including weighted average capital additions for 2003 of approximately $89 million.

~~The parties have agreed that the Utility's next GRC will be to determine rates for test year 2007.~~

Attrition Rate Adjustments for ~~2004 - 2006~~2004-2006

The ~~Utility may receive annual increases~~July 2003 and September 2003 settlement agreements in the Utility's 2003 GRC, as discussed above, provide for yearly adjustments to the Utility's base revenues, ~~established during the test year of a GRC, known as~~or attrition rate ~~adjustments (ARAs), for~~adjustments. On April 6, 2004, a proposed decision was issued in the ~~years between GRCs to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. Under the generation settlement agreement and the~~Utility's 2003 GRC, pending at the CPUC. The proposed decision would approve the terms of the settlement ~~agreement,~~agreements that provide for an attrition ~~revenue increases~~adjustment in 2004, 2005 and 2006 based on changes in the CPI, except the ALJ recommends that the settlement agreements be modified to delete the provision for ~~electric~~a minimum attrition adjustment amount in each year.

The proposed minimum attrition adjustments for electricity and natural gas distribution ~~and electric generation operations~~revenue requirements for 2004, 2005 and 2006 are 2.00%, 2.25% and 3.00%, respectively. The proposed minimum attrition adjustments for electricity generation revenue requirements for 2004, 2005 and 2006 are 1.50%, 1.50% and 2.50%, respectively. If the proposed decision is adopted, the aggregate attrition adjustment for 2004 would be ~~authorized in~~approximately $61 million based on the 2003 GRC. The attrition increase for 2004 and 2005 would be calculated as the prior year's revenue requirement multiplied by the change in the Consumer Price Index (CPI). To calculate the attrition increase for 2006, the 2005 revenue requirement would be multiplied by theactual change in the CPI ~~plus 1.0 percent. The generation attrition revenue requirement~~of 1.4%. This would ~~also include additional revenues~~reflect a reduction of approximately $21 million compared to ~~cover the costs of refueling activities at~~ the Utility's November 2003 and January 2004 combined attrition requests for approximately $82 million (excluding a $32 million allowance for a second refueling outage in 2004 at Diablo Canyon ~~Power Plan t. For electric~~nuclear power plant and ~~natural gas distribution operations,~~$13 million for public purpose program expenses) based on the proposed minimum attrition increases would be subject to a minimum increase of 2.0 percent and a maximum increase of 3.0 percent for 2004, a minimum increase of 2.25 percent and a maximum increase of 3.25 percent for 2005, and a minimum increase of 3.0 percent and a maximum increase of 4.0 percent for 2006. For electric generation operations,adjustments in the attrition increases would be subject to a minimum increase of 1.5 percent and a maximum increase of 3.0 percent for 2004 and 2005, and a minimum increase of 2.5 percent and a maximum increase of 4.0 percent for 2006. The GRC settlement agreement notes that outcomes in future cost of capital proceedings, in which the CPUC determines the authorized rate of return that the Utility may earn on its electric and gas distribution and electric generation assets, could affect the Utility's revenue requirement, including the attrition adjustments.

~~2002 Attrition Rate Adjustment Request~~

In April 2003, the Utility filed an application for rehearing of the CPUC's March 2003 decision, which denied the Utility's request for a $76.7 million increase to its annual electric distribution revenue requirement and a $19.5 million increase to its annual gas distribution revenue requirement for 2002. In the filing, the Utility contends that the CPUC's denial of attrition relief was in error because the decision applied the wrong legal standard and because its findings were not supported by substantial evidence. In October 2003, the CPUC issued a final decision denying the Utility's application for rehearing.agreements.

Cost of Capital Proceedings

Each year the Utility ~~files~~must file an application with the CPUC to determine the Utility's authorized capital structure and the authorized rate of return the Utility may earn on its ~~electric~~electricity and natural gas distribution, natural gas transmission and ~~electric~~storage, and electricity generation assets.

For its ~~gas~~electricity and ~~electric~~natural gas distribution operations, natural gas transmission and ~~electric~~storage, and electricity generation operations, the Utility's currently authorized ~~ROE~~return on equity is ~~11.22 percent~~11.22% and its currently authorized cost of debt is ~~7.57 percent.~~7.57%. The ~~Utility also has a~~Utility's currently authorized capital structure ~~of 48.00 percent~~is 48.00% common equity, ~~46.20 percent~~46.20% long-term debt and ~~5.80 percent~~5.80% preferred equity.

The ~~November 2002 decision in the Utility's 2003 Cost of Capital proceeding adopted these authorized figures but held the case open to address the effect~~Settlement Agreement provides that ~~implementing and financing a confirmed plan of reorganization would have on the Utility's ROE, costs of debt and preferred stock, and ratemaking capital structure. Subsequently, in February 2003,~~from January 1, 2004 until Moody's has issued an issuer rating for the Utility ~~filed~~of not less than A3 or S&P has issued a ~~petition to modify the November 2002 decision to waive the normal requirement that~~long-term issuer credit rating for the Utility ~~file a test year 2004 cost~~ of ~~capital application. In May 2003, the CPUC granted the Utility's request, exempting the Utility from filing a test year 2004 cost of capital application.~~

~~The proposed CPUC settlement agreement provides that~~not less than A-, the Utility's authorized ~~ROE would~~return on equity will be no less than ~~11.22 percent~~11.22% per year and ~~the Utility's~~its authorized equity ratio ~~for ratemaking purposes would~~will be no less than ~~52 percent, except that,~~52%. However, for 2004 and 2005, the Utility's authorized equity ratio ~~would~~will equal the greater of the proportion of equity approved in the ~~forecast of the~~ Utility's ~~average capital structure for calendar years~~ 2004 and 2005 ~~filed in the Utility's~~ cost of capital proceedings and ~~48.6 percent.~~48.6%.

The Utility's cost of capital application must be filed by May 12, 2004.In this filing, the Utility plans to propose a true-up cost of capital for 2004 that reflects the Utility's new, post-Chapter 11 financing costs and its updated capital structure. In its application, the Utility will seek recovery in rates of its (1) actual cost of capital 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 2004, this cost of capital proceeding will also determine the authorized rate of return for natural gas transportation and storage. For test year 2005, the Utility will request authorization for its cost of common equity, preferred equity and long-term debt and for its capital structure based on forecasts for 2005. The Utility expects that its application will include a forecasted common equity ratio of approximately 49% for 2004.

DWR Revenue Requirements

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 the CPUC in September 2003. In January 2004, the CPUC issued a decision that adopted an interim allocation of the DWR's proposed 2004 revenue requirements among the three California investor-owned electric utilities' customers. The Utility customers' share 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 kilowatt-hour, or kWh, basis, which resulted in approximately $369 million being allocated to the Utility's customers. SCE has filed a petition to modify the CPUC's approa ch for allocating the DWR's bond charges, requesting that more be allocated to the Utility's customers. On April 16, 2004, the assigned ALJ for the proceeding issued a draft decision that would deny SCE's petition. On April 22, 2004, a CPUC commissioner issued an alternate draft decision that would grant SCE's petition on a prospective basis, allocating more of the DWR's bond charges to the Utility. If this alternate draft decision is approved by the CPUC, the bond charges allocated to the Utility's customers would be increased by approximately $50 million per year for the life of the bonds (through 2020). If approved, however, this is not expected to have an impact on the Utility's results of operations because the Utility is on cost-of-service ratemaking and because amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. The CPUC has not yet acted on this matter.

The CPUC is considering adopting a multi-year allocation of the DWR's power charge revenue requirements in a second phase of the 2004 DWR power charge proceeding. If adopted, a multi-year allocation would replace the interim allocation for 2004. In April 2004, the Utility filed with the CPUC a settlement agreement reached with SCE and TURN on the allocation of the DWR's power charge revenue requirement for 2004 and beyond. The Utility cannot predict the final outcome of this matter.

In April 2004, the DWR submitted the Supplemental Determination of its 2004 revenue requirements to the CPUC for allocation among the three California investor-owned utilities. The Supplemental Determination would reduce 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.

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, including the reduction in the 2004 revenue requirement related to 2001 through 2002, will not affect the Utility's results of operations.

Baseline Proceeding

In May 2002, the CPUC ordered California investor-owned electric utilities to increase baseline allowances for certain residential customers, reducing the Utility's electricity revenues. A customer's baseline allowance is the amount of monthly usage that is billed at the lowest rate and is exempt from certain surcharges. The new balancing account structure approved by the CPUC on April 1, 2004, retroactive to January 1, 2004, provides for full recovery of the Utility's revenue requirements. Therefore, the Utility does not expect that the baseline program revisions will affect the Utility's results of operations.

Electricity Procurement

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 recorded procurement revenues 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 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. These mandatory adjustments will continue until January 1, 2006. The CPUC's review of the Utility's procure ment activities will examine 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. At March 31, 2004, the Utility's ERRA had an over-collected balance of $2.3 million.

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. In its decision approving the Util ity's 2004 short-term procurement plan, the CPUC extended the application of this maximum disallowance amount to cover the Utility's 2004 procurement activities. It is uncertain whether the CPUC will modify or eliminate the maximum annual disallowance for future years.

In April 2004, the ORA issued its reasonableness review report of the Utility's ERRA covering the period from January 1, 2003 through May 31, 2003. Although the ORA did not specifically recommend any disallowances, the ORA does ask the Utility to provide additional information in future ERRA filings. Additionally, the report indicates that an audit of ERRA entries was not performed but that the ORA intends to perform a full financial audit of the Utility's procurement activities in future ERRA proceedings. The Utility cannot predict whether a disallowance will occur based on information reviewed or audited by the ORA in future ERRA filings or the size of any potential disallowance.

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.

Finally, the California Governor has called upon the CPUC to revisit its January 2004 interim decision establishing the long-term regulatory framework under which the California investor-owned electric utilities are required to plan for and procure energy resources. Among other requirements, the decision requires the utilities to achieve an electricity reserve margin of 15% to 17% in excess of peak capacity electricity requirements by January 1, 2008. The California Governor has requested that the CPUC accelerate the phase-in of the planning reserve requirement to 2006. The planning reserve requirement will increase the Utility's residual net open position. The Governor also 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 Governor's recommendations will be considered by the CPUC in its pending electricity procurement and other proceedings implementing AB 57. The Utility is unable to predict whether the CPUC will adopt the Governor's recommendations, but it is possible that the recommendations if adopted could have a material impact on the Utility's future operations or costs of service.

FERC Prospective Price Mitigation Relief

Various ~~parties,~~entities, including the Utility and the ~~State~~state of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity ~~purchasers.~~purchasers from January 2000 to June 2001. In December 2002, a FERC ALJ issued an initial decision finding that power suppliers overcharged the utilities, the ~~State~~state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

~~In March~~ During 2003, the FERC confirmed most of the ALJ's findings, 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 ~~October 2003,~~addition, the FERC ~~issued a decision confirming the modified refund methodology set forth in the March 2003 order and~~ directed the ISO and the Power Exchange, ~~(PX)~~or PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ~~modified refund methodology included use of a new gas price methodology as the basis for mitigated prices and directed~~ISO has indicated that it plans to make its compliance filing by November 2004. The PX cannot make its compliance filing until after the ISO ~~and the PX to make compliance filings establishing refund amounts by March 2004.~~makes its filing. The actual refunds will not be determined until the FERC issues a final decision, following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding, after which appellate review is ~~expected in the first half of 2004.~~expected. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, ~~Amendment 51 proceeding.~~which incorporates revised data provided by the Utility and other entities. The ~~Amendment 51 proceeding is~~FERC has indicated that it does not have the power to direct refunds for the period before October 2, 2000, but has engaged in an ~~ISO~~investigation of market manipulation and sought through settlement or hearings disgorgement of profits for any tariff ~~amendment that proposes certain adjustments~~violations during this period. Unless settled among the various entities, this conclusion will also be subject to ISO data and treatment of ISO charges to permit calc ulation of FERC refunds from a database that the ISO considers appropriate for such calculations. A decision in this proceeding is expected in November 2003.judicial review.

Under the ~~proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding,~~Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the ~~State~~state of California in seeking refunds from generators and other energy suppliers. ~~Refunds,~~The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility's ~~electricity purchase~~ISO, PX, qualifying facilities or energy service provider costs ~~once tax effected,~~that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding will reduce the ~~$2.21 billion after-tax regulatory asset created by~~balance of the ~~proposed CPUC settlement agreement.~~Settlement Regulatory Asset.

The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 ~~case~~proceeding as ~~Liabilities Subject~~liabilities subject to ~~Compromise.~~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 ~~these~~the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the ALJ's initial ~~decision.~~decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The ~~recent~~ recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could ~~result in a reduction of several hundred million dollars in~~further redu ce the amount of the suppliers' ~~claims. This~~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 ~~provide evidence~~demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund ~~methodology and are acceptable to the FERC in future FERC decisions.~~

On June 25, 2003, the FERC issued a series of orders directing more than 40 companies to show cause why they should not disgorge profits for a variety of violations of the ISO and PX tariffs related to market manipulation during the summer of 2000. The Utility was named as one of the companies in these orders. The Utility has shown that some transactions were misidentified and do not relate to it, and that other identified transactions did not constitute improper behavior, but rather justifiable transactions under the operational circumstances. On October 30, 2003, the FERC staff filed a motion to dismiss the Utility from this proceeding. The Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations.

In June 2003, the FERC also began an investigation of why companies should not disgorge profits related to electricity bids in violation of ISO and PX tariffs during the period from May 1 to October 1, 2000. The Utility submitted information explaining its bidding, which was designed to ensure optimal dispatch of its resources, including when and at what level it operated its hydroelectric generating facilities. Since the Utility was a net purchaser of electricity during this period, the Utility expects that the amount it would be required to pay, if any, would be offset by the refunds it would receive from other companies. Assuming the Utility receives refunds from other companies, the Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations. This proceeding is being conducted as a FERC staff investigation and results are not expected until the first half of 2004. However, some cases may be resolved by settlements and one s ettlement proposed by the FERC staff with a seller has proposed payments of up to $25 million and additional compensation in the form of options to purchase rights to generation.

~~FERC Transmission Rate Cases~~

On January 13, 2003, the Utility filed an application with the FERC requesting authority to recover $545 million in electric transmission retail rates annually, an increase of $166 million over the revenue requirement then in effect. The requested increase is mainly attributable to significant capital additions and replacements made to the Utility's system to accommodate load growth, maintain the infrastructure, and ensure safe and reliable service. In addition, the request includes a 15-year useful life for transmission plant coming into service in 2003 and a ROE of 13.5 percent. The January 13, 2003 proposed rates went into effect, subject to refund, on August 13, 2003.

The Utility filed an additional rate application with the FERC at the end of October 2003 requesting recovery of $530 million per year, subject to refund, in electric transmission retail rates, a slight decrease from rates currently in effect. The filing requests a 13.0 percent ROE and seeks recovery of the Utility's costs of providing safe and reliable transmission service during 2004.methodology.

