PACIFIC GAS & ELECTRIC CO - 10-Q Quarterly Report

Back to GetFilings.com

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

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

For the quarterly period ended September 30, 2002 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)				(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 the number of shares outstanding of each of the issuer's classes of common stock, as of latest practicable date.

Common Stock Outstanding, November 5, 2002:
PG&E Corporation			404,695,286 shares
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, 2002
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Consolidated Statements of Income		3
		Consolidated Balance Sheets		4
		Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company, A Debtor-In-Possession
		Consolidated Statements of Income		8
		Consolidated Balance Sheets		9
		Consolidated Statements of Cash Flows		11
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	12
	NOTE 2:		The Utility Chapter 11 Filing	19
	NOTE 3:		PG&E NEG's Liquidity and Financial Resources	34
	NOTE 4:		Debt Financing	42
	NOTE 5:		Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures	45
	NOTE 6:		Price Risk Management	46
	NOTE 7:		Commitments and Contingencies	50
	NOTE 8:		Impairment and Write-offs	60
	NOTE 9:		Segment Information	61

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			63
	Market Conditions and Business Environment			67
	Liquidity and Financial Resources			69
	Risk Management Activities			84
	Results of Operations			90
	Regulatory Matters			100
	Critical Accounting Policies			116
	Accounting Pronouncements Issued But Not Yet Adopted			116
	Taxation Matters			117
	Environmental and Legal Matters			117

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			119
ITEM 4.	CONTROLS AND PROCEDURES			119

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			120
ITEM 2.	CHANGES IN SECURITIES AND USE OF PROCEEDS			126
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES			126
ITEM 5.	OTHER INFORMATION			127
ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K			128

SIGNATURE AND CERTIFICATION				131

PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
					Three months ended					Nine months ended
					September 30,					September 30,
					-------------------------					-------------------------
					2002		2001			2002		2001
					-----------		-----------			-----------		-----------
Operating Revenues
		Utility			$	2,949	$		2,937	$	8,116	$	7,808
		Energy commodities and services			1,069		782			2,364		2,077
					------------		------------			------------		------------
				Total operating revenues	4,018		3,719			10,480		9,885
					------------		------------			------------		------------
Operating Expenses
		Cost of energy for utility			674		697			1,526		3,997
		Cost of energy commodities and services			745		462			1,564		1,119
		Operating and maintenance			1,063		713			2,819		2,293
		Impairments and write-offs			125		-			390		-
		Depreciation, amortization, and decommissioning			365		270			1,021		784
		Reorganization professional fees and expenses			41		25			75		33
					------------		------------			------------		------------
				Total operating expenses	3,013		2,167			7,395		8,226
					------------		------------			------------		------------
Operating Income					1,005		1,552			3,085		1,659
		Reorganization interest income			17		32			58		64
		Interest income			28		29			72		106
		Interest expense			(434)		(317)			(1,129)		(876)
		Other income (expense), net			64		(38)			61		(43)
					------------		------------			------------		------------
Income Before Income Taxes					680		1,258			2,147		910
		Income taxes provision			214		487			771		340
					------------		------------			------------		------------
Income From Continuing Operations					466		771			1,376		570
	Cumulative effect of a change in an accounting principle
			(net of income tax benefit of $42 million)		-		-			(61)		-
					------------		------------			------------		------------
Net Income					$	466	$	771		$	1,315	$	570
					=======		=======			=======		=======
Weighted Average Common Shares Outstanding					373		363			368		363
					------------		------------			------------		------------
Earnings Per Common Share,
	from Continuing Operations, Basic				$	1.25	$	2.12		$	3.74	$	1.57
					=======		=======			=======		=======
Net Earnings Per Common Share, Basic					$	1.25	$	2.12		$	3.57	$	1.57
					=======		=======			=======		=======
Earnings Per Common Share,
	from Continuing Operations, Diluted				$	1.19	$	2.12		$	3.65	$	1.57
					=======		=======			=======		=======
Net Earnings Per Common Share, Diluted					$	1.19	$	2.12		$	3.49	$	1.57
					=======		=======			=======		=======

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

PG&E CORPORATION
CONSOLIDATED BALANCE SHEETS
(In millions)