El Paso Settlement

In June 2003, the Utility, along with SCE, the state of California and a number of other parties, entered into the El Paso settlement, 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 ~~period from September 1996 to March 2003.~~California energy crisis. Under the El Paso ~~settlement's terms,~~settlement, El Paso will pay $1.5 billion in cash and non-cash ~~consideration. Of that total,~~consideration, of which approximately ~~$352~~$550 million ~~will be paid up front, another approximately $227 million (depending on the proceeds) will be paid from the sale of El Paso stock~~is now in an escrow account and approximately $875 million will be paid over 15 to 20 years.El Paso also agreed to aan approximately $125 million reduction in El Paso's long-term electricity supply ~~contracts~~contract with the DWR, to provide pipeline capacity to California and to ensure specific reserve capacity for the Utility, if needed. The exact amounts allocated to each entity are detailed in a master settlement agreement and delineated in an alloca tion agreement. DWR.In October 2003, the CPUC ~~issued a decision to complete the final~~approved an allocation of these refunds, under which the Utility's natural gas ~~ratepayer~~customers would receive ~~approximately $75~~appr oximately $80 million and its electricity ~~ratepayers~~customers would receive approximately ~~$210~~$216 million. The ~~agreement is now pending approval by the FERC and the San Diego County Superior Court.~~

~~It is uncertain whether or when these required approvals will be obtained. The proposed CPUC settlement agreement provides that the~~ net after-tax amount of any consideration that the Utility actually ~~realizes~~receives in cash related to the electricity refunds ~~(but not the natural gas refunds) would~~will reduce the ~~new $2.21 billion after-tax regulatory asset if consistent with CPUC rules~~outstanding balance of the Settlement Regulatory Asset. The settlement was approved by the FERC in November 2003, and ~~orders.~~by the San Diego Superior Court in December 2003. An appeal of the attorney's fees award to class action plaintiffs' counsel in the litigation is pending, but that appeal will not affect the effectiveness of the settlement. The Superior Court's approval of the settlement is now final and is no longer subject to appeal. The refunds will be released from the escrow account when the settlement becomes effective according to its terms. The Utility believes it is probable that all conditions precedent to the effectiveness of the settlement will be satisfied soon.

~~Gas Accord II~~Enron Settlement

~~In 1998,~~ On December 23, 2003, the Utility ~~implemented~~entered into a ~~ratemaking pact called~~settlement agreement with five subsidiaries of Enron Corporation, or Enron, settling certain claims between the ~~Gas Accord, under which~~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 Condensed Consolidated Financial Statements. As a result of the Enron Settlement, the Utility will receive an after-tax credit of approximately $114 million that will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. In the rate design settlement approved by the CPUC on February 26, 2004, the Utility's ~~natural~~revenue requirement related to the amortization of the Settlement Regulatory Asset has been reduced to reflect an esti mate of the after-tax credit included in the Enron Settlement. The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the net after-tax amounts actually received by the Utility under settlements with energy suppliers, including Enron.

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. In order for the settlement to become effective, it must first be approved by the CPUC as to SCE, and the FERC. If the Williams settlement is approved, the Utility will receive an after-tax credit of approximately $41 millionthat will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. Certain settlement issues are still being resolved and could impact the amount the Utility ultimately receives.The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements wit h energy suppliers, including The Williams Companies.

Dynegy Settlement

In April 2004, the Utility, along with SCE, San Diego Gas and 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. In order for this settlement to become effective, it must first be approved by the CPUC and the FERC. If the Dynegy 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 Prospective Price Mitigation Relief" above. The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements with energy suppliers, including Dynegy.

Natural Gas Supply and Transportation

On March 19, 2004, the Utility filed a gas transportation and storage ~~services were separated~~rate case application. This application proposes a $435 million revenue requirement for ~~ratemaking purposes~~2005, representing an approximately $1 million reduction from the 2004 revenue requirement. This application also proposes certain limited rate design changes, as well as eligibility requirements and resulting rates to implement the CPUC's adopted rate structure and fully recover its ~~distribution services.~~cost of providing local transmission service.

The Gas Accord established natural gas transportation rates through 2002 and natural gas storage rates through March 2003. In addition, the Gas Accord established an incentive mechanism whereby the Utility recovers its costs of purchasing natural gas for its residential and smaller commercial, or core, customers. Under the Gas Accord, the Utility is at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account ~~protection~~provisions for over-collections or under-collections of natural gas transportation or storage revenues.

In August 2002, the CPUC approved the Gas Accord settlement that provided for a one-year extension of the Utility's existing natural gas transportation rates and terms and conditions of service, as well as rules governing contract extensions and a contract solicitation period for new contracts. In January 2003, the Utility filed an amended Gas Accord II application with the CPUC proposing to permanently retain the Gas Accord market structure, extend the incentive mechanism for recovery of core procurement costs, and increase the Utility's rates for natural gas transportation service for 2004 and for storage service for the period from April 1, 2004, to March 31, 2005, by $55 million. Subsequently, the CPUC removed the cost of capital issues from this proceeding, resulting in a $25 million reduction in the Utility's revenue requirement request.

The amended Gas Accord II application proposed a rate increase for 2004, calculated on a demand or throughput forecast basis. In addition, for the 12-month period ending December 31, 2004, for transportation service, and for the 12-month period ending March 31, 2005, for storage service, the Utility proposes to provide an option for current holders of contract capacity to extend their rights and for a structured contract solicitation period to be held for any capacity that is not under contract. The Utility may experience a material reduction in operating revenues if ~~(1)~~throughput levels or market conditions are significantly less favorable than reflected in rates for these services.

System Safety and Reliability

Pursuant to California legislation, the Utility ~~were unable~~was granted base revenue increases for 1997 and 1998 to ~~renew or replace existing transportation contracts at the beginning or throughout the Gas Accord II period, (2)~~enhance its transmission and distribution system safety and reliability. In 1999, the Utility ~~were forced~~filed its application for review and approval of its expenditures related to ~~renew or replace~~these enhancements. In March 2004, a proposed decision was issued disallowing approximately $44.2 million in expenses and $24.0 million in capital for 1997 and 1998. The proposed decision would also remove storm-related expenses of $17.2 million and storm-related capital expenditures of $34.9 million for 1997 and 1998, and would require the Utility to file a new Catastrophic Event Memorandum Account application for recovery of those ~~contracts on less favorable terms than adopted by~~costs. The Utility filed comments opposing the ~~CPUC, or (3) overall demand for transportation and storage services were less than anticipated and reflected by the CPUC in rates. A CPUC~~proposed decision in ~~this proceeding is expected in December 2003. Until~~April 2004. PG&E Corporation and the ~~CPUC issues a decision,~~Utility do not expect that the ~~existing natural gas transportation and storage rates will continue in effect.~~

~~The Utility cannot predict what the~~final outcome of this ~~proceeding will be, or whether the outcome~~matter will have a material ~~adverse effect~~impact on ~~its~~the Utility's financial position or results of ~~operations or financial condition.~~operations.

Electric Restructuring Costs Account Application

~~Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities~~

The Utility administers general and low-income energy efficiency programs, and has been authorized to earn incentives based on a portion of the net present value of the savings achieved by the programs, incentives based on accomplishing certain tasks, and incentives based on expenditures. Each year the Utility files an earnings claim in the Annual Earnings Assessment Proceeding (AEAP), a forum for stakeholders to comment on, and for the CPUC to verify, the Utility's claim. In March 2002, the CPUC eliminated the opportunity for shareholder incentives in connection with the California IOUs' 2002 energy efficiency programs. This decision does not preclude the opportunity to recover shareholder incentives in connection with previous years' energy efficiency programs.

In May 2003, 2002, 2001, and 2000, the Utility filed its annual applications claiming incentives totaling approximately $106 million, consisting of $74 million for pre-1998 energy efficiency programs, $30 million for post-1997 energy efficiency programs, and $1.6 million for low-income programs. The Utility has not included any earnings associated with incentives in the Utility's Consolidated Statements of Income.

Since March 2002, the CPUC had not taken any significant action on the applications while it considered whether the incentive mechanism adopted for pre-1998 energy efficiency programs should be reduced or eliminated for claims in future years. In October 2003, the CPUC issued a decision confirming that the shared savings shareholder incentive mechanism adopted for energy efficiency shareholder incentives in the AEAPs should not be modified. The decision further indicated that all of the earnings claims remain subject to verification, in accordance with the Commission's adopted measurement and evaluation protocols. The CPUC verification lead consultant has begun the verification process and the consultant's report should be completed in the first quarter of 2004.

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would agree to act promptly on pending Utility ratemaking proceedings, including the AEAP applications. Once the consultant's reports are issued, the Utility expects that the applications should proceed reasonably quickly.

In August 2003, the CPUC authorized the recovery of $0.1 million associated with the earnings claim for electric low-income programs in 1998 and held recovery of the Utility's 1999, 2000, and 2001 claims pending the results of the consultant's verification reports. The Utility was also ordered to track the low-income earnings claims for 1999, 2000, and 2001 in a memorandum account.

~~The 2003 AEAP hearing process began with a pre-hearing conference in July 2003. The 2003 AEAP is not consolidated with the 2002, 2001, and 2000 AEAPs.~~

~~The Utility does not expect that the outcome of these proceedings will have a material adverse effect on its results of operations or financial condition.~~

~~Nuclear Decommissioning Cost Triennial Proceeding~~

~~In March 2002,~~ On April 16, 2004, the Utility filed an updated Electric Restructuring Costs Account, or ERCA, application ~~to increase the Utility's nuclear decommissioning~~for recovery of distribution related electric industry restructuring related revenue requirements ~~for the years 2003 through 2005. The Utility sought to recover $24~~totaling $117 million in revenue requirements relating to the Diablo Canyon Nuclear Decommissioning Trusts and $17.5 million in revenue requirements relating to the Humboldt Bay Power Plant Decommissioning Trusts. The Utility also sought recovery of $8.3 million in CPUC-jurisdictional revenue requirements for Humboldt Bay Unit 3 SAFSTOR (a mode of decommissioning) operating and maintenance costs, and escalation associated with that amount in 2004 and 2005.

In October 2003, the CPUC issued a decision adopting 2003 revenue requirements of $18.4 million for decommissioning the Humboldt Bay Power Plant and approved the Utility's request to begin decommissioning the Humboldt Bay Power Plant in 2006 instead of 2015. The decision further grants a revenue requirement of $8.3 million for Humboldt SAFSTOR operating and maintenance costs. In the same decision, the CPUC adopted no revenue requirement for decommissioning the Diablo Canyon Power Plant, finding that the trust funds for Diablo Canyon are sufficient to pay for its eventual decommissioning. The total adopted annual revenue requirement of $26.7 million represents a $4.5 million decrease from the previously adopted revenue requirement of $31.2 million.

~~Baseline Allowance Increase~~

In April 2002, the CPUC required the Utility to increase baseline allowances for certain residential customers by May 1, 2002. An increase to a customer's baseline allowance increases the amount of their monthly usage that is covered under the lowest possible rate and is exempt from the average $0.03 per kWh surcharge. The CPUC deferred consideration of corresponding rate changes until a later phase of the proceeding and ordered the utilities to track the under-collections associated with their respective baseline quantity changes in an interest-bearing balancing account. The Utility is charging the electric-related shortfall against earnings because it cannot predict the outcome of the second phase of the proceeding, nor can it conclude that recovery of the electric-related balancing account is probable. The total electric revenue shortfall for the period ~~May~~1999 through ~~December 2002 was $70 million.~~2002. Revenue requirements associated with these ongoing activities in 2003 and afterwards are included in the 2003 GRC, discussed above. The ~~total electric~~Settlement Agreement requires timely resolution of this proceeding by the CPUC.

Costs included in this application consist primarily of:

·	Expenditures for customer information system and direct access, unbundling, billing and other restructuring activities;
·	Other unfunded mandates from the CPUC and the FERC; and
·	Costs expended by the Utility that the FERC did not allow the Utility to recover from its wholesale customers.

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

Because these costs did not meet the applicable accounting probability standard under SFAS No. 71 needed to record regulatory assets, the Utility has not recorded a regulatory asset for the ~~nine-month period from January 1, 2003, through September 30, 2003, was $81 million.~~

~~Issues expected to be resolved during the second phase~~costs it has incurred as of the proceeding include a number of proposals that would result in additional revenue shortfalls. These proposals include demographic revisions to baseline allowances, special allowances, and changes to baseline territories or seasons. The Utility estimates that the upper range of additional annual electric revenue shortfalls, if all such proposals were adopted in this second phase, could total $55 million per year, plus $10 million in administration costs spread out over three to five years. A proposed decision issued by the CPUC in October 2003 would reject all but two of these proposals: (1) a waiver of Tier 3 electric surcharges for larger lower-middle income households, and (2) a revision to gas and electric baseline quantitiesin the Utility climate zones in which exclusion of seasonal residences' lower usage would increase baseline allowances by at least 3 percent. If adopted as written, the Utility estimates that the pro posed decision could result in annual electric shortfalls of up to $16 million, plus $2 million in initial administrative costs.

The Utility cannot predict what the final outcome of the second phase of the proceeding will be, nor can it conclude that recovery of the electric baseline related balancing account is probable. Any electric revenue shortfalls will continue to be charged to earnings and will reduce revenue available to recover previously written-off under-collected purchased power costs and transition costs.

~~RISK MANAGEMENT ACTIVITIES~~

March 31, 2004. PG&E Corporation and the Utility are ~~exposed~~unable to ~~various risks associated with their operations,~~predict the ~~marketplace, contractual obligations, financing arrangements,~~ultimate outcome of this proceeding.

RISK MANAGEMENT ACTIVITIES

The Utility and ~~other aspects of their business.~~ PG&E Corporation, ~~and the Utility actively manage these risks~~mainly through ~~risk management programs. These programs are designed to support business objectives, minimize costs, discourage unauthorized risk, reduce the volatility~~its ownership of earnings and manage cash flows. At PG&E Corporation and the Utility, risk management activities often include the use of energy and financial derivative instruments and other instruments and agreements. These derivatives include forward contracts, futures, swaps, options, and other contracts.

PG&E Corporation and the Utility use derivatives for non-trading (i.e., risk mitigation) purposes. PG&E Corporation and the Utility enter into derivatives to mitigate the risks associated with an asset (e.g., the natural position embedded in asset ownership and regulatory arrangements), liability, committed transaction, or probable forecasted transaction. Derivatives are used in accordance with approved risk management policies adopted by a senior officer-level risk oversight committee. Entering into derivatives is permitted only after the risk oversight committee approves appropriate risk limits for such activity. The organizational unit proposing the activity must successfully demonstrate that there is a business need for such activity and that the market and credit risks will be adequately measured, monitored, and controlled.

As discussed in the "Liquidity and Financial Resources" section of this MD&A and Note 4 of the Notes to the Consolidated Financial Statements, effective July 8, 2003, NEGT, Inc.'s financial results are no longer consolidated with those of PG&E Corporation and are classified as discontinued operations. Upon deconsolidation of NEGT, Inc., the only risk management activities reported relate to Utility non-trading activities.

PG&E Corporation and the Utility estimated the gross mark-to-market value of their respective non-trading contracts at September 30, 2003, using the mid-point of quoted bid and ask forward prices, where available. When market data is not available, PG&E Corporation and the Utility use models to estimate forward prices with the support of third-party expert applications. Currently, the non-trading contracts of PG&E Corporation and the Utility, are ~~marked~~exposed to market ~~using spread option valuation models.~~

~~Market Risk~~

~~Market~~ risk, which is the risk that changes in market conditions will adversely affect ~~earnings~~net income or cash ~~flow.~~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 with other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk ~~foreign currency risk,~~ and credit risk. ~~PG&E Corporation no longer retains significant influence over NEGT, Inc. as~~The Utility actively manages market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk, reduce earnings volatility and manage cash flows. The Utility's risk management activities often include the use of energy and financial deriv ative instruments, including forward contracts, futures, swaps, options, and other instruments and agreements.

The Utility uses derivative instruments only 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 ~~result~~risk oversight committee composed of ~~their Chapter 11 filing on July 8, 2003. As~~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.

The Utility estimates fair value of ~~this date, PG&E Corporation accounts for its investment in NEGT, Inc. under~~derivative instruments using the ~~cost method~~midpoint of ~~accounting~~quoted bid and ~~consequently NEGT, Inc.'s future financial results~~asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market ~~risk will~~data is not ~~impact PG&E Corporation.~~available the Utility uses models to estimate fair value.

Price Risk

~~Price risk is the risk that changes in commodity market prices will adversely affect earnings and cash flows.~~Electricity

The Utility is exposed to price risk, which consists of electric commodity (including purchased power and nuclear fuel) and natural gas commodity price risks, as described below. Also described below is the value-at-risk methodology, which is PG&E Corporation's and the Utility's method for assessing the prospective price risk that exists within a portfolio.

~~Electric Commodity Price Risk~~

On January 1, 2003, the Utility became responsible for scheduling and dispatching, on a least-cost basis, electricity allocated under contracts entered into by the DWR to fulfill the Utility's customers' electricity requirements. While the DWR continues to be legally and financially responsible for these contracts, the Utility relies on electricity ~~provided by the~~from a diverse mix of resources, including third party contracts, amounts allocated under DWR ~~allocated~~ contracts ~~to service a significant portion of~~and its ~~total load. Customers are billed for these DWR~~own electricity ~~purchases and~~generation facilities. In addition, the Utility ~~remits amounts collected to the DWR based on the DWR's CPUC-approved revenue requirement.~~

~~Beginning January 1, 2003, the Utility began purchasing~~purchases electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to ~~meet its residual net open position. The~~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 ~~increase~~change over time for a number of reasons, including:

~~Periodic expirations of existing electricity purchase contracts;~~

~~Periodic expirations or other terminations of the DWR allocated contracts; and~~

~~Increases in customers' electricity demands due to customer and economic growth or other factors.~~

·	Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts;
·	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; and
·	Planning reserve and operating requirements.

In addition, unexpected outages at the Utility's ~~Diablo Canyon Power Plant or any of the Utility's other significant~~ 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.

~~In December 2002, the CPUC issued an interim opinion granting the~~ The Utility ~~authority~~expects to ~~enter into contracts designed to meet and to hedge~~satisfy at least some of the residual net open position through ~~the first quarter of 2004.~~new contracts.

The Utility entered into contracts to supply 2003 peak capacity, all of which expired after the peak summer months. The Utility expects to enter into contracts to supply peak capacity demand in future years based upon annual CPUC approvals. In connection with these transactionsSettlement Agreement provides that the Utility ~~expects it~~ will be required to post collateral with the ISO and other counterparties. The Utility also buys electricity in short-term market transactions (i.e. forward contracts ranging from one hour ahead to one month ahead).

~~California's SB 1976 directed~~recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC ~~to increase~~review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, ifor order refunds when there is an under- or over-collection exceeding 5% of the ~~available~~Utility's prior year electricity procurement revenues, excluding the revenue ~~does not cover forecasted costs~~collected on behalf of ~~purchasing electricity, and~~ the ~~shortfall exceeds 5 percent~~DWR. In addition, the CPUC has established a maximum procurement disallowance of ~~prior year's generation revenue, excluding amounts collected~~approximately $36 million for the ~~DWR. Because these amounts collected for~~Utility's administration of the DWR contracts and least-cost dispatch. Adverse market price changes are ~~excluded from this shortfall calculation,~~not expected to impact the Utility's net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the ~~CPUC increases~~CP UC may in the ~~portion of~~future disallow transactions that do not comply with the ~~DWR's revenue requirement allocated to the Utility's customers to cover~~CPUC-approved short-term procurement plan. Additionally, adverse market price changes ~~or other factors,~~could impact the ~~Utility has commodity price risk.~~

~~The amount~~timing of electricity provided by the DWR allocated contracts will likely result in surplus electricity during certain periods. The Utility plans to sell this surplus electricity on the open market. 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 share of surplus sales revenues are included in its calculation determining whether it faces an under-collection of electricity procurement costs and is subject to review and recovery within the ERRA procedures discussed under "Electricity Procurement" in the "Regulatory Matters" section of this MD&A.cash flows.

Nuclear Fuel

The Utility ~~has purchase~~purchases nuclear fuel for Diablo Canyon through contracts with terms ranging from two to five years. These agreements ~~for nuclear fuel. The Utility relies on~~are with large, well-established international producers for its long-term nuclear fuel agreements in order to diversify its commitments and ensure security of supply. ~~Pricing terms are also diversified, ranging from fixed prices to base prices that are adjusted using published information.~~

Nuclear fuel purchases are subject to tariffs of up to ~~50 percent~~50% on imports from certain countries. ~~Nuclear~~The Utility's nuclear fuel costs have not increased based on the imposed tariffs because the terms of the Utility's existing long-term contracts ~~did~~do not include ~~such~~these costs. However, ~~once~~ these contracts begin to expire in 2004, ~~the costs~~and prices under new 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 trending higher in 2004.

As the Utility replaces existing contracts ending in 2004, new higher priced uranium contracts will raise nuclear fuel costs. The Utility is expected to offset these higher prices with reduced costs for other nuclear fuel components. While the cost recovery mechanisms under California law described above remain in place, adverse market changes in nuclear fuel prices are not expected to impact net income materially.

Natural Gas

The Utility enters into physical and financial natural gas commodity contracts of up to one-and-a-half years 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 ~~increase. As noted above,~~be purchased in the ~~CPUC is obligated to change retail electricity rates at any time that forecasts indicate the Utility will face an under-collection~~spot market. The Utility's cost of ~~electricity procurement costs, including~~natural gas includes the cost of ~~nuclear fuel, in excess~~Canadian and interstate transportation of ~~5 percent of prior year's generation revenues, excluding amounts collected for the DWR.~~

On August 14, 2003, the Utility entered into an agreement with AmerenUE and TXU Generation LP to form FuelCo, a limited liability company under the laws of the State of Delaware. The purpose of FuelCo is to assist its utility members to purchase nuclear fuel and related services in an efficient and cost-effective manner, principally by acting as agent in fuel procurement transactions. (The members have agreed to share out-of-pocket administrative expenses equally, although the Utility will initially have an ownership interest of less than 5 percent.)

~~Natural Gas Commodity Price Risk and Transportation Revenue Risk~~

~~The Utility recovers~~ natural gas ~~purchase costs through billings to~~purchased for its core customers.

Under the Core Procurement Incentive Mechanism, ~~(CPIM),~~ the ~~Utility is allowed to adjust natural gas rates on a monthly basis. Purchase~~Utility's purchase costs 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 ~~were~~where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is ~~99 percent~~99% to ~~102 percent around~~102% of the benchmark, are considered reasonable and are fully recovered in ~~customer~~customers' rates. ~~Currently, one-half~~One-half of the costs ~~outside~~above 102% of the ~~tolerance band~~benchmark are recoverable ~~customer~~in customers' rates, and the Utility's customers receive ~~the benefits of one-half~~three-fourths of any savings ~~outside~~resulting from the ~~tolerance band~~Utility's cost of natural gas that is less than 99% of the benchmark, in their rates. ~~However,~~While this cost recovery mechanism remains in ~~June 2003,~~place changes in the price of natural gas are not expected to materially impact net income.

Transportation and Storage

The Utility ~~entered into a settlement~~currently faces price risk for the portion of intra state natural gas transportation capacity that is not used by core customers. Non-core customers contract with the ORA that, if approved by the CPUC, would increase the amount of savings passed through to ratepayers from one-half to three-fourths, retroactive to November 1, 2002. Under the proposal, ratepayers would continue to bear one-half of the costs incurred above the tolerance band.

~~In addition, the~~ Utility ~~has contracts~~ for natural gas transportation ~~capacity on various~~and storage, along with natural gas ~~pipelines. In July 2002, the CPUC ordered IOUs to contract for a certain amount of El Paso pipeline capacity to gain firm access to the southwest natural gas producing basins.~~parking and lending (market center) services. The CPUC pre-approved the costs of these contracts as just and reasonable. The July decision also ordered the utilities to retain their then-current interstate pipeline capacity levels and sell any excess capacity to a third party under short-term capacity release arrangements. It also ordered that, to the extent the utilities comply with the decision, they would be able to fully recover their costs associated with existing capacity contracts.

Under a previous CPUC decision, costs paid to Transwestern for gas pipeline capacity through 1997 were not recoverable. The Gas Accord provided for partial recovery of Transwestern costs from 1998 forward. In June 2003, a settlement agreement was reached with TURN that would allow the Utility to fully recover Transwestern costs beginning in July 2003. The CPUC has not yet approved the settlement.

~~Under the Gas Accord settlement, as with the Gas Accord, the~~ Utility is at risk for any natural gas transportation and storage revenue volatility. ~~Capacity~~Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. ~~The Utility currently faces price risk for the part of intrastate natural gas transportation capacity that is not used by core customers.~~ There are significant seasonal and annual ~~fluctuations~~variations in the demand for natural gas transportation and storage services. ~~Because the~~The Utility sells most of its pipeline capacity based on the volume of natural gas ~~customers actually ship rather than through long-term firm capacity contracts,~~that is transported by its customers. As a result, the Utility's natural gas transportation revenues ~~will~~ fluctuate.

~~Value-at-Risk~~

~~PG&E Corporation and~~ The Utility uses value-at-risk to measure the ~~Utility measure price risk exposure using value-at-risk and other methodologies that simulate future price movements~~expected maximum change over a one-day period in the energy markets to estimate the probability of future potential losses. Price risk is quantified using what is referred to as the variance-covariance technique of measuring value-at-risk, which provides a consistent measure of risk across diverse energy markets and products. This methodology relies on a number of important assumptions, including a confidence level for losses, price volatility, market liquidity, and a specified holding period. This technique uses historical price movement data and specific, defined mathematical parameters to estimate the characteristics of, and the relationships between, components of assets and liabilities held for price risk management (PRM) activities. PG&E Corporation and the Utility therefore use the historical data for calculating the expected price volatility of their portfolios' contractual positions to project the likelihood that the prices of those positions will move together.

~~PG&E Corporation's and the Utility's value-at-risk calculation is a dollar amount reflecting the maximum potential one-day loss in the fair~~18-month forward value of ~~their portfolios due to adverse market movements over a defined time horizon within a specified confidence level.~~its transportation and storage portfolio. This calculation is based on a ~~95 percent~~95% confidence level, which means that there is a ~~5 percent~~5% probability that ~~PG&E Corporation's portfolios~~the portfolio will incur a ~~loss~~change 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 percent~~95% probability that if prices moved against current positions, the ~~reduction~~change in the value of the portfolio resulting from ~~such~~a one-day price ~~movements~~movement would not exceed $5 million. ~~There also would be a 5 percent probability~~The value-at-risk provides an indication of the Utility's exposure to potential market conditions that acould impact revenues based on one-day price ~~movement would be greater than $5 million.~~

~~The value-at-risk exposure for~~changes. It is also a way to measure the ~~Utility's non-trading activities includes substantially all derivatives in its natural gas portfolio, with the exception~~effectiveness of financial options, over the entire length of the terms of the transactions. Since January 1, 2003, when the Utility resumed procurement of electricity, the Utility has been measuring certain of the risks embedded in the electricity portfolio, and ensuring that it is within the risk limits adopted in the CPUC's December 2002 interim opinion on the Utility's electricity procurement plan.

~~The potential one-day unfavorable impact for price risk as measured by the value-at-risk model, based~~hedge strategies on a ~~one-day holding period~~portfolio.

The Utility's value-at-risk for its transportation and storage portfolio was $6$3 million at ~~September 30, 2003,~~March 31, 2004 and $4 million at ~~December~~March 31, ~~2002, for the Utility's natural gas portfolio.~~2003. A comparison of daily values-at-risk ~~at September 30, 2003, and at December 31, 2002,~~ 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 ~~has increased at September 30, 2003, as compared to levels at December 31, 2002, due to increases in natural gas prices~~during the first 3 months of 2004 was approximately $6.4, $2.9 and ~~volatility.~~$3.8 million, respectively.

Value-at-risk 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, inadequate indication of the exposure of a portfolio to extreme price movements and the inability to address the risk resulting from intra-day trading activities. ~~Value-at-risk also does not reflect the significant regulatory and legislative risks currently facing the Utility or the risks relating to the Utility's Chapter 11 proceeding.~~

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, 2003,~~March 31, 2004, if interest rates changed by ~~1 percent~~1% for all current variable rate debt held 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.

~~As discussed above under "Terms of the Settlement Plan," the Utility plans to issue debt to facilitate payment of allowed claims in the Utility's Chapter 11 case.~~ The Utility ~~anticipates that all costs associated with~~entered into derivative instruments to partially hedge the ~~debt will be fully recoverable. The Utility filed a petition with the CPUC during the third quarter of 2003 requesting authorization to enter into~~ interest rate ~~hedges~~risk on up to $7.4 billion of long-term debt ~~that would~~to be issued ~~under any plan of reorganization because~~in conjunction with the emergence from Chapter 11 protection. The cost of the hedges, purchased at fair value, was approximately $45 million. At March 31, 2004, the hedges were reflected on the balance sheet in other current ~~low interest rate environment and~~assets at a fair value of approximately $0.25 million. On April 13, 2004 the ~~possibility of interest rates rising~~hedges were liquidated for approximately $1 million. As provided for in the ~~period when the Utility expects to issue debt to emerge from bankruptcy. On September 4, 2003,~~Settlement Agreement with the CPUC, ~~issued a decision authorizing~~the CPUC agreed that the actual reasonable cost of the interest rate hedging activities with respect to ~~mitigate~~ the ~~final~~financing necessary for the Settlement Plan shall be reflected and recoverable in the Utility's retail gas and electric rates without further review. Therefore, the Utility has recorded a regulatory asset for the net costs of the plan of reorganization, subject to the approval of the actual transactions by the CPUC's financing team (consisting of the Director of the CPUC's Energy Division and the designee of the CPUC's General Counsel). The CPUC's financing team issued a letter of authorization on October 24, 2003, authorizing the Utility to enter into specific interest rate hedges.

The Utility also petitioned the Bankruptcy Court for the authority to enter into interest rate hedges in August 2003, with a maximum cost of up to an aggregate of $90 million and with settlement dates through June 30, 2004. Bankruptcy Court approval was received on September 26, 2003.

On October 31, 2003, and November 3, 2003, the Utility entered into interest rate hedges to reduce the impact to ratepayers resulting from possible significant increases in interest rates on the debt to be issued.

~~Foreign Currency Risk~~

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar. The Utility is exposed to such risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements.

Changes in gas purchase costs due to fluctuations in the value of the Canadian dollar would be passed through to customers in rates, as long as the overall costs of purchasing gas are within a 99 percent to 102 percent tolerance band around the benchmark price under the CPIM mechanism, as discussed above.

The Utility uses sensitivity analysis to measure exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at September 30, 2003, a 10 percent devaluation of the Canadian dollar would be immaterial to the Utility's Consolidated Financial Statements.

Credit Risk

PG&E Corporation had gross accounts receivable of ~~$1.9~~approximately $2.1 billion at ~~September 30, 2003~~March 31, 2004 and ~~$2.0~~approximately $2.5 billion at December 31, ~~2002.~~2003. The majority of the accounts receivable ~~are~~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 ~~$60~~approximately $61 million at ~~September 30, 2003,~~March 31, 2004 and ~~$59~~approximately $68 million at December 31, ~~2002,~~2003 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~~northern and central California. However, ~~the risk of~~ material loss due to non-performance from ~~these~~the se customers is not considered likely.