				Balance at
				----------------------------------------
				September 30,		December 31,
				2002		2001
				------------------		-----------------
ASSETS
Current Assets
	Cash and cash equivalents			$	4,485	$	5,421
	Restricted cash			395		195
	Accounts receivable:
		Customers (net of allowance for doubtful accounts of
			$100 million and $89 million, respectively)	3,283		3,148
		Regulatory balancing accounts		158		75
	Price risk management			615		427
	Inventories			491		462
	Prepaid expenses and other			354		149
				-----------------		----------------
		Total current assets		9,781		9,877
				-----------------		----------------
Property, Plant and Equipment
	Utility			26,773		25,963
	Non-utility:
		Electric generation		3,013		2,848
		Gas transmission		1,612		1,514
	Construction work in progress			3,121		2,402
	Other			201		195
				-----------------		----------------
		Total property, plant and equipment (at original cost)		34,720		32,922
	Accumulated depreciation and decommissioning			(14,363)		(13,831)
				-----------------		----------------
		Net property, plant and equipment		20,357		19,091
				-----------------		----------------
Other Noncurrent Assets
	Regulatory assets			2,096		2,319
	Nuclear decommissioning funds			1,311		1,337
	Price risk management			550		423
	Other			2,540		2,916
				-----------------		----------------
		Total other noncurrent assets		6,497		6,995
				-----------------		----------------
TOTAL ASSETS				$	36,635	$	35,963
				==========		==========

PG&E CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
			Balance at
			--------------------------------------
			September 30,			December 31,
			2002			2001
			------------------			-----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Short-term borrowings		$		431	$		330
	Long-term debt, classified as current		1,054			381
	Current portion of rate reduction bonds		290			290
	Accounts payable:
		Trade creditors	1,762			1,289
		Regulatory balancing accounts	442			360
		Other	662			530
	Interest payable		363			26
	Income taxes payable		756			610
	Price risk management		741			293
	Other		877			856
			----------------			----------------
		Total current liabilities	7,378			4,965
			----------------			----------------
Noncurrent Liabilities
	Long-term debt		6,736			7,297
	Rate reduction bonds		1,237			1,450
	Deferred income taxes		1,671			1,666
	Deferred tax credits		146			153
	Price risk management		836			436
	Other		3,573			3,688
			----------------			----------------
		Total noncurrent liabilities	14,199			14,690
			----------------			----------------
Liabilities Subject to Compromise
	Financing debt		5,606			5,651
	Trade creditors		3,330			5,555
			----------------			----------------
		Total liabilities subject to compromise	8,936			11,206
			----------------			----------------
Commitments and Contingencies (Notes 1, 2, 3, 6, 7, and 8)			-			-
			----------------			----------------
Preferred Stock of Subsidiaries			480			480
Utility Obligated Mandatorily Redeemable Preferred Securities
	of Trust Holding Solely Utility Subordinated Debentures		-			300
Common Stockholders' Equity
	Common stock, no par value, authorized 800,000,000 shares,
		issued 402,955,647 and 387,898,848 shares, respectively	6,222			5,986
	Common stock held by subsidiary, at cost, 23,815,500 shares		(690)			(690)
	Reinvested earnings (accumulated deficit)		311			(1,004)
	Accumulated other comprehensive income (loss)		(201)			30
			----------------			----------------
		Total common stockholders' equity	5,642			4,322
			----------------			----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY			$	36,635		$	35,963
			==========			==========
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

PG&E CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

						Nine months ended
						September 30,
						-------------------------------
						2002		2001
						------------		------------
Cash Flows From Operating Activitites
		Net income				$	1,315	$	570
		Adjustments to reconcile net income to
			net cash provided by operating activities:
					Depreciation, amortization, and decommissioning	1,021		784
					Deferred income taxes and tax credits, net	(50)		180
					Reversal of ISO accrual (Note 2)	(970)		-
					Price risk management assets and liabilities, net	302		37
					Other deferred charges and noncurrent liabilities	282		(604)
					Loss on impairment of assets	390		-
					Cumulative effect of a change in accounting principle	61		-
		Net changes in operating assets and liabilities:
				Restricted cash		(200)		(129)
				Accounts receivable		(89)		1,165
				Accounts payable		328		875
				Inventories		(29)		(147)
				Income taxes payable		146		1,241
				Regulatory balancing accounts, net		20		360
		Liabilities subject to compromise (Note 2)				(1,216)		-
		Other working capital				50		287
		Other, net				(295)		155
						-------------		-------------
Net cash provided by operating activities						1,066		4,774
						-------------		-------------
Cash Flows From Investing Activities
	Capital expenditures					(2,476)		(1,818)
	Proceeds from sale-leaseback					340		-
	Other, net					47		(235)
						-------------		-------------
Net cash used by investing activities						(2,089)		(2,053)
						-------------		-------------
Cash Flows From Financing Activities
	Net borrowings (repayments) under credit facilities and short-term borrowings					101		(1,159)
	Long-term debt issued					1,610		2,580
	Long-term debt matured, redeemed, or repurchased					(1,814)		(963)
	Common stock issued					190		-
	Dividends paid					-		(109)
						-------------		-------------
Net cash provided by financing activities						87		349
						-------------		-------------
Net change in cash and cash equivalents						(936)		3,070
Cash and cash equivalents at January 1						5,421		2,430
						-------------		-------------
Cash and cash equivalents at September 30						$	4,485	$	5,500
						========		========

Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income	$	59	$	56
	Cash paid for:
		Interest (net of amounts capitalized)		1,085		421
		Income taxes (net of refunds)	541		(1,241)
		Reorganization professional fees and expenses	25		6
	Transfer of liabilities and other payables subject to compromise (to) from operating payables and liabilities, net		(97)		11,313
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONSOLIDATED STATEMENTS OF INCOME
(in millions)

			Three months ended				Nine months ended
			September 30,				September 30,
			-------------------------				-------------------------
			2002		2001		2002		2001
			----------		----------		----------		----------
Operating Revenues
	Electric		$	2,483	$	2,509	$	6,454	$	5,265
	Gas		466		428		1,662		2,543
			-----------		-----------		-----------		-----------
		Total operating revenues	2,949		2,937		8,116		7,808
			-----------		-----------		-----------		-----------
Operating Expenses
	Cost of electric energy		555		434		894		2,389
	Cost of gas		119		263		632		1,608
	Operating and maintenance		860		563		2,269		1,771
	Depreciation, amortization, and decommissioning		315		224		880		663
	Reorganization professional fees and expenses		41		25		75		33
			-----------		-----------		-----------		-----------
		Total operating expenses	1,890		1,509		4,750		6,464
			-----------		-----------		-----------		-----------
Operating Income			1,059		1,428		3,366		1,344
	Reorganization interest income		17		32		58		64
	Interest income		1		7		1		31
	Interest expense:
	Contractual interest expense		(187)		(198)		(630)		(594)
	Noncontractual interest expense		(34)		(47)		(137)		(109)
	Other income (expense), net		1		(6)		(5)		(12)
			-----------		-----------		-----------		-----------
Income Before Income Taxes			857		1,216		2,653		724
	Income tax provision		330		472		1,061		272
			-----------		-----------		-----------		-----------
Net Income			527		744		1,592		452
	Preferred dividend requirement		7		7		19		19
			-----------		-----------		-----------		-----------
Income Available for Common Stock			$	520	$	737	$	1,573	$	433
			=======		=======		=======		=======

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONSOLIDATED BALANCE SHEETS
(in millions)
					Balance at
					----------------------------------------
					September 30,		December 31,
					2002		2001
					------------------		------------------
ASSETS
Current Assets
		Cash and cash equivalents			$	3,917	$	4,341
		Restricted cash			110		53
		Accounts receivable:
			Customers (net of allowance for doubtful accounts of
				$56 million and $48 million, respectively)	1,867		2,063
			Related parties		15		18
			Regulatory balancing accounts		158		75
		Inventories:
			Gas stored underground and fuel oil		186		218
			Materials and supplies		122		119
		Prepaid expenses			70		80
					------------------		------------------
			Total current assets		6,445		6,967
					------------------		------------------
Property, Plant and Equipment
	Electric				18,725		18,153
	Gas				8,048		7,810
	Construction work in progress				408		323
					------------------		------------------
			Total property, plant and equipment (at original cost)		27,181		26,286
	Accumulated depreciation and decommissioning				(13,354)		(12,929)
					------------------		------------------
			Net property, plant and equipment		13,827		13,357
					------------------		------------------
Other Noncurrent Assets
		Regulatory assets			2,062		2,283
		Nuclear decommissioning funds			1,311		1,337
		Other			1,297		1,325
					------------------		------------------
			Total other noncurrent assets		4,670		4,945
					------------------		------------------
TOTAL ASSETS					$	24,942	$	25,269
					===========		===========