The schedule below summarizes the Utility's credit risk exposure to counterparties that are in a net asset position, as well as the Utility's credit risk exposure to counterparties with a greater than 10 percent net credit exposure, at September 30, 2003, and December 31, 2002:

~~The schedule below summarizes the credit quality of the Utility's net credit risk exposure to counterparties at September 30, 2003, and December 31, 2002.~~

CRITICAL ACCOUNTING POLICIES

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

~~Derivatives and Energy Trading Activities~~

~~In 2001,~~ PG&E Corporation and the Utility ~~adopted SFAS No. 133, "Accounting~~account for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging Activities" (collectively, SFAS No. 133), which required all derivative instruments to be recognized in the financial ~~statements at their fair value. Prior to its rescission, PG&E Corporation accounted for its energy trading activities~~effects of regulation in accordance with ~~Emerging Issues Task Force (EITF) No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and~~ SFAS No. ~~133, which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting.~~

PG&E Corporation and the Utility have derivative commodity contracts for the physical delivery of purchase and sale quantities such as natural gas and electricity transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and are not reflected on the balance sheet at fair value. See further discussion in Notes 1 and 5 of the Notes to the Consolidated Financial Statements.

~~Unbilled and Surcharge Revenues~~

Since the CPUC authorized the collection of incremental surcharge revenues in January, March, and May 2001, the Utility has not provided reserves for potential refunds of these surcharges, nor would the surcharges be subject to refund under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding. If the proposed CPUC settlement agreement is not approved, it is possible that subsequent decisions by the CPUC may affect the amount and timing of these surcharge revenues recovered by the Utility and that subsequent CPUC decisions may order the Utility to refund all or a portion of the surcharge revenues collected. See Note 2 of the Notes to the Consolidated Financial Statements and the risk factors discussion within the "Overview" section of this MD&A for further discussion.

~~DWR Revenues~~

The Utility acts as a pass-through entity for electricity purchased by the DWR on behalf of customers in the Utility's service area. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from electric revenues amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers at the related CPUC-approved rate. These pass-through amounts are excluded from the Utility's electric revenues in its Consolidated Statements of Income.

The DWR's revenue requirements for 2001, 2002, 2003, and 2004 are subject to true-up adjustments to reflect actual data. Factors that could affect the amount of pass-through revenues recorded by the Utility include whether the CPUC revises or adjusts any of these DWR revenue requirements.

Depending on whether these revisions or adjustments or any other revisions are ultimately approved or disapproved by the CPUC, the outcome could have a material adverse effect on the Utility's results of operations or financial condition. See further discussion in "DWR Revenue Requirement" and "DWR Bond Charges" in the "Regulatory Matters" section of this MD&A.

~~Regulatory Assets and Liabilities~~

~~PG&E Corporation and the Utility apply~~71. SFAS No. 71 ~~"Accounting~~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 a natural gas pipeline expansion project. During the ~~Effects~~first quarter of ~~Certain Types of Regulation" (SFAS~~2004, the Utility began reapplying SFAS No. ~~71),~~71 to ~~their regulated~~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 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 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, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that can be recovered through rates.

If it is determined that ~~these items are~~a regulatory asset is no longer ~~likely to be recovered under~~probable of recovery in rates, then SFAS No. 71 ~~they will~~requires that it be written off at that time. At ~~September 30, 2003,~~March 31, 2004, PG&E Corporation and the Utility reported regulatory assets ~~of $2.2 billion, including~~(including current regulatory balancing accounts ~~receivable,~~receivable) of approximately $7.5 billion and regulatory liabilities ~~of $1.1 billion, including~~(including current ~~regulatory~~ balancing accounts ~~payable.~~payable) of approximately $4.7 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, 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 in unbilled revenues no longer have the same impact on the Utility's results of operations that they had in prior years.

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 ana liability associated with environmental remediation ~~liability~~activities when ~~site assessments indicate~~it is determined that remediation is probable and the cost can be ~~reasonably estimated. This~~estimated in a reasonable manner. The liability iscan be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is ~~reviewed on a quarterly basis and is~~ recorded at the lower range of estimated costs, unless ~~there~~a more objective estimate can be achieved. The recorded liability is ~~a better estimate available.~~re-examined every quarter.

At ~~September 30, 2003,~~March 31, 2004, the Utility's accrual for undiscounted environmental ~~remediation~~ liability was ~~$323~~approximately $337 million. The Utility's undiscounted future ~~cost~~costs could increase to as much as ~~$418~~$454 million if ~~(1) the~~ other potentially responsible parties are not ~~financially~~ able to contribute to the settlement of these costs ~~(2)~~or the extent of contamination or necessary remediation is greater than ~~anticipated, or (3) the Utility is found to be responsible for clean-up costs at additional sites.~~

The process of estimating remediation liabilities is difficult and changes in the estimate could occur, given the uncertainty concerning the Utility's ultimate liability, the complexity of environmental laws and regulations, the selection of compliance alternatives, and the financial resources of other responsible parties.

~~The Utility's Chapter 11 Filing~~

Due to the Utility's Chapter 11 filing in 2001, the financial statements for both PG&E Corporation and the Utility are prepared in accordance with SOP 90-7, which is used by reorganizing entities operating under the Bankruptcy Code. Under SOP 90-7, certain claims against the Utility prior to its Chapter 11 filing are classified as Liabilities Subject to Compromise. The Utility reported a total of $9.5 billion of Liabilities Subject to Compromise at September 30, 2003. While the Utility operates under the protection of the Bankruptcy Court, the realization of assets and the liquidation of liabilities is subject to uncertainty, as additional claims to Liabilities Subject to Compromise can change due to such actions as the resolution of disputed claims or certain Bankruptcy Court actions. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion of the status of the Utility's Chapter 11 proceeding.

~~See Note 1 of the Notes to the Consolidated Financial Statements for further discussion of accounting policies and new accounting developments.~~

anticipated.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

In ~~January 2003,~~March 2004, the FASB issued ~~Interpretation~~Staff Position SFAS No. ~~46, "Consolidation~~106-b, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of ~~Variable Interest Entities" (FIN 46),~~2003," or SFAS No. 106-b. SFAS No. 106-b supersedes SFAS No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," or SFAS No. 106-1, and provides guidance on the accounting, disclosure, effective date and transition related to the Prescription Drug Act. Under the current proposal, SFAS No. 106-b is to become effective for the third quarter 2004, which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity. A "variable interest entity" is an entity that does not have sufficient equity investment at risk or lacks the essential characteristics of a controlling financial interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E Corporation or the Utility between Februarybegins on July 1, ~~2003, and September 30, 2003. PG&E Corporation and the Utility must apply the provisions of FIN 46 as of December 31, 2003, for entities created prior to February 1, 2003.~~

2004. PG&E Corporation and the Utility are continuing to evaluate the ~~impacts~~impact of ~~FIN 46's initial~~SFAS 106-b's recognition, measurement and disclosure provisions on the consolidated financial statements and are unable to estimate the impact, if any, which will result when FIN 46 becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in two of these entities as a result of the adoption of FIN 46. At September 30, 2003, the Utility's recorded investment in these entities is approximately $17 million. As a limited partner, the Utility's exposure to potential loss is limited to its investment in each partnership.

~~Changes to Accounting for Certain Derivative Contracts~~

In June 2003, the Financial Accounting Standards Board (FASB) issued a new Derivatives Implementation Group (DIG) interpretation of SFAS No. 133, Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of~~Not Clearly and Closely Related~~in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature" (DIG C20). DIG C20 specifies additional circumstances under which price adjustment features, such as those based on broad market indices, in a derivative contract would not be an impediment to qualify for the normal purchases and normal sales scope exception under SFAS No. 133. One of the attributes necessary to qualify for the normal purchases and sales exception is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. Under DIG C20, as long as the price adjustment feature in a contract is expected to be highly correlated to the asset to be delivered under that contract, the use of a broad market index (such as the consumer price index) as a price adjustment feature is considered clearly and closely related. Previously, under DIG C11, "Interpretations of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exceptions," the use of a price adjustment based on a broad market index was not considered to be clearly and closely related to the asset to be delivered, and the contract was not eligible for the normal purchases and sales exception. The guidance in DIG C11 is superseded by DIG C20.

TAXATION MATTERS

The ~~Internal Revenue Service (IRS)~~IRS has completed its audit of PG&E Corporation's 1997 and 1998 consolidated ~~U.S.~~ federal income tax returns and has assessed additional federal income taxes of ~~$73~~$75 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 PG&E Corporation's financial position or results of operations.

The IRS also is auditing PG&E Corporation's 1999 and 2000 consolidated ~~U.S.~~ federal income tax returns, but has not issued its final report. ~~However,~~In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS ~~has proposed adjustments totaling $69~~of $75 million ~~(including interest).~~to halt the accrual of interest in respect of these tax returns. The assessment and payment did not have a material effect on PG&E Corporation's financial position or results of operations.

As a result of ~~NEGT, Inc.'s~~NEGT's Chapter 11 filing on July 8, 2003, the IRS recently began its audit of PG&E Corporation's 2001 and 2002 consolidated ~~U.S.~~ federal income tax returns. ~~Under applicable bankruptcy law,~~On June 27, 2003 the IRS announced it will review scientific tests related to production of synthetic fuels. One of NEGT's subsidiaries operated two synthetic fuel facilities in 2001 and most of 2002. PG&E Corporation has ~~180 days from~~claimed tax credits totaling approximately $104 million for these facilities. If the ~~date of~~IRS determines that these synthetic fuel facilities do not meet the ~~filing of~~criteria to qualify for the ~~petition~~tax credit, PG&E Corporation may be subject to ~~submit its proof of claim to the Bankruptcy Court.~~additional tax and interest.

All of PG&E Corporation's federal income tax returns prior to 1997 have been closed. In addition, California and certain other state tax authorities currently are auditing various state tax returns. On June 27, 2003, the IRS announced it will review scientific tests related to production of synthetic fuels (Section 29); NEGT, Inc. operated two synthetic fuel facilities in 2001 and most of 2002. The aggregate amount claimed for these Section 29 credits was approximately $104 million. The resolution of these matters with the IRS is not expected to have a material adverse effect on PG&E Corporation's earnings.

In Through March 31, 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty in ~~realizing certain state deferred tax assets arising at NEGT, Inc.~~their realization. Valuation allowances of ~~zero and $24~~approximately $17 million were recorded in discontinued operations, and ~~zero and~~approximately $5 million in accumulated other comprehensive loss ~~for the three- and nine-month periods ended September 30,~~through March 31, 2003.

In addition, PG&E Corporation recognized federal deferred tax assets related to losses incurred at NEGT, Inc. These deferred tax assets were determined on a consolidated basis, with the related tax benefit of zero and $157 million recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and zero and $44 million recorded in OCI for the three- and nine-month periods ended September 30, 2003.

Upon deconsolidation of NEGT, Inc. for financial statement purposes, PG&E Corporation adopted the cost method of accounting for its ownership interest in NEGT, Inc. As a result of this accounting change, PG&E Corporation will not recognize additional ~~deferred~~income tax ~~assets~~benefits for financial reporting purposes after July 8,7, 2003 with respect to any subsequent losses ofrelated to NEGT ~~Inc.~~or its subsidiaries even though it continues to include NEGT ~~Inc.~~ and its subsidiaries in its consolidated income tax returns. Any ~~unrealized~~such recognized benefits and deferred tax assets ~~relating~~arising from losses related to ~~the losses of~~ NEGT ~~Inc.~~or its subsidiaries that have been recognized through July 7, 2003 will ~~reverse~~be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in NEGT.

NEGT ~~Inc. This reversal of deferred tax assets will partially offset any one-time gain recognized when~~and its creditors have brought litigation against PG&E Corporation ~~writes off~~in NEGT's Chapter 11 proceeding, asserting that NEGT is entitled to be compensated under an alleged implied tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of losses and deductions related to NEGT or its ~~net investment~~subsidiaries in ~~NEGT, Inc.~~PG&E Corporation's consolidated federal tax return. This litigation is discussed above.

ADDITIONAL SECURITY MEASURES

Various federal regulatory agencies have issued guidance and the ~~Nuclear Regulatory Commission recently~~NRC has issued orders regarding additional security measures to be taken at various facilities, ~~owned by PG&E Corporation and the Utility. Facilities of PG&E Corporation and the Utility affected by the guidance and the orders include~~including generation facilities, transmission substations and natural gas transportation facilities. The ~~pending~~ guidance ~~may,~~ and the ~~current guidance and~~ orders ~~will~~ require additional capital investment and an increased ~~level of~~ operating ~~costs, some of which may not be recoverable through current regulatory mechanisms.~~costs. However, neither PG&E Corporation nor the Utility believes that these costs will have a material impact on ~~their~~its consolidated financial position or results of operations.

~~OTHER LONG-TERM CAPITAL EXPENDITURES~~

~~Steam Generator~~

During a routine inspection conducted as part of Diablo Canyon's last refueling of Unit 2, the Utility has found indications of steam generator tube cracking in locations not previously detected. Additional inspections of steam generators that the Utility now will need to perform at each refueling until the steam generators are replaced will lengthen future refueling outages. Therefore, the Utility now is planning to accelerate the replacement of steam generators, which is estimated to cost approximately $655 million for the two units combined, to 2008 and 2009 rather than 2009 as originally contemplated.

~~Path 15 Upgrade~~

In December 2002, the Utility agreed to participate in a project sponsored by Western Area Power Administration (WAPA) to upgrade the transfer capability of the section of transmission system known as Path 15, located in central California. The project entails construction of a new 84-mile, 500 kV transmission line by WAPA between two existing substations in northern and central California owned by the Utility and WAPA. All the participants have agreed to turn over operational control of the transmission system upgrade to the ISO upon completion of the project. The Utility's share of total costs of this project is approximately $75 million. The Utility's commitments are contingent upon WAPA meeting certain construction milestones.

~~UTILITY CUSTOMER INFORMATION SYSTEM~~

The Utility implemented a new customer information system at the end of 2002 and continues to work through various billing and collection issues associated with the change over to the new system. The implementation has, among other things, required the Utility to put into place new processes for recording and estimating revenues and electricity-related costs. The Utility does not expect the system changes to have a significant impact on its financial position and 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 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 6 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters and significant pending legal matters.

~~OTHER MATTERS~~

The Boards of Directors of PG&E Corporation and the Utility each has determined that both C. Lee Cox and Barry Lawson Williams, members of each company's Audit Committee, are "audit committee financial experts" as defined by the Securities and Exchange Commission regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Messrs. Cox and Williams are "independent" as defined by current listing standards of the New York Stock Exchange and the American Stock Exchange, as applicable.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4: CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation's and Pacific Gas and Electric Company's, or the Utility's, disclosure controls and procedures as of ~~September 30, 2003,~~March 31, 2004, 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.

There were no changes in internal controls over financial reporting that occurred during the quarter ended ~~September 30, 2003,~~March 31, 2004, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's controls over financial reporting.

During the first quarter of 2003, PG&E National Energy Group, Inc. (PG&E NEG) management discovered misclassifications of certain offsetting revenues and expenses between discontinued operations and continuing operations of a subsidiary of PG&E NEG, which netted to zero. As a result of PG&E NEG's Chapter 11 filing on July 8, 2003, the resignation of PG&E Corporation's representatives who previously served on PG&E NEG's Board of Directors, and their replacement with Board members elected by PG&E NEG who are not affiliated with PG&E Corporation, PG&E Corporation no longer retains significant influence over the ongoing operations of PG&E NEG. On October 3, 2003, the Bankruptcy Court authorized PG&E NEG to change its name to National Energy and Gas Transmission, Inc. (NEGT, Inc.). The change reflects NEGT, Inc.'s pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG will refer to NEGT, Inc. However, PG&E Corpo ration has been informed that subsequent to the end of the second quarter, NEGT, Inc. has initiated appropriate actions and controls designed to prevent recurrence of the types of errors that led to the misclassifications.

NEGT, Inc. reviewed its second quarter presentation methods for netting certain trading and hedging revenues and expenses. NEGT, Inc. adopted a net presentation approach for such transactions and reflected this change in its second quarter results. For prior periods, NEGT, Inc. continues to review this matter, which generally arises as the result of changes made in 2002 to the presentation of trading and hedging revenues and expenses to reflect the netting of certain trading activities and the reclassification of discontinued operations. PG&E Corporation cannot predict the results of this review, but does not believe that it will have any impact to net income. This review could result in additional changes in revenues and expenses of discontinued operations for prior periods.

PART II. OTHER INFORMATION

ITEM 1:1. LEGAL PROCEEDINGS

For additional information regarding certain of the legal proceedings presented below, see Note 6 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company Chapter 11 Filing

Pacific Gas and Electric Company's, ~~(Utility)~~or the Utility's, Chapter 11 proceeding has been previously disclosed in PG&E Corporation's and the Utility's combined ~~2002~~2003 Annual Report on Form 10-K ~~as amended, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.~~in "Part I, Item 3: Legal Proceedings."

~~On June 19, 2003,~~ As previously disclosed, PG&E Corporation, the Utility and the ~~staff of the~~ California Public Utilities Commission, ~~(CPUC) announced~~or CPUC, entered into a ~~proposed~~ settlement agreement ~~that contemplates a new~~on December 19, 2003 to resolve the Utility's Chapter 11 proceeding, or the Settlement Agreement. The CPUC had approved the Settlement Agreement on December 18, 2003. On December 22, 2003, the bankruptcy court confirmed the Utility's plan of reorganization, ~~(Settlement Plan). The proposed~~or Plan of Reorganization, that fully incorporated the Settlement Agreement.

On March 16, 2004, the CPUC ~~settlement agreement is subject~~denied the applications filed by various parties to rehear and reconsider its December 18, 2003 decision approving the ~~approval of the Boards of Directors of PG&E Corporation and the Utility, as well as the CPUC.~~Settlement Agreement. In addition, the ~~proposed~~two CPUC ~~settlement agreement must be executed by all parties on~~commissioners who did not vote to approve the Settlement Agreement, or ~~before December 31, 2003. On July 25, 2003,~~ the ~~Utility~~dissenting commissioners, and a municipality filed ~~its testimony in support~~appeals of the proposed CPUC settlement agreement. Testimony from the staff of the CPUC and the Official Committee of Unsecured Creditors (OCC) was also filed on July 25, 2003. On September 25, 2003, the Utility and 22 other organizations representing federal, state, and local governments, environmental groups, resource conservation, and agricultural and water interests entered into a comprehensive stipulation that resolves most, if not all, of the environmen tal issues pertaining to the proposed settlement agreement. While the stipulation does not change the proposed CPUC settlement agreementbankruptcy court's confirmation order in any way, it establishes mutually agreeable procedures for implementing the proposed CPUC settlement agreement's proposed land conservation commitment, under which the Utility will either provide conservation easements or donate to public agencies or conservation organizations approximately 140,000 acres of watershed and other lands.

The CPUC concluded the public evidentiary hearings on the proposed CPUC settlement agreement on September 26, 2003. The CPUC is currently expected to vote on the proposed CPUC settlement agreement in late December 2003.

~~In addition,~~ the U.S. ~~Bankruptcy~~District Court for the Northern District of California, ~~(Bankruptcy Court) must confirm~~or the District Court, citing similar objections to those included in the request for rehearing and reconsideration of the CPUC's decision. The District Court will set a schedule for briefing and argument of the appeals at a later date. On March 26, 2004, the Utility and PG&E Corporation notified the bankruptcy court that all conditions precedent to the effectiveness of the Plan of Reorganization were satisfied. On April 9, 2004, the District Court denied a request filed by t he dissenting commissioners to stay the implementation of the Plan of Reorganization on April 12, 2004.

On April 12, 2004, the Utility's Plan of Reorganization became effective. Although the Utility's operations will no longer be subject to the oversight of the bankruptcy court, the bankruptcy court will retain jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement ~~Plan. While~~Agreement, (2) the ~~CPUC is not a proponent, it would agree under~~Plan of Reorganization, and (3) the ~~proposed CPUC settlement agreement~~bankruptcy court's confirmation order. The bankruptcy court also will retain jurisdiction to ~~support~~resolve disputed claims. For information regarding the Settlement Plan. On August 15, 2003, a disclosure statement and ballot were sent to creditors entitled to vote on the Settlement Plan. Solicitation of creditor votes ended on September 29, 2003. On October 14, 2003, the Utility filed the voting results with the Bankruptcy Court. Allimplementation of the ~~creditor classes that voted on the Settlement~~ Plan ~~voted in favor~~of Reorganization, see Note 2 of the ~~Settlement Plan.~~Notes to the Condensed Consolidated Financial Statements.

On September 26, 2003, the State of California filed a motion for summary judgment in the Bankruptcy Court, seeking an order finding that the Settlement Plan cannot be confirmed because it illegally releases or discharges third-party claims against PG&E Corporation and its officers and directors, including the claims brought by the California Attorney General (AG) andApril 15, 2004, the City and County of San Francisco, ~~(CCSF) under Section 17200~~or CCSF, and Aglet Consumer Alliance, or Aglet, each filed a petition with the California Court of Appeals seeking review of (1) the CPUC's December 18, 2003 decision approving the Settlement Agreement and (2) the CPUC's March 16, 2004 denial of their applications for rehearing of the CPUC's December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California ~~Business & Professions Code, without~~law, among other claims. CCSF requests the ~~third parties' express consent.~~appellate court to hear and review the CPUC's decisions approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. PG&E Corporation and the Utility believe ~~that~~ the ~~Settlement Plan does not attempt to obtain the release or discharge of claims other than as allowed by law.~~petitions are without merit and should be denied. The ~~Bankruptcy Court heard the State's summary judgment motion on October 16, 2003, but has not ruled on the motion.~~

The Bankruptcy Court confirmation hearing began on November 10, 2003. Various confirmation trial dates have been set for November and December 2003, the latest of which is December 18, 2003. Trial briefsUtility's answer in opposition to the Settlement Plan were filed by, among others, the State of California, CCSF, and various municipalities. Among other arguments, the State of California and CCSF reassert the argument made by the State of California in its summary judgment motion; namely, that the Settlement Plan's proposed release and discharge provisions are overbroad and are intended to improperly release claims held by third parties against PG&E Corporation.

For more information about the Utility's Chapter 11 proceeding and the proposed settlement agreement, see "Management's Discussion and Analysis" and Note 2 of the Notes to the Consolidated Financial Statements.

PG&E Corporation and the Utility are unable to predict whether the proposed CPUC settlement agreement will be approved or whether the Settlement Plan will become effective or what the outcome of the Utility's Chapter 11 proceeding will be. If the proposed CPUC settlement agreement and the related Settlement Plan do not become effective, the Utility's financial condition and results of operations could be materially adversely affectedpetitions for review is due ~~to the outcome of certain pending regulatory proceedings as discussed above in "Management's Discussion and Analysis" and Note 6 of the Notes to the Consolidated Financial Statements.~~May 19, 2004.

Chapter 11 Filing of ~~National Energy & Gas Transmission, Inc. (formerly PG&E National Energy Group, Inc.)~~NEGT

For information regarding this matter, see PG&E Corporation's ~~Quarterly~~and the Utility's combined 2003 Annual Report on Form ~~10-Q for the quarter ended June 30, 2003,~~10-K, in "Part I, Item 3: Legal Proceedings" and ~~Notes 1 and~~Note 4 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company v. ~~Loretta M. Lynch,~~Michael Peevey, et al.

For more information regarding the Filed Rate Case litigation, see "Part I, Item 3: Legal Proceedings - Pacific Gas and Electric Company vs. ~~California Public Utilities Commissioners~~ Michael Peevey, et al." in PG&E Corporation's and the Utility's combined ~~2002~~2003 Annual Report on Form ~~10-K, as amended, and "Part II, Item 1: Legal Proceedings - Pacific~~10-K.

In re: Natural Gas ~~and Electric Company vs. California Public Utilities Commissioners " of PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.~~Royalties Qui Tam Litigation

~~Federal Securities Lawsuit~~

As previously disclosed in PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on June 10, 2003, the Ninth Circuit heard oral argument on plaintiffs' appeal of the District Court's order dismissing the second amended complaint with prejudice. In July 2003, the Ninth Circuit court upheld the District Court's dismissal of the plaintiffs' second amended complaint, finding that the plaintiffs had failed to establish that PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 were materially misleading. The plaintiffs have failed to appeal or take any further steps to pursue this matter.

For ~~more~~ information regarding this matter, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's ~~2002~~and the Utility's combined 2003 Annual Report on Form ~~10-K, as amended.~~10-K.

Diablo Canyon Power Plant

As previously disclosed, on June 13, 2002, the Utility received a draft enforcement order from the California Department of Toxic Substances Control, or DTSC, alleging that the Utility's Diablo Canyon power plant failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months after the Utility's Chapter 11 filing in 2001. The draft order sought $340,000 in civil penalties for the period during which the Utility was unable to comply with the DTSC's requirements. The draft order also directed the Utility to maintain appropriate financial assurance on a going forward basis. On September 4, 2002, the Utility received a draft enforcement order from DTSC alleging a variety of hazardous waste violations at the Utility's Diablo Canyon power plant. This draft order sought $24,330 in civil penalties.

In ~~re: Natural Gas Royalties Qui Tam Litigation~~April 2003, the Utility signed a final settlement agreement with DTSC, under which the Utility agreed to pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The Utility paid these amounts in May 2003. The California Attorney General had filed a claim in the Utility's Chapter 11 case on behalf of DTSC, and in February 2004 it withdrew those portions of the claim relating to financial assurance and hazardous waste matters.

For more information regarding ~~this matter, see " Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.~~

~~Moss Landing~~matters relating to Diablo Canyon Power Plant,

~~For information regarding this matter,~~ see PG&E Corporation's and the Utility's combined ~~2002~~2003 Annual Report on Form ~~10-K, as amended, 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 quarter ended June 30, 2003.~~

~~Diablo Canyon Power Plant~~

For information regarding this matter, see PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and "Part II, Item 1: Legal Proceedings" of PG&E Corporation's and the Utility's combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.10-K.

Compressor Station Chromium Litigation

As previously disclosed, the Utility has filed 14 summary judgment motions or motions in limine that challenge plaintiffs' lack of admissible scientific evidence that chromium caused the injuries alleged by the test plaintiffs. The Los Angeles Superior Court began hearing argument on two of the motions in February 2004, but no rulings have been issued. Although the trial date had previously been scheduled to begin in March 2004, the Court vacated the trial date, and no new trial date has been set.

The Utility has recorded a reserve in the Utility's financial statements in the amount of $160 million for these matters. The Utility believes that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on the Utility's financial condition or future results of operations.

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 ~~2002~~2003 Annual Report on Form ~~10-K, as amended, and~~10-K.

Complaints Filed by the combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, as amended, the Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs in the Chromium Litigation. Two of these motions are scheduled to be heard in December 2003 and two of these motions are scheduled to be heard in January 2004. The Utility also has filed a motion to dismiss the complaint in one of the cases that is scheduled to be heard on November 14, 2003. The trial of 18 test cases has been scheduled to begin in March 2004.

~~California Energy Trading Litigation~~

~~For information regarding these matters, see PG&E Corporation's 2002 Annual Report on Form 10-K, as amended, and PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.~~

California Attorney General, ~~Complaint~~City and County of San Francisco, and Cynthia Behr

As previously disclosed in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on July 24, 2003, the U.S. District Court for the Northern District of California, ~~(District Court)~~or District Court, heard oral argument on the appeal and cross-appeal of the ~~Bankruptcy Court's~~bankruptcy court's remand ~~order.~~order in the three cases. On October 8, 2003, the District Court reversed, in part, the ~~Bankruptcy Court's~~bankruptcy court's June 2002 decision and ordered the AGCalifornia Attorney General's restitution claims sent back to the ~~Bankruptcy Court.~~bankruptcy court. The District Court found that these claims, estimated along with the City and County of San Francisco's claims ~~discussed below~~ at approximately $5 billion, ~~are~~were the property of the Utility's Chapter 11 estate and therefore are properly within the ~~Bankruptcy Court's~~bankruptcy court's jurisdiction. ~~Under~~As part of the ~~Settlement~~Utility's Plan of Reorganization, the Utility ~~would release these claims.~~released PG&E Corporation and the director s from any claims that it might have had for restitution. The Attorney General and the City and County of San Francisco have appealed the District Court's October 2003 ruling to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit.The defendants filed motions to dismiss the appeals on the ground that the Ninth Circuit lacked jurisdiction to hear them under certain provisions of the U.S. Bankruptcy Code. The Ninth Circuit denied defendants' motions to dismiss in March 2004, and consolidated the two appeals.

The District Court also ~~affirmed, in part, the Bankruptcy Court's June 2002 decision and found~~ruled that the ~~AG's~~Attorney General's civil penalty and injunctive relief claims under Section 17200 of the California's Business and Professions Code ~~(Section 17200)~~ could be resolved in San Francisco Superior Court, where a status conference has been scheduled ~~for December 18, 2003. No proceedings have been scheduled~~to occur in ~~Bankruptcy Court regarding the restitution claims.~~ July 2004.Under Section 17200, the AGAttorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The ~~AG's~~Attorney General's complaint asserted that the total civil penalties would be not less than $500 million. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

For more information regarding ~~this matter,~~these cases, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined ~~2002~~2003 Annual Report on Form ~~10-K, as amended, and the combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.~~10-K.

~~Complaint Filed by the City and County of San Francisco and the People of the State of California~~

As previously disclosed in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on July 24, 2003, the District Court heard oral argument on the appeal and cross appeal of the Bankruptcy Court's remand order. On October 8, 2003, the District Court reversed, in part, the Bankruptcy Court's June 2002 decision and ordered the City and County of San Francisco (City)'s restitution claims sent back to the Bankruptcy Court. The District Court found that these claims, estimated along with the AG's claims discussed above at approximately $5 billion, are the property of the Utility's Chapter 11 estate and therefore are properly within the Bankruptcy Court's jurisdiction. Under the Settlement Plan, the Utility would release these claims. The District Court also affirmed, in part, the Bankruptcy Court's June 2002 decision and found that the City's civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Su perior Court, where a status conference has been scheduled for December 18, 2003. No proceedings have been scheduled in Bankruptcy Court regarding the restitution claims. Under Section 17200, the City is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

~~Cynthia Behr v. PG&E Corporation, et al.~~

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

~~PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its financial condition or results of operations.~~

~~PG&E National Energy Group's Brayton Point Generating Station~~

~~For information regarding this matter, see PG&E Corporation's 2002 Annual Report on Form 10-K, as amended.~~

~~William Ahern, et al. v. Pacific Gas and Electric Company~~

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Report for the Form 10-Q for the quarter ended March 31, 2003, as amended.