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
				Balance at
				----------------------------------------
				September 30,			December 31,
				2002			2001
				-----------------			-----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Long-term debt, classified as current			$	281		$	333
	Current portion of rate reduction bonds			290			290
	Accounts payable:
		Trade creditors		510			333
		Related parties		86			86
		Regulatory balancing accounts		442			360
		Other		302			289
	Interest payable			356			26
	Income taxes payable			474			295
	Deferred income taxes			36			65
	Other			686			599
				------------------			------------------
		Total current liabilities		3,463			2,676
				------------------			------------------
Noncurrent Liabilities
	Long-term debt			2,739			3,019
	Rate reduction bonds			1,237			1,450
	Deferred income taxes			1,221			1,028
	Deferred tax credits			146			153
	Other			2,889			2,724
				------------------			------------------
		Total noncurrent liabilities		8,232			8,374
				------------------			------------------
Liabilities Subject to Compromise
	Financing debt			5,606			5,651
	Trade creditors			3,531			5,733
				------------------			------------------
		Total liabilities subject to compromise		9,137			11,384
				------------------			------------------
Commitments and Contingencies (Notes 1, 2, 6, and 7)				-			-
				------------------			------------------
Preferred Stock With Mandatory Redemption Provisions
	6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009					137	137
Company Obligated Mandatorily Redeemable Preferred Securities
	of Trust Holding Solely Utility Subordinated Debentures
	7.90%, 12,000,000 shares, due 2025		-				300
Stockholders' 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 (accumulated deficit)		584				(989)
	Accumulated other comprehensive income (loss)		-				(2)
			------------------				------------------
		Total stockholders' equity	3,973				2,398
			------------------				------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY			$		24,942		$	25,269
			===========				===========
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
					Nine months ended
					September 30,
					---------------------------------
					2002		2001
					------------		------------
Cash Flows From Operating Activities
	Net income				$	1,592	$	452
	Adjustments to reconcile net income to
			net cash provided by operating activities:
				Depreciation, amortization, and decommissioning	880		663
				Deferred income taxes and tax credits, net	157		127
				Other deferred charges and noncurrent liabilities	290		(658)
				Reversal of ISO accrual (Note 2)	(970)		-
	Net changes in operating assets and liabilities:
				Restricted cash	(57)		(9)
				Accounts receivable	245		493
				Income taxes receivable	-		1,120
				Accounts payable	(292)		1,003
				Inventories	29		(142)
				Income taxes payable	179		359
				Regulatory balancing accounts, net	(1)		231
	Liabilities subject to compromise (Note 2)				(1,180)		-
	Other working capital				345		663
	Other, net				37		21
					-------------		-------------
Net cash provided by operating activities					1,254		4,323
					-------------		-------------
Cash Flows From Investing Activities
	Capital expenditures				(1,156)		(889)
	Net proceeds from sale of assets				8		-
	Other, net				16		3
					-------------		-------------
Net cash used by investing activities					(1,132)		(886)
					-------------		-------------
Cash Flows From Financing Activities
	Net repayments under credit facilities and short-term borrowings				- -		(28)
	Long-term debt matured, redeemed, or repurchased				(546)		(325)
					-------------		-------------
Net cash used by financing activities					(546)		(353)
					-------------		-------------
Net change in cash and cash equivalents					(424)		3,084
Cash and cash equivalents at January 1					4,341		1,344
					-------------		-------------
Cash and cash equivalents at September 30					$	3,917	$	4,428
					========		========
Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income			$	59	$	56
	Cash paid for:
		Interest (net of amount capitalized)			830		300
		Income taxes (net of refunds)			708		(1,120)
		Reorganization professional fees and expenses			25		6
	Transfer of liabilities and other payables subject to
		compromise (to) from operating payables and liabilities, net			(97)		11,492

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

PG&E Corporation was incorporated in California in 1995 and became the holding company of Pacific Gas and Electric Company, a debtor-in-possession (the Utility), 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 4.9 million customers and natural gas service to approximately 4.1 million customers in northern and central California. Both PG&E Corporation and the Utility are headquartered in San Francisco. As discussed further in Note 2, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.

PG&E Corporation's other significant subsidiary is PG&E National Energy Group, Inc. (PG&E NEG) and its subsidiaries, headquartered in Bethesda, Maryland. PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG and its subsidiaries are located principally in the United States and Canada, and are engaged in power generation and development, wholesale energy marketing and trading, risk management, and natural gas transmission. PG&E NEG's principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, PG&E Gen), PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, PG&E ET), and PG&E Gas Transmission Corporation and its subsidiaries (collectively, PG&E GTC), which include PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively, PG&a mp;E GTN) and North Baja Pipeline, LLC (NBP). PG&E NEG also has other less significant subsidiaries.

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the unaudited Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's unaudited Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, PG&E NEG, and other wholly owned and controlled subsidiaries. The Utility's unaudited Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries.