ITEM 2:2. CHANGES IN SECURITIES AND USE OF PROCEEDS

On ~~July 2, 2003,~~February 18, 2004, the Board of Directors of PG&E Corporation ~~completed a private placement of $600 million of 6⅞ percent Senior Secured Notes due 2008 (Notes). The Notes are secured by a pledge of approximately 94 percent~~authorized the amendment of the ~~outstanding common stock~~Rights Agreement, or Rights Agreement, dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, or Rights Agent, by providing that the ~~Utility. The Notes are effectively subordinated~~rights to ~~all indebtedness and other obligations~~purchase one one-hundredth of a share of PG&E Corporation's ~~subsidiaries. The indenture, dated as~~Series A Preferred Stock, par value $100 per share, that were distributed to PG&E Corporation's shareholders on December 20, 2000, will expire on the close of ~~July 2, 2003, will permit~~business on the date that Pacific Gas and Electric Company's confirmed plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code becomes effective. PG&E Corporation has delivered to the Rights Agent an Amendment of Rights Agreement and ~~its subsidiaries~~Certification of Compliance with Section 26 dated February 18, 2004, directing the Rights Agent to ~~incur additional indebtedness, including secured equal ranking indebtedness.~~

~~The net proceeds~~amend Section 7(a) of the ~~offering, together~~Rights Agreement by deleting clause (ii) thereof and replacing it with ~~cash~~the following: "(ii) the Close of Business on ~~hand, were used~~the date that Pacific Gas and Electric Company's confirmed plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code becomes effective."

On April 12, 2004, the Utility's Plan of Reorganization became effective and the rights to pay approximately $735 million under PG&E Corporation's existing credit agreement, including outstanding principal, all accrued interest, and prepayment premiums. The payment also resulted in the terminationpurchase one one-hundredth of a share of PG&E Corporation's existing credit agreement and the release of liens on PG&E Corporation's shares of PG&E National Energy Group, LLC and on PG&E National Energy Group, LLC shares of National Energy & Gas Transmission, Inc. (formerly PG&E National Energy Group, Inc.).Series A Preferred Stock, par value $100 per share, expired.

The Notes were offered within the United States only to qualified institutional investors pursuant to Rule 144A under the Securities Act of 1933 (Securities Act) and, outside the United States, only to non-U.S. investors. The offer and sale of the Notes have not been registered under the Securities Act, or under any state securities laws, and the Notes may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements under the Securities Act and applicable state securities laws.

PG&E Corporation has agreed to file a registration statement with the Securities and Exchange Commission relating to an offer to exchange the Notes for publicly tradable notes having substantially identical terms to the Notes. In addition, PG&E Corporation may be required to file a shelf registration statement covering resales of the Notes.

ITEM 3:3. DEFAULTS UPON SENIOR SECURITIES

At the time of the Utility's Chapter 11 filing on April 6, 2001, the Utility had defaulted on $873 million of commercial paper outstanding and had drawn and had outstanding $938 million under its bank credit facility, which was also in default. As authorized by the ~~Bankruptcy Court,~~bankruptcy court, starting in May 2002, the Utility has made past due and current interest payments on its commercial paper and bank credit facility.

With regard to certain pollution control bond-related debt of the Utility, the Utility ~~has been in default~~had defaulted under the credit agreements with the banks that provide letters of credit as credit and liquidity support for the underlying pollution control bonds. These defaults included the Utility's non-payment of other debt in excess of $100 million, the Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code, and non-payment of interest. As a result of these defaults, several of the letters of credit banks caused the acceleration and redemption of four series of pollution control bonds. All of these redemptions were funded by the letters of credit ~~banks, resulting in loans from the banks to the Utility, which have not been paid.~~banks. The total principal of the bonds (and related loans) accelerated and redeemed in April and May 2001 was $454 million. As authorized by the Bankruptcy Court, starting in May 2002, the Utility ~~has~~ made past-due and current interest ~~payments~~payment s on these loans.

In 2002, the Utility paid advances and interest on advances to banks providing letters of credit on pollution control bonds series 96C, 96E, 96F, and 97B. As authorized by the ~~Bankruptcy Court,~~bankruptcy court, starting in June 2002, the Utility ~~has~~also paid past-due interest advances and ~~is paying current~~ monthly interest. As authorized by the ~~Bankruptcy Court,~~bankruptcy court, the Utility also made semi-annual interest payments on pollution control bond series 96A backed by bond insurance. With regard to certain pollution control bond-related debt of the Utility backed by the Utility's mortgage bonds, an event of default ~~has~~ occurred under the relevant loan agreements with the California Pollution Control Financing Authority due to the Utility's Chapter 11 filing. ~~However, the~~The Utility ~~has~~ obtained ~~Bankruptcy Court~~bankruptcy court approval to make regular payments on its mortgage bonds and consequently the debt service payments on these bonds ~~are~~were passed through to the pollution control ~~bondholders.~~bondholders .

The Utility's filing of a Chapter 11 petition also ~~constitutes~~constituted a default under the indenture that ~~governs~~governed its medium-term notes ($287 million aggregate amount outstanding), five-year ~~7.375 percent~~7.375% senior notes ($680 million aggregate amount outstanding), and floating rate notes ($1.24 billion aggregate amount outstanding). As authorized by the ~~Bankruptcy Court,~~bankruptcy court, starting in May 2002, the Utility ~~has made~~paid past-due and current interest payments on its medium-term notes, its ~~7.375 percent~~7.375% senior notes, and its $1.24 billion floating rate notes. The Utility did not make a principal payment of $1.24 billion on its 364-day floating rate notes at maturity.

~~The~~ At March 31, 2004, the Utility ~~has~~had not made principal payments on unsecured long-term debt of $155 million.

With regard to the ~~7.90 percent~~7.90% Quarterly Income Preferred Securities, ~~(QUIPS)~~or QUIPS, and the related ~~7.90 percent~~7.90% Deferrable Interest Debentures, ~~(Debentures),~~or Debentures, the Utility's filing of a Chapter 11 petition iswas an event of default under the applicable indenture. Pursuant to the related trust agreement, the trustee was required to take steps to liquidate the trust and distribute the Debentures to the QUIPS holders. Pursuant to the trustee's notice dated April 24, 2002, the trust was liquidated on May 24, 2002. Upon liquidation of the trust, the former holders of QUIPS received a like amount of ~~7.90 percent~~7.90% Deferrable Interest Subordinated Debentures, ~~(QUIDS).~~or QUIDS. As authorized by the ~~Bankruptcy Court,~~bankruptcy court, starting in May 2002, the Utility ~~has~~ made past-due and current interest payments on the QUIDS. ~~See Note 2 of the Notes to the Consolidated Financial Statements for more information.~~

The Utility has authorized 75 million shares of First Preferred Stock ($25 par value) and 10 million shares of $100 First Preferred Stock ($100 par value), which may be issued as redeemable or non-redeemable preferred stock. (The Utility has not issued any $100 First Preferred Stock.) At ~~September 30, 2003,~~March 31, 2004, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock and 5,973,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 3 million shares of the ~~6.57 percent~~6.57% series and 2.5 million shares of the ~~6.30 percent~~6.30% series at ~~September 30, 2003.~~March 31, 2004. At the Utility's option, the ~~6.57 percent~~6.57% series may be redeemed ~~beginning~~b eginning 2002 and the ~~6.30 percent~~6.30% series may be redeemed ~~beg inning~~beginning in 2004 at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. At ~~September 30, 2003,~~March 31, 2004, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions ~~were~~are approximately $4 million per year for 2002, 2003, and 2004 for the ~~6.57 percent~~6.57% series, and $3 million per year beginning 2004 for the ~~6.30 percent~~6.30% series. The Utility is not permitted to make sinking fund payments unless all dividends on preferred stock have been paid. As discussed below, through March 31, 2004, the Utility's Board of Directors ~~has~~did not ~~declared~~declare any preferred stock dividends since the dividend paid with respect to the period ended October 31, 2000. Therefore, the $4 million sinking fund payments that were due on July 31, 2002, and July 31, 2003 to redeem 150,000 ~~shares~~sha res per sinking fund payment of the ~~6.57 percent~~6.57% series were not made. The sinking fund payments are cumulative so that if on July 31 of any given year, the sinking fund payment is not made, the remaining shares of the ~~6.57 percent~~6.57% series required to be redeemed must be redeemed before the Utility can issue any shares of another series with a required sinking fund, unless the redemption of shares of both series is pro rata.

Holders of the Utility's non-redeemable ~~5.0 percent, 5.5 percent,~~5.0%, 5.5%, and ~~6.0 percent~~6.0% series of preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

Due to the California energy crisis and the Utility's pending Chapter 11 proceeding, the Utility's Board of Directors has not declared any preferred stock dividends since the dividend paid with respect to the three-month period ended October 31, 2000.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Accumulated and unpaid dividends through ~~September 30, 2003,~~March 31, 2004, amounted to ~~$69.6 million.~~$82.2million. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Until cumulative dividends and cumulative sinking fund payments on its preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock.

Under the ~~proposed settlement agreement in the Utility's Chapter 11 proceeding, there would be no restrictions on the ability of the Boards of Directors of~~Settlement Agreement, the Utility or PG&E Corporation to declare and pay dividends or repurchase common stock, other than the capital structure and stand-alone dividend conditions contained in prior CPUC decisions authorizing the formation of the holding company. Further, the Utility would agreehas agreed that it would not pay any dividend on its common stock before July 1, 2004.

On April 12, 2004, the Utility's Plan of Reorganization became effective. In addition to other payments, the Utility paid approximately $83 million in preferred stock dividends and made sinking fund payments of approximately $10 million that were in arrears. The Utility's various series of preferred stock remain outstanding. The preferred stock has an aggregate par value of approximately $421 million, excluding the par value of the shares of 6.57% and 6.30% series of preferred stock that were redeemed on April 12, 2004.

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

PG&E Corporation:

On April 21, 2004, PG&E Corporation held its annual meeting of shareholders. At the meeting, the shareholders voted as indicated below on the following matters:

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

For

Withheld
David R. Andrews
282,510,885

14,637,181
Leslie S. Biller
286,911,290

10,236,776
David A. Coulter
284,020,634

13,127,432
C. Lee Cox
285,211,839

11,936,227
Robert D. Glynn, Jr.
285,114,172

12,033,894
David M. Lawrence, MD
285,325,514

11,822,552
Mary S. Metz
286,173,133

10,974,933
Barry Lawson Williams
285,712,467

11,435,599

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2004 (included as Item 2 in the proxy statement):

For:
289,950,135
Against:
4,308,251
Abstain:
2,889,680

The 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 a shareholder proposal regarding poison pills (included as Item 3 in the proxy statement):

For:
144,811,801
Against:
80,689,110
Abstain:
4,869,520
Broker non-vote⁽¹⁾:
66,777,635

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.

4. Consideration of a shareholder proposal regarding golden parachutes (included as Item 4 in the proxy statement):

For:
104,738,906
Against:
119,653,869
Abstain:
5,977,656
Broker non-vote⁽¹⁾:
66,777,635

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.

5. Consideration of a shareholder proposal regarding link-free directors (included as Item 5 in the proxy statement):

For:
34,210,874
Against:
191,266,280
Abstain:
4,893,277
Broker non-vote⁽¹⁾:
66,777,635

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

For:
22,744,297
Against:
188,391,757
Abstain:
19,234,377
Broker non-vote⁽¹⁾:
66,777,635

7. Consideration of a shareholder proposal regarding separation of the positions of Chairman of the Board and Chief Executive Officer (included as Item 7 in the proxy statement):

For:
83,424,376
Against:
142,549,868
Abstain:
4,396,187
Broker non-vote⁽¹⁾:
66,777,635

8. Consideration of a shareholder proposal regarding executive compensation (included as Item 8 in the proxy statement):

For:
23,405,818
Against:
202,126,494
Abstain:
4,838,119
Broker non-vote⁽¹⁾:
66,777,635

(1) A non-vote occurs when a broker or other nominee holding shares for a beneficial owner indicates a vote on one or more proposals, but does not indicate a vote on other proposals because the broker or other nominee does not have discretionary voting power as to such proposals and has not received voting instructions from the beneficial owner as to such proposals.

Pacific Gas and Electric Company:

On April 21, 2004, Pacific Gas and Electric Company (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 subsidiary voted all of their respective shares of common stock for the nominees named in the 2004 joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2004. The balance of the votes shown below were cast by holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters:

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

For

Withheld
David R. Andrews
325,831,957

657,306
Leslie S. Biller
326,357,142

132,121
David A. Coulter
326,356,927

132,336
C. Lee Cox
326,358,602

130,661
Robert D. Glynn, Jr.
326,349,700

139,563
David M. Lawrence, MD
326,370,148

119,115
Mary S. Metz
326,355,815

133,448
Gordon R. Smith
326,365,803

123,460
Barry Lawson Williams
326,280,139

209,124

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2004 (included as Item 2 in the proxy statement):

For:
326,417,068
Against:
37,181
Abstain:
35,014

ITEM 5:5. 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's~~ The Utility's earnings to fixed charges ratio for the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, was ~~2.98. Pacific Gas and Electric Company's~~24.63. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the ~~nine~~three months ended ~~September 30, 2003,~~March 31, 2004, was ~~2.87.~~22.85. 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 ~~33-64136, 33-50707,~~ and ~~33-61959,~~333-10994 relating to ~~Pacific Gas and Electric Company's~~ various ~~classes~~series of ~~debt and~~the Utility's first preferred stock ~~outstanding.~~and its senior secured bonds, respectively.

PG&E Corporation's earnings to fixed charges ratio for the three months ended March 31, 2004, was 20.87. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibits 12.3 hereto, is included herein for the purpose of incorporating such information and exhibit into PG&E Corporation's Registration Statement No. 333-114923 relating to its senior secured notes.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

~~(a)~~

~~4.1~~(a) Exhibits:

1.1	~~Indenture~~Underwriting Agreement, dated ~~as of July 2, 2003 by~~March 18, 2004, between Pacific Gas and ~~between PG&E Corporation~~Electric Company and ~~Bank One, N.A.~~Lehman Brothers Inc. and UBS Securities LLC (incorporated by reference to PG&E ~~Corporation's~~Corporation and Pacific Gas and Electric Company's Form 8-K filed ~~July 2, 2003 (File No. 1-12609),~~March 23, 2004, Exhibit ~~4.1)~~ 1.1)
3.1	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 3)
3.2	Bylaws of PG&E Corporation dated as of April 21, 2004
3.3	Bylaws of Pacific Gas and Electric Company dated as of April 21, 2004
4.1	Amendment of Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed February 19, 2004, Exhibit 99)
4.2	~~Utility Stock Base Pledge Agreement~~Indenture of Mortgage, dated as of ~~July 2, 2003 by~~March 11, 2004, between Pacific Gas and ~~among PG&E Corporation, Bank One, N.A.~~Electric Company and ~~Deutsche Bank~~BNY Western Trust Company ~~Americas~~ (incorporated by reference to PG&E ~~Corporation's~~Corporation and Pacific Gas and Electric Company's Form 8-K filed ~~July 2, 2003 (File No. 1-12609)~~March 23, 2004), Exhibit ~~4.2)~~4.1)
4.3	~~Utility Stock Protective Pledge Agreement~~First Supplemental Indenture, dated as of ~~July 2, 2003 by~~March 23, 2004, between Pacific Gas and ~~among PG&E Corporation, Bank One, N.A.~~Electric Company and ~~Deutsche Bank~~BNY Western Trust Company ~~Americas~~ (incorporated by reference to PG&E ~~Corporation's~~Corporation and Pacific Gas and Electric Company's Form 8-K filed ~~July 2, 2003 (File No. 1-12609),~~March 23, 2004, Exhibit ~~4.3)~~4.2)
4.4	~~Form~~Second Supplemental Indenture, dated as of ~~6⅞ percent Senior Secured Note due 2008~~April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E ~~Corporation's~~Corporation and Pacific Gas and Electric Company's Form 8-K filed ~~July 2, 2003 (File No. 1-12609),~~April 12, 2004, Exhibit 4)
4.5	Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.3)
4.6	Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.4)
10.1	Credit Agreement dated as of March 5, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004, 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
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

* Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

(b)	The following Current Reports on Form 8-K⁽¹⁾ were filed, or furnished as indicated, during the first quarter of 2004 and through the date hereof:

1. January 22, 2004
Item 5.
Other Events
Applications Filed for Rehearing of CPUC Decision
Approving Chapter 11 Settlement Agreement
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits:
Exhibit 99 - Notice to Directors and ExecutiveOfficers, dated January 22, 2004
Item 11.
Temporary Suspension of Trading Under Registrant's
Employee Benefits Plan
2. February 3, 2004
Item 5.
Other Events
Implementation of Chapter 11 Settlement Rate Reduction
3. February 19, 2004
Item 5.
Other Events and Regulation FD Disclosure
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits:
Exhibit 99 - Amendment to Rights Agreement dated February 18, 2004,
between PG&E Corporation andMellon Investor Services LLC
Item 12.
Results of Operations and Financial Condition (furnished to the SEC)
Release of Third Quarter Earnings Results
4. March 2, 2004
Item 5.
Other Events and Regulation FD Disclosure
A. Electric Rate Reduction
B. Reclassification of Estimated Costs of Removal and Decommissioning Obligations at December 31, 2002.
C. Controls and Procedures
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits
Exhibit 23 - Independent Auditors' Consent (Deloitte & Touche LLP)
Exhibit 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
Exhibit 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
Exhibit 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 (furnished to the SEC)
Exhibit 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 (furnished to the SEC)
Exhibit 99.1 - This exhibit is comprised of the following portions of the revised 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Stockholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," "Consolidated Statements of Stockholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)"
Exhibit 99.2 - Financial Statement Schedules and Independent Auditors' Report (Deloitte & Touche LLP)
Exhibit 99.3 - Pacific Gas and Electric Company's Income Statement for the month ended January 31, 2004 and Balance Sheet dated January 31, 2004 (furnished to the SEC)
Item 9.
Regulation FD Disclosure
5. March 10, 2004
Item 5.
Other Events and Regulation FD Disclosure
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits
Exhibit 99 - Credit Agreement dated as of March 5, 2004
6. March 12, 2004
Item 5.
Other Events and Regulation FD Disclosure
A. Rating Agency Actions
B. Status Conference Statement
7. March 16, 2004
Item 5.
Other Events and Regulation FD Disclosure
8. March 18, 2004
Item 5.
Other Events and Regulation FD Disclosure
9. March 23, 2004
Item 5.
Other Events and Regulation FD Disclosure
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits
Exhibit 1.1 - Underwriting Agreement, dated March 18, 2004, between Pacific Gas and Electric Company and Lehman Brothers Inc. and UBS Securities LLC (annexes omitted).
Exhibit 4.1 - Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
Exhibit 4.2 - First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
Exhibit 4.3 - Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (Exhibit B omitted).
Exhibit 4.4 - Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
Exhibit 5.1 - Opinion of Orrick, Herrington & Sutcliffe LLP, dated March 23, 2004, regarding the First Mortgage Bonds.
Exhibit 5.2 - Opinion of Orrick, Herrington & Sutcliffe LLP, dated March 23, 2004, regarding the unsold Senior Secured Bonds.
Exhibit 23.2 - Consent of Orrick, Herrington & Sutcliffe LLP (included as part of their opinions filed herewith).
10. March 26, 2004
Item 5.
Other Events and Regulation FD Disclosure
11. March 31, 2004
Item 5.
Other Events and Regulation FD Disclosure
Item 9.
Regulation FD Disclosure - Pacific Gas and Electric Company's Income Statement for the month ended February 29, 2004 and Balance Sheet dated February 29, 2004 (furnished to the SEC)
12. April 7, 2004
Item 5.
Other Events and Regulation FD Disclosure
A. Pacific Gas and Electric Company's 2003 General Rate Case
B. Pacific Gas and Electric Company's Chapter 11 Proceeding
13. April 12, 2004
Item 5.
Other Events and Regulation FD Disclosure
Pacific Gas and Electric Company's Chapter 11 Proceeding
14. April 12, 2004
Item 5.
Other Events and Regulation FD Disclosure
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits
Exhibit 3 - Restated Articles of Incorporation of Pacific Gas and Electric Company
Exhibit 4 - Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company
15. April 19, 2004
Item 5.
Other Events and Regulation FD Disclosure
16. April 27, 2004
Item 5.
Other Events and Regulation FD Disclosure
Pro forma financial information
17. May 4, 2004
Item 12.
Results of Operation and Financial Condition (furnished to the SEC)
Release of First Quarter Earnings Results
(1) Unless otherwise noted, all reports were filed or furnished under Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (Pacific Gas and Electric Company).

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: May 4, 2004

EXHIBIT INDEX

1.1	Underwriting Agreement, dated March 18, 2004, between Pacific Gas and Electric Company and Lehman Brothers Inc. and UBS Securities LLC (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 1.1)
3.1	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 3)
3.2	Bylaws of PG&E Corporation dated as of April 21, 2004
3.3	Bylaws of Pacific Gas and Electric Company dated as of April 21, 2004
4.1	Amendment of Rights Agreement dated February 18, 2004 between PG&E Corporation and Mellon Investor Services LLC (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed February 19, 2004, Exhibit 99)
4.2	Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.1)
4.3	First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.2)
4.4	Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 4)
4.5	Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.3)
4.6	Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004, Exhibit 4.4)
10.1	Credit Agreement dated as of March 5, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004, 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
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

* Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

~~(b)~~

~~The following Current Reports on Form 8-K~~⁽¹⁾ ~~were filed, or furnished as indicated, during the third quarter of 2003 and through the date hereof:~~

~~1. July 2, 2003~~
         ~~PG&E Corporation and NEGT, Inc.~~
~~Item 5.~~
~~Other Events~~
~~Extension of GenHoldings Transfer Date~~
~~Settlement of DTE/Georgetown Tolling Dispute~~
~~Item 7.~~
~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
~~Exhibit 99.1 - Termination Agreement, dated as of June 24, 2003, by and between PG&E Energy Trading-Power, L.P., PG&E Gas Transmission, Northwest Corporation, and DTE Georgetown, LLC~~
~~2. July 2, 2003~~
         ~~PG&E Corporation only~~
~~Item 5.~~
~~Other Events~~
~~Closing of Private Placement~~
~~Item 7.~~
~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
~~Exhibit 4.1 - Indenture dated as of July 2, 2003 by and between PG&E Corporation and Bank One, N.A.~~
~~Exhibit 4.2 - Utility Stock Base Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas~~
~~Exhibit 4.3 - Utility Stock Protective Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas~~
~~Exhibit 4.4 - Form of 6⅞ percent Senior Secured Note due 2008~~
~~3. July 2, 2003~~
         ~~PG&E Corporation only~~
~~Item 5.~~
~~Other Events~~
~~Press Release Regarding Closing of Private Placement~~
~~Item 7.~~
~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
~~Exhibit 99 - Press release dated July 2, 2003~~
~~4. July 8, 2003~~
         ~~PG&E Corporation only~~
~~Item 5.~~
~~Other Events~~
~~PG&E National Energy Group, Inc. Bankruptcy~~
~~5. July 8, 2003~~
~~Item 5.~~
~~Other Events~~
~~Proposed Settlement Agreement~~
~~Credit Ratings~~
~~Item 9.~~
~~Regulation FD Disclosure (furnished to the SEC)~~
~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended May 31, 2003 and Balance Sheet dated May 31, 2003~~
~~Exhibit 2 - Exhibit C to Disclosure Statement~~
~~6. August 14, 2003~~
~~Item 5.~~
~~Other Events~~
~~Inability to File Form 10-Q by August 14, 2003~~
~~7. August 19, 2003~~
~~Item 12.~~
~~Results of Operation and Financial Condition (furnished to SEC)~~
~~Release of Second Quarter Earnings Results~~
~~8. August 25, 2003~~
~~Item 5.~~
~~Other Events~~
~~California Supreme Court Decision~~
~~California Department of Water Resources' 2003 Revenue Requirement~~
~~9. September 3, 2003~~
~~Item 5.~~
~~Other Events~~
~~Settlement Conference in 2003 General Rate Case Proceeding~~
~~Item 9.~~
~~Regulation FD Disclosure (furnished to the SEC)~~
~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2003 and Balance Sheet dated July 31, 2003~~
~~10. September 10, 2003~~
~~Item 5.~~
~~Other Events~~
~~California Department of Water Resources' 2003 Revenue Requirement~~
~~Utility's Bankruptcy Proceeding~~
~~PG&E National Energy Group, Inc. Bankruptcy~~
~~11. September 16, 2003~~
~~Item 5.~~
~~Other Events~~
~~Pacific Gas and Electric Company's 2003 General Rate Case Proceeding~~
~~Item 9.~~
~~Regulation FD Disclosure (furnished to the SEC)~~
~~12.October 3, 2003~~
~~Item 9.~~
~~Regulation FD Disclosure (furnished to the SEC)~~
~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003~~
~~13.October 15, 2003~~
~~Item 5.~~
~~Other Events~~
~~Item 9.~~
~~Regulation FD Disclosure (furnished to the SEC)~~
~~Exhibit 1 - Revised Financial Projections Relating to the Settlement Plan~~
~~14. October 24, 2003~~
~~Item 5.~~
~~Other Events~~
~~Credit Rating Change~~
~~Department of Water Resources' 2001-2002 Revenue Requirement True-Up Proceeding~~
~~15. November 12, 2003~~
~~Item 12.~~
~~Results of Operation and Financial Condition (furnished to the SEC)~~
~~Release of Third Quarter Earnings Results~~

~~(1) Unless otherwise noted, all reports were filed or furnished under Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (Pacific Gas and Electric Company).~~

~~SIGNATURES~~

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

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

~~Dated: November 12, 2003~~

~~EXHIBIT INDEX~~

~~4.1~~	~~Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.1)~~
~~4.2~~	Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2)
~~4.3~~	Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3)
~~4.4~~	~~Form of 6⅞ percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4)~~
11	~~Computation of Earnings Per Common Share~~
~~12.1~~	~~Computation 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~~

* Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

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

(in millions, except per share amounts)						Three months ended					Nine months ended
						September 30,					September 30,

						2003		2002			2003		2002

Operating Revenues
		Electric				$	2,524	$		2,483	$	5,823	$	6,454
		Natural gas				579		464			2,074		1,654

				Total operating revenues		3,103		2,947			7,897		8,108

Operating Expenses
		Cost of electricity				679		550			1,725		874
		Cost of natural gas				233		108			1,010		586
		Operating and maintenance				690		865			2,110		2,280
		Depreciation, amortization, and decommissioning				312		314			910		881
		Reorganization professional fees and expenses				16		41			116		75

				Total operating expenses		1,930		1,878			5,871		4,696

Operating Income						1,173		1,069			2,026		3,412
		Reorganization interest income				9		17			36		58
		Interest income				6		3			13		2
		Interest expense				(342)		(371)			(857)		(971)
		Other income (expense), net				(5)		60			(10)		59

Income Before Income Taxes						841		778			1,208		2,560
		Income tax provision				333		299			454		1,028

Income From Continuing Operations						508		479			754		1,532
Discontinued Operations
	Gain/(Loss) from operations of NEGT, Inc.
			(net of income tax benefit of $10 million and $85 million for the three months ended September 30, 2003, and 2002, and $230 million and $257 million for the nine months ended September 30, 2003, and 2002)
						2		(13)			(365)		(156)

Net Income Before Cumulative Effect of Changes
	in Accounting Principles					510		466			389		1,376
	Cumulative effect of changes in accounting principles, $(8) million and $(103) million related to discontinued operations for the nine months ended September 30, 2003 and 2002 (net of income tax benefit of $4million and $42 million for the nine months ended September 30, 2003, and 2002)				-			-			(6)		(61)

Net Income						$	510	$	466		$	383	$	1,315



Weighted Average Common Shares Outstanding, Basic						387		373			384		368

Earnings Per Common Share
	from Continuing Operations, Basic					$	1.31	$	1.28		$	1.96	$	4.16



Net Earnings Per Common Share, Basic						$	1.32	$	1.25		$	1.00	$	3.57



Earnings Per Common Share
	from Continuing Operations, Diluted					$	1.24	$	1.22		$	1.86	$	4.06



Net Earnings Per Common Share, Diluted						$	1.24	$	1.19		$	0.96	$	3.49




See accompanying Notes to the Condensed Consolidated Financial Statements.

			Three months ended				Nine months ended
			September 30, 2003				September 30, 2003

			PG&E				PG&E
			Corporation⁽¹⁾		Utility		Corporation⁽¹⁾		Utility

Net income available for common stock			$	510	$	583	$	383	$	843
Continuing operations
	Foreign currency translation adjustment		-		-		3		-
	Retirement plan remeasurement (Note 8)		-		-		(60)		(60)

	Comprehensive income from continuing operations		510		583		326		783
Discontinued operations (Note 4)
	Net loss in other comprehensive income (OCI)
		from current period hedging transactions and price
		changes in accordance with SFAS No. 133	-		-		(5)		-
	Net reclassification from OCI to earnings		2		-		17		-
	Other		1		-		1		-

	Comprehensive income from discontinued operations		3		-		13		-

Total comprehensive income			$	513	$	-	$	339	$	783




(1)	Includes other comprehensive income of NEGT, Inc. prior to July 8, 2003, after which PG&E Corporation accounts for NEGT, Inc. using the cost method of accounting.

		Three months ended				Nine months ended
		September 30, 2002				September 30, 2002

		PG&E				PG&E
		Corporation		Utility		Corporation		Utility

Net income available for common stock		$	466	$	520	$	1,315	$	1,573
Net loss in other comprehensive income (OCI)
	from current period hedging transactions and price
	changes in accordance with SFAS No. 133	(153)		-		(237)		-
Net reclassification from OCI to earnings		(2)		-		3		-
Foreign currency translation adjustment		-		-		3		2

Total comprehensive income		$	311	$	520	$	1,084	$	1,575

	Three months ended September 30,				Nine months ended September 30,				Receivable (Payable) Balance Outstanding at
(in millions)									September 30,		December 31,

	2003		2002		2003		2002		2003		2002

Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	3	$	6	$	6	$	1	$	1
Natural gas transmission capacity services provided to NEGT ET	2		2		6		8		1		-
Contribution in aid of construction received from NEGT, Inc.	-		-		-		-		-		3
Trade deposit due from GTNW	-		-		3		-		15		12
Utility expenses from:
Administrative services received from PG&E Corporation	$	40	$	16	$	137	$	66	$	(376)	$	(289)
Interest accrued on pre-petition liability due to PG&E Corporation	2		-		5		-		(2)		(2)
Administrative services received from NEGT, Inc.	-		-		2		-		(1)		(2)
Software purchases from NEGT ET	-		-		1		-		-		-
Gas commodity services received from NEGT ET	-		5		10		33		-		(26)
Gas transportation services received from GTNW	14		11		43		33		(8)		(8)
Trade deposit due to NEGT ET	(6)		-		(5)		-		(2)		(7)

(in millions)	Amount Owed		Agreed Upon Interest Rate at September 30, 2003 (per annum)


Commercial Paper Claims	$	873	8.216%
Floating Rate Notes	1,240		8.333%
Senior Notes	680		10.375%
Medium-Term Notes	287		6.560% to 9.200%
Revolving Line of Credit Claims	938		8.750%
Pollution Control Bonds	814		1.230% to 5.350%
QFs	52		5.000%
Other Claims	4,617		3.100% to 12.000%

Liabilities Subject to Compromise at September 30, 2003	$	9,501

	Seven days ended July 7,		Three months ended September 30,		188 Days ended July 7,		Nine months ended September 30,

(in millions)	2003		2002		2003		2002

Operating Revenues	$	35	$	524	$	786	$	1,390
Loss Before Income Taxes	(8)		(98)		(595)		(413)

	~~Balance at~~

~~(in millions)~~	~~December 31,~~ ~~2002~~

~~Assets~~
~~Total current assets~~	$			~~3,029~~
~~Net property, plant and equipment~~	~~2,939~~
~~Total other non-current assets~~	~~1,944~~

~~Total assets~~	~~7,912~~


~~Liabilities~~
~~Debt in default~~			~~4,230~~
~~Long-term debt, classified as current~~	17
~~Other current liabilities~~	~~2,410~~

~~Total current liabilities~~	~~6,657~~

~~Long-term debt~~	~~630~~
~~Price risk management~~	~~305~~
~~Other non-current liabilities and deferred credits~~		~~972~~

~~Total non-current liabilities~~		~~1,907~~

~~Total liabilities~~		~~8,564~~

~~Excess of liabilities over assets~~		$		~~(652)~~

(in millions)		Gross Credit Exposure Before Credit Collateral⁽¹⁾		Credit Collateral		Net Credit Exposure⁽²⁾		Number of Counterparties >10 percent	Net Exposure of Counterparties >10 percent


September 30, 2003 ⁽³⁾		$	141	$	8	$	133	4	$	76
December 31, 2002		288		113		175		2	55

(1)	Gross credit exposure equals mark-to-market value, notes receivable, and net (payables) receivables where netting is 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 incurred prior to the Utility's Chapter 11 filing 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.
(3)	Excludes post-petition exposures to Enron.