PG&E Corporation and the Utility believe that the accompanying unaudited 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 unaudited 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 incorporated by reference in their combined 2001 Annual Report on Form 10-K, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission (SEC) since their combined 2001 Annual Report on Form 10-K was filed.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. 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," and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. However, as a result of the Chapter 11 filing, such realization of assets and liquidation of liabilities are subject to uncertainty. Among other things, SOP 90-7 generally requires that unsecured claims in existence prior to the filing of a bankruptcy case be listed on the Consolidated Balance Sheets as "Liabilities Subject to Compromise."

Certain amounts in PG&E Corporation's and the Utility's Consolidated Financial Statements, incorporated by reference in their combined 2001 Annual Report on Form 10-K and included in the Form 10-Q for the quarterly period ended September 30, 2001, have been reclassified to conform to the current period presentation.

Earnings Per Share

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed by dividing net income, adjusted for convertible note interest and amortization, by the weighted average number of common shares outstanding plus the assumed issuance of common shares for all dilutive securities.

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

			Three months ended					Nine months ended
			September 30,					September 30,
			--------------------------					-------------------------
(in millions, except per share amounts)			2002			2001		2002		2001
			-----------			----------		----------		----------
Income from continuing operations			$		466	$	771	$	1,376	$	570
Cumulative effect of accounting change			-			-		(61)		-
			-----------			----------		----------		----------
Net Income			466			771		1,315		570
			-----------			----------		----------		----------
Interest expense on 7.50% Convertible Subordinated Notes
	(net of income taxes of $2 million and $3 million, respectively)		3			-		4		-
			-----------			----------		----------		----------
Net Income for Diluted Calculations			$		469	$	771	$	1,319	$	570
			=======			======		======		======

Weighted average common shares outstanding, basic			373			363		368		363
Add:		Employee stock options and PG&E Corporation
		shares held by grantor trusts		-		1		2		-
		PG&E Corporation warrants		3		-		1		-
		7.50% Convertible Subordinated Notes	19			-		7		-
			-----------			----------		----------		----------
Shares outstanding for diluted calculations			395			364		378		363
			=======			======		======		======
Earnings Per Common Share, Basic
Income from continuing operations			$		1.25	$	2.12	$	3.74	$	1.57
Cumulative effect of accounting change			-			-		(0.17)		-
			-----------			----------		----------		----------
Net earnings			$		1.25	$	2.12	$	3.57	$	1.57
			=======			======		======		======
Earnings Per Common Share, Diluted
Income from continuing operations			$		1.19	$	2.12	$	3.65	$	1.57
Cumulative effect of accounting change			-			-		(0.16)		-
			-----------			----------		----------		----------
Net earnings			$		1.19	$	2.12	$	3.49	$	1.57
			=======			======		======		======

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 accounts 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 the Financial Accounting Standards Board (FASB) issued, Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation." Under the intrinsic value method, PG&E Corporation does not recognize any compensation expense, as the exercise price of all stock options is equal to the fair market value at the time the options are granted. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro-forma consolidated earnings and earnings per share would be as follows:

	Three months ended				Nine months ended
	September 30,				September 30,
	---------------------------				--------------------------
(in millions, except per share amounts)	2002		2001		2002		2001
	-----------		----------		----------		----------
Net Income:
As reported	$	466	$	771	$	1,315	$	570
Pro-forma	461		765		1,301		554

Basic Earnings per Share:
As reported		1.25		2.12		3.57		1.57
Pro-forma		1.24		2.11		3.54		1.53

Diluted Earnings per Share:
As reported		1.19		2.12		3.49		1.57
Pro-forma		1.17		2.10		3.45		1.53

Comprehensive Income

PG&E Corporation's and the Utility's comprehensive income consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS 133), as amended.

	PG&E Corporation				Utility
	-------------------------				------------------------
(in millions)	2002		2001		2002		2001
	----------		---------		---------		---------
Three months ended September 30
Net income available for common stock	$	466	$	771	$	520	$	737
Net gain (loss) in other comprehensive income (OCI) from current period hedging transactions and price changes in accordance with SFAS No. 133	(153)		21		- -		1
Net reclassification from OCI to earnings	(2)		43		-		40
	-----------		-----------		-----------		-------------
Comprehensive income	$	311	$	835	$	520	$	778
	=======		=======		=======		========
Nine months ended September 30
Net income available for common stock	$	1,315	$	570	$	1,573	$	433
Cumulative effect of adoption of SFAS No. 133	-		(243)		-		90
Net gain (loss) in OCI from current period hedging transactions and price changes in accordance with SFAS No. 133	(237)		170		-		(6)
Net reclassification from OCI to earnings	3		31		-		(84)
	------------		------------		------------		-------------
Comprehensive income	$	1,081	$	528	$	1,573	$	433
	=======		=======		=======		=======

Significant Accounting Policies

Accounting principles used include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). Except as disclosed below, PG&E Corporation and the Utility are following the same accounting principles discussed in their combined 2001 Annual Report on Form 10-K.

Adoption of New Accounting Policies

Change from Gross to Net Method of Reporting Revenues and Expenses on Trading Activities - For the quarter ended September 30, 2002, PG&E Corporation changed its method of reporting gains and losses associated with energy trading contracts from the gross method of presentation to the net method. As with the gross method, the net method is in accordance with Generally Accepted Accounting Principles (GAAP). PG&E Corporation believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements, in that net presentation is a better method of conveying the changes in market prices associated with trading activities. Amounts to be presented under the net method include all gross margin elements related to energy trading activities, including both unrealized and realized trades and both physical and financial trades.

Before implementation of the net method, PG&E Corporation already had reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E Corporation had reported realized gains and losses on a gross basis in operating income, as both operating revenues and costs of commodity sales and fuel. PG&E Corporation is now reporting all gains and losses from trading activities, including amounts that are realized, on a net basis as operating revenues. This will provide greater consistency in reporting the results of all energy trading activities. Amounts for trading activities in comparative prior periods have been reclassified to conform to the net method.

Implementation of the net method has no net effect on gross margin, operating income, or net income. The Utility did not have any trading contracts and therefore was unaffected by this change. The net method does not apply to non-trading activities. Accordingly, PG&E Corporation continues to report realized income from non-trading activities on a gross basis in operating revenues and operating expenses. The schedule below summarizes the amount impacted by the change in methodology in PG&E Corporation's Consolidated Statements of Income:

Prior Method Presentation
(Gross Method)
- --------------------------------------------

As Presented
(Net Method)
- -------------------------------------------

(in millions)

Three months
ended
September 30, 2002

Nine months
ended
September 30, 2002

Three months
ended
September 30, 2002

Nine months
ended
September 30, 2002

--------------------

--------------------

--------------------

--------------------

Generation, transportation, and
   trading revenues

$

4,853

$

10,238

$

1,079

$

2,407

Cost of commodity sales and fuel

4,537

9,469

763

1,638

---------------

---------------

---------------

---------------

Net Subtotal

$

316

$

769

$

316

$

769

=========

=========

=========

=========

Comparative results for the three- and nine-month periods ended September 30, 2001, including the effect of reclassifying certain amounts to comply with the implementation of the net method in 2002, are as follows:

Prior Method of Presentation
(Gross Method)
- -----------------------------------------------

As Presented
(Net Method)
- ----------------------------------------------

(in millions)

Three months
ended
September 30, 2001

Nine months
ended
September 30, 2001

Three months
ended
September 30, 2001

Nine months
ended
September 30, 2001

----------------------

----------------------

----------------------

--------------------

Generation, transportation, and
  trading revenues

$

3,343

$

10,253

$

764

$

2,157

Cost of commodity sales and fuel

3,041

9,362

462

1,266

---------------

---------------

---------------

---------------

Net Subtotal

$

302

$

891

$

302

$

891

=========

=========

=========

=========

Rescission of EITF 98-10 - In October 2002, the Emerging Issues Task Force (EITF) rescinded EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Energy trading contracts that are derivatives in accordance with SFAS No. 133 will continue to qualify for fair value accounting under SFAS No. 133. Contracts that had been marked to market under EITF 98-10 that do not meet the definition of a derivative will be recorded on a cost basis with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003.

The EITF also delayed the implementation (to January 1, 2003) of EITF 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk Management Activites,' and EITF 00-17, ' Measuring the Fair Value of Energy Related Contracts in Applying EITF 98-10'" (EITF 02-03). The official guidance related to EITF 02-03 will be outlined in the final minutes of the recent EITF meeting, scheduled for release in November 2002.

The reporting requirements associated with the rescission of EITF 98-10 should be applied prospectively for all EITF 98-10 energy trading contracts entered into after October 24, 2002. For all EITF 98-10 energy trading contracts in existence at or prior to October 24, 2002, the effective date is the fiscal quarter beginning after December 15, 2002.

PG&E Corporation is currently assessing the impact of this ruling.

Change in Estimate Due to Changes in Certain Fair Value Assumptions - PG&E Corporation estimates the gross mark-to-market value of its trading contracts and certain non-trading contracts using forward curves. The forward curves used to calculate mark-to-market value have liquid periods (includes continuous maturities starting from the month for which broker quotes are available on a daily basis) and illiquid periods (includes those maturities for which broker quotes are not readily available). When market data is not available, PG&E Corporation historically has utilized alternative pricing methodologies, including third-party pricing curves, the extrapolation of forward pricing curves using historically reported data, and interpolation between existing data points. The gross mark-to-market valuation is then adjusted for time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to de termine fair value. For trading activities, these models are used to estimate the fair value of long-term transactions including tolling agreements. For non-trading activities, these models are used to estimate the fair value of cash flow hedges, certain power purchase agreements and fuel purchase agreements which are accounted for as derivative contracts under SFAS No. 133.

Beginning in the third quarter of 2002, PG&E Corporation implemented a new model for projecting forward power and gas prices during illiquid periods. This new process primarily impacts the estimation of power prices. The model estimates forward power prices in illiquid periods using the mid-point of the marginal cost curve (the lowest variable cost of generation available in a particular region) and the forecast curve (the price at which a generation unit will recover its capital costs and a return on investment). Assumptions about cost recovery are combined with assumptions about volatility and correlation in an option model to project forward power prices. Interpolation methods continue to be used for intermediate periods when broker quotes are intermittent. In addition to implementing the new process for projecting forward power prices in illiquid periods, PG&E Corporation also enhanced its models to better incorporate certain physical characteristics of its power plants.

As discussed above, PG&E Corporation makes adjustments to gross mark-to-market values in order to arrive at fair values. Beginning in the third quarter of 2002, PG&E Corporation enhanced its process of estimating fair values by adjusting certain long-term valuations to account for uncertainties surrounding projected forward prices, volumetric assumptions, and modeling complexity. PG&E Corporation also refined its process for estimating the bid-ask spread in illiquid periods for purposes of liquidity adjustments.

All of these changes in fair values are being accounted for on a prospective basis as a change in accounting estimate. The change in fair values had a pre-tax income effect of a $14 million loss from trading activities and a pre-tax gain of $25 million from non-trading activities. These income effects, totaling a pre-tax gain of $11 million for both trading and non-trading activities, were recognized in the quarter ended September 30, 2002.

Accounting for Gains and Losses on Debt Extinguishment and Certain Lease Modifications - On July 1, 2002, PG&E Corporation adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This Statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the accompanying Consolidated Statements of Income. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current criteria for extraordinary classification under GAAP. On August 30, 2002, PG&E Corporation recorded $115 million of debt extinguishment losses as charges to interest expense for voluntary prepayment of a loan to General Electric Capital Corporation (GECC) and a new waiver extension from the Tranche B Lenders (see Note 4, Debt Financing).

In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistently with sale-leaseback accounting rules. This provision did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility at the date of adoption.

Changes to Accounting for Certain Derivative Contracts - On April 1, 2002, PG&E Corporation implemented two interpretations issued by the FASB's Derivatives Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (collectively, SFAS No. 133). Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus were not marked to market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis.

DIG C15 changed the definition of normal purchases and sales for certain power contracts. DIG C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. PG&E NEG determined that five of its derivative commodity contracts for the physical delivery of power and purchase of fuel no longer qualified for normal purchases and sales treatment under these interpretations. Beginning April 1, 2002, these five contracts were required to be recorded on the balance sheet at fair value and marked to market through earnings. Three of the contracts had positive market values and resulted in pre-tax income of $125 million. The remaining two contracts had negative market values that resulted in a pre-tax charge of $127 million. The cumulative effects of implementing these accounting changes at April 1, 2002, resulted in PG&E Corporation recording price risk management assets of $37 million, price risk management liabilities of $255 million, and a reduction of out-of-market obligations of $129 million reclassified to net price risk management liabilities.

One of the contracts with a positive market value included above is for a power sales contract at a partnership in which PG&E NEG has a 50 percent ownership interest. PG&E NEG reflects its investment in this partnership on an equity basis (Investments in Unconsolidated Affiliates). Upon adoption of DIG C15 and C16, PG&E NEG recognized its equity share of the gain from the cumulative change in accounting method and correspondingly increased the book value of its equity investment in the partnership. However, the future net cash flows from the partnership do not support the increased equity investment balance. Therefore, PG&E NEG has recognized an impairment charge of $101 million to reduce its equity-method investment to fair value. The cumulative effect of the change in accounting principle for DIG C15 and C16 was a net charge of $61 million, after-tax, and included the recognition of the fair market value of the five contracts impacted by DIG C15 and C16 and the resultant impairment charge. The Utility was not impacted by these accounting changes.

Implementation of these accounting changes will not impact the timing and amount of cash flows associated with the affected contracts; however, it will impact the timing and magnitude of future earnings. Future earnings will reflect the gradual reversal of the assets and liabilities recorded upon adoption over the contracts' lives, as well as any prospective changes in the market value of the contracts. Prospective changes in the market value of these contracts could result in significant volatility in earnings. However, over the total lives of the contracts, there will be no net impact to total operating results after netting the cumulative effect of adoption against the subsequent years' impacts (assuming that the affected contracts are held to their expiration).

Accounting for the Impairment or Disposal of Long-Lived Assets - On January 1, 2002, PG&E Corporation adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," but retains its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. This Statement requires that all long-lived assets to be disposed of by sale be carried at the lower of carrying amount or fair value less cost to sell, and that depreciation cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. The adoption of this Statement did not have any impact on the Consolidated Financial Statements of PG&E Corporation and the Utility (See Note 8, Impairment and Write-offs).

Accounting for Goodwill and Other Intangible Assets - On January 1, 2002, PG&E Corporation adopted SFAS No. 142, "Goodwill and Other Intangible Assets (SFAS No. 144)." This Statement eliminates the amortization of goodwill and requires that goodwill be reviewed at least annually for impairment. Upon implementation of this Statement, the transition impairment test for goodwill was performed as of January 1, 2002, and no impairment loss was recorded. Goodwill amortization expense for the three and nine months ended September 30, 2001, was $1 million and $4 million, respectively (See Note 8, Impairment and Write-offs). The Utility had no goodwill on its balance sheet at December 31, 2001, or September 30, 2002.

This Statement also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. Adoption of this Statement did not require any adjustments to be made to the useful lives of existing intangible assets and no reclassifications of intangible assets to goodwill were necessary.

Intangible assets other than goodwill are being amortized on a straight-line basis over their estimated useful lives, and are reported under noncurrent assets in the Consolidated Balance Sheets.

The schedule below summarizes the amount of intangible assets by major classes.

Balance at

-----------------------------------------------------------------------

September 30, 2002

December 31, 2001

----------------------------------

----------------------------------

(in millions)

Gross Carrying Amount

Accumulated Amortization

Gross Carrying Amount

Accumulated Amortization

-------------

-----------------

-------------

----------------

PG&E NEG:

Service agreements

$

33

$

7

$

33

$

6

Power sale agreements

67

37

67

30

Other agreements

33

15

32

11

Utility:

Hydro licenses and other
agreements

66

16

66

14

-------------

--------------

-------------

-------------

PG&E Corporation-Consolidated

$

199

$

75

$

198

$

61

========

========

========

========

PG&E NEG's amortization expense on intangible assets for the three and nine months ended September 30, 2002, was $2 million and $5 million, respectively, compared to $1 million and $3 million for the same periods in 2001. These amounts do not include amortization expense related to intangibles for certain power sale agreements, which are recorded against the related revenue or expense. The amount of amortization expense that was recorded against related revenue or expense was $7 million for the nine months ended September 30, 2002. The Utility's amortization expense of intangible assets was $1 million and $2 million, respectively, for the three and nine months ended September 30, 2002, and for the same periods in 2001.

The following schedule shows the estimated amortization expenses for intangible assets for full years 2002 through 2006. The schedule excludes the expense recorded against the related revenue or expense on power sale agreements by PG&E NEG.

(in millions)

2002

2003

2004

2005

2006

-----------

-----------

----------

-----------

----------

PG&E NEG

$

6

$

6

$

6

$

6

$

6

Utility

3

3

3

3

3

Related Party Transactions

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation. 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 or at the higher of fully loaded cost or fair market value, depending on the nature of the services provided. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using a variety of factors that are based upon the number of employees, operating expenses excluding fuel purchases, total assets, and other cost causal methods. Additionally, the Utility purchases gas commodity and transmission services from, and sells reservation and other ancillary services to, PG&E NEG. These services are priced at either tariff rates or fair market value depending on the nature of the services provided. In tercompany transactions are eliminated in consolidation and no profit results from these transactions. The Utility's significant related party transactions were as follows:

	Three months ended September 30,				Nine months ended September 30,
	--------------------------				--------------------------
(in millions)	2002		2001		2002		2001
	-----------		-----------		-----------		----------
Utility