(in millions)	Operations & Maintenance		Debt Service

2003	$	11	$	7
2004	41		28
2005	35		26
2006	31		26
2007	30		27
Thereafter	214		168

Total	$	362	$	282


(in millions)		Utility		PG&E Corporation, Eliminations and Other⁽¹⁾			Total

Three months ended September 30, 2003
Operating revenues		$	3,103	$	-		$	3,103
Intersegment revenues		-		-			-

Total operating revenues		3,103		-			3,103
Income (Loss) from continuing operations⁽²⁾		583		(75)			508
Net income (loss)⁽³⁾		583		(73)			510

Three months ended September 30, 2002
Operating revenues		2,947		-			2,947
Intersegment revenues		2		(2)			-

Total operating revenues		2,949		(2)			2,947
Income (Loss) from continuing operations⁽²⁾		520		(41)			479
Net income (loss)⁽³⁾		520		(54)			466

Nine months ended September 30, 2003
Operating revenues		7,897		-			7,897
Intersegment revenues		3		(3)			-

Total operating revenues		7,900		(3)			7,897
Income (Loss) from continuing operations⁽²⁾		844		(90)			754
Net income (loss)⁽³⁾		843		(460)			383

Nine months ended September 30, 2002
Operating revenues		8,108		-			8,108
Intersegment revenues		8		(8)			-

Total operating revenues		8,116		(8)			8,108
Income (Loss) from continuing operations⁽²⁾		1,573		(41)			1,532
Net income (loss)⁽³⁾		1,573		(258)			1,315

Total assets at September 30, 2003		$	26,850	$		910	$	27,760

Total assets at September 30, 2002		$	24,942	$		11,693	$	36,635

(1)	Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries. PG&E Corporation's net income (loss) includes the results of NEGT, Inc.'s discontinued operations through July 7, 2003, and the elimination of $160 million for the nine-month period ended September 30, 2003, of deferred tax asset valuation reserves recorded at NEGT, Inc. PG&E Corporation believes it is more likely than not that it will be able to realize these deferred tax assets on a consolidated basis.
(2)	Corresponds to the Utility's Income Available for Common Stock excluding Cumulative Effect of a Change in Accounting Principle.
(3)	Corresponds to the Utility's Income Available for Common Stock.

(in millions)		Utility		PG&E Corporation, Eliminations and Other⁽¹⁾		Total


Three months ended September 30, 2003
Operating revenues		$	3,103	$	-	$	3,103
Operating expenses			1,908		22	1,930

Operating income (loss)		$	1,195	$	(22)	1,173



Interest income						15
Interest expense						(342)
Other income (expenses), net						(5)

Income before income taxes						841
Income taxes						333

Income from continuing operations						508

Net income						$	510




Three months ended September 30, 2002⁽²⁾
Operating revenues		$	2,949	$	(2)	$	2,947
Operating expenses			1,890		(12)	1,878

Operating income		$	1,059	$	10	1,069



Interest income						20
Interest expense						(371)
Other income, net						60

Income before income taxes						778
Income taxes						299

Income from continuing operations						479

Net income						$	466




Nine months ended September 30, 2003⁽²⁾
Operating revenues		$	7,900	$	(3)	$	7,897
Operating expenses			5,901		(30)	5,871

Operating income		$	1,999	$	27	2,026



Interest income						49
Interest expense						(857)
Other income (expenses), net						(10)

Income before income taxes						1,208
Income taxes						454

Income from continuing operations						754

Net income						$	383




Nine months ended September 30, 2002⁽²⁾
Operating revenues		$	8,116	$	(8)	$	8,108
Operating expenses			4,750		(54)	4,696

Operating income		$	3,366	$	46	3,412



Interest income						60
Interest expense						(971)
Other income, net						59

Income before income taxes						2,560
Income taxes						1,028

Income from continuing operations						1,532

Net income						$	1,315




(1)	PG&E Corporation eliminates all inter-segment transactions in consolidation.
(2)	Prior period amounts of NEGT, Inc. have been reclassified to discontinued operations.

			Three months ended		Nine months ended
(in millions)			September 30		September 30

PG&E Corporation
	Interest expense	$	44	$	33

Utility
	Electric revenues		41		(631)
	Natural gas revenues		113		415
	Cost of electricity		(124)		(841)
	Cost of natural gas		(114)		(407)
	Operating and maintenance expenses		191		174
	Depreciation, amortization and decommissioning		4		(36)
	Reorganization professional fees and expenses		25		(41)
	Interest and other income, net		(5)		(2)
	Interest expense		(16)		86

	For	Withheld


David R. Andrews	282,510,885	14,637,181
Leslie S. Biller	286,911,290	10,236,776
David A. Coulter	284,020,634	13,127,432
C. Lee Cox	285,211,839	11,936,227
Robert D. Glynn, Jr.	285,114,172	12,033,894
David M. Lawrence, MD	285,325,514	11,822,552
Mary S. Metz	286,173,133	10,974,933
Barry Lawson Williams	285,712,467	11,435,599

For:	144,811,801
Against:	80,689,110
Abstain:	4,869,520
Broker non-vote⁽¹⁾:	66,777,635

For:	104,738,906
Against:	119,653,869
Abstain:	5,977,656
Broker non-vote⁽¹⁾:	66,777,635

For:	34,210,874
Against:	191,266,280
Abstain:	4,893,277
Broker non-vote⁽¹⁾:	66,777,635

For:	22,744,297
Against:	188,391,757
Abstain:	19,234,377
Broker non-vote⁽¹⁾:	66,777,635

For:	83,424,376
Against:	142,549,868
Abstain:	4,396,187
Broker non-vote⁽¹⁾:	66,777,635

For:	23,405,818
Against:	202,126,494
Abstain:	4,838,119
Broker non-vote⁽¹⁾:	66,777,635

	For	Withheld


David R. Andrews	325,831,957	657,306
Leslie S. Biller	326,357,142	132,121
David A. Coulter	326,356,927	132,336
C. Lee Cox	326,358,602	130,661
Robert D. Glynn, Jr.	326,349,700	139,563
David M. Lawrence, MD	326,370,148	119,115
Mary S. Metz	326,355,815	133,448
Gordon R. Smith	326,365,803	123,460
Barry Lawson Williams	326,280,139	209,124


1. January 22, 2004	Item 5.	Other Events
		Applications Filed for Rehearing of CPUC Decision
		Approving Chapter 11 Settlement Agreement
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits: Exhibit 99 - Notice to Directors and ExecutiveOfficers, dated January 22, 2004
	Item 11.	Temporary Suspension of Trading Under Registrant's Employee Benefits Plan

2. February 3, 2004	Item 5.	Other Events
		Implementation of Chapter 11 Settlement Rate Reduction

3. February 19, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits: Exhibit 99 - Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation andMellon Investor Services LLC
	Item 12.	Results of Operations and Financial Condition (furnished to the SEC) Release of Third Quarter Earnings Results

4. March 2, 2004	Item 5.	Other Events and Regulation FD Disclosure
		A. Electric Rate Reduction
		B. Reclassification of Estimated Costs of Removal and Decommissioning Obligations at December 31, 2002.
		C. Controls and Procedures
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 23 - Independent Auditors' Consent (Deloitte & Touche LLP)
		Exhibit 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
		Exhibit 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
		Exhibit 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 (furnished to the SEC)
		Exhibit 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 (furnished to the SEC)
		Exhibit 99.1 - This exhibit is comprised of the following portions of the revised 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Independent Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Stockholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," "Consolidated Statements of Stockholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)"
		Exhibit 99.2 - Financial Statement Schedules and Independent Auditors' Report (Deloitte & Touche LLP)
		Exhibit 99.3 - Pacific Gas and Electric Company's Income Statement for the month ended January 31, 2004 and Balance Sheet dated January 31, 2004 (furnished to the SEC)
	Item 9.	Regulation FD Disclosure

5. March 10, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 99 - Credit Agreement dated as of March 5, 2004

6. March 12, 2004	Item 5.	Other Events and Regulation FD Disclosure
		A. Rating Agency Actions
		B. Status Conference Statement

7. March 16, 2004	Item 5.	Other Events and Regulation FD Disclosure

8. March 18, 2004	Item 5.	Other Events and Regulation FD Disclosure

9. March 23, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 1.1 - Underwriting Agreement, dated March 18, 2004, between Pacific Gas and Electric Company and Lehman Brothers Inc. and UBS Securities LLC (annexes omitted).
		Exhibit 4.1 - Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
		Exhibit 4.2 - First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
		Exhibit 4.3 - Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (Exhibit B omitted).
		Exhibit 4.4 - Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company.
		Exhibit 5.1 - Opinion of Orrick, Herrington & Sutcliffe LLP, dated March 23, 2004, regarding the First Mortgage Bonds.
		Exhibit 5.2 - Opinion of Orrick, Herrington & Sutcliffe LLP, dated March 23, 2004, regarding the unsold Senior Secured Bonds.
		Exhibit 23.2 - Consent of Orrick, Herrington & Sutcliffe LLP (included as part of their opinions filed herewith).

10. March 26, 2004	Item 5.	Other Events and Regulation FD Disclosure

11. March 31, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 9.	Regulation FD Disclosure - Pacific Gas and Electric Company's Income Statement for the month ended February 29, 2004 and Balance Sheet dated February 29, 2004 (furnished to the SEC)

12. April 7, 2004	Item 5.	Other Events and Regulation FD Disclosure
		A. Pacific Gas and Electric Company's 2003 General Rate Case
		B. Pacific Gas and Electric Company's Chapter 11 Proceeding

13. April 12, 2004	Item 5.	Other Events and Regulation FD Disclosure
		Pacific Gas and Electric Company's Chapter 11 Proceeding

14. April 12, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 3 - Restated Articles of Incorporation of Pacific Gas and Electric Company
		Exhibit 4 - Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company

15. April 19, 2004	Item 5.	Other Events and Regulation FD Disclosure

16. April 27, 2004	Item 5.	Other Events and Regulation FD Disclosure Pro forma financial information

17. May 4, 2004	Item 12.	Results of Operation and Financial Condition (furnished to the SEC) Release of First Quarter Earnings Results

(1) Unless otherwise noted, all reports were filed or furnished under Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (Pacific Gas and Electric Company).

~~1. July 2, 2003~~
~~PG&E Corporation and NEGT, Inc.~~
	~~Item 5.~~	~~Other Events~~
		~~Extension of GenHoldings Transfer Date~~
		~~Settlement of DTE/Georgetown Tolling Dispute~~
	~~Item 7.~~	~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
		~~Exhibit 99.1 - Termination Agreement, dated as of June 24, 2003, by and between PG&E Energy Trading-Power, L.P., PG&E Gas Transmission, Northwest Corporation, and DTE Georgetown, LLC~~

~~2. July 2, 2003~~
~~PG&E Corporation only~~
	~~Item 5.~~	~~Other Events~~
		~~Closing of Private Placement~~
	~~Item 7.~~	~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
		~~Exhibit 4.1 - Indenture dated as of July 2, 2003 by and between PG&E Corporation and Bank One, N.A.~~
		~~Exhibit 4.2 - Utility Stock Base Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas~~
		~~Exhibit 4.3 - Utility Stock Protective Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas~~
		~~Exhibit 4.4 - Form of 6⅞ percent Senior Secured Note due 2008~~

~~3. July 2, 2003~~
~~PG&E Corporation only~~
	~~Item 5.~~	~~Other Events~~
		~~Press Release Regarding Closing of Private Placement~~
	~~Item 7.~~	~~Financial Statements, Pro Forma Financial Information, and Exhibits~~
		~~Exhibit 99 - Press release dated July 2, 2003~~

~~4. July 8, 2003~~
~~PG&E Corporation only~~
	~~Item 5.~~	~~Other Events~~
		~~PG&E National Energy Group, Inc. Bankruptcy~~

~~5. July 8, 2003~~	~~Item 5.~~	~~Other Events~~
		~~Proposed Settlement Agreement~~
		~~Credit Ratings~~
	~~Item 9.~~	~~Regulation FD Disclosure (furnished to the SEC)~~
		~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended May 31, 2003 and Balance Sheet dated May 31, 2003~~
		~~Exhibit 2 - Exhibit C to Disclosure Statement~~

~~6. August 14, 2003~~	~~Item 5.~~	~~Other Events~~
		~~Inability to File Form 10-Q by August 14, 2003~~

~~7. August 19, 2003~~	~~Item 12.~~	~~Results of Operation and Financial Condition (furnished to SEC)~~
		~~Release of Second Quarter Earnings Results~~

~~8. August 25, 2003~~	~~Item 5.~~	~~Other Events~~
		~~California Supreme Court Decision~~
		~~California Department of Water Resources' 2003 Revenue Requirement~~

~~9. September 3, 2003~~	~~Item 5.~~	~~Other Events~~
		~~Settlement Conference in 2003 General Rate Case Proceeding~~
	~~Item 9.~~	~~Regulation FD Disclosure (furnished to the SEC)~~
		~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2003 and Balance Sheet dated July 31, 2003~~

~~10. September 10, 2003~~	~~Item 5.~~	~~Other Events~~
		~~California Department of Water Resources' 2003 Revenue Requirement~~
		~~Utility's Bankruptcy Proceeding~~
		~~PG&E National Energy Group, Inc. Bankruptcy~~

~~11. September 16, 2003~~	~~Item 5.~~	~~Other Events~~
		~~Pacific Gas and Electric Company's 2003 General Rate Case Proceeding~~
	~~Item 9.~~	~~Regulation FD Disclosure (furnished to the SEC)~~

~~12.October 3, 2003~~	~~Item 9.~~	~~Regulation FD Disclosure (furnished to the SEC)~~
		~~Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003~~

~~13.October 15, 2003~~	~~Item 5.~~	~~Other Events~~
	~~Item 9.~~	~~Regulation FD Disclosure (furnished to the SEC)~~
		~~Exhibit 1 - Revised Financial Projections Relating to the Settlement Plan~~

~~14. October 24, 2003~~	~~Item 5.~~	~~Other Events~~
		~~Credit Rating Change~~
		~~Department of Water Resources' 2001-2002 Revenue Requirement True-Up Proceeding~~

~~15. November 12, 2003~~	~~Item 12.~~	~~Results of Operation and Financial Condition (furnished to the SEC)~~
		~~Release of Third Quarter Earnings Results~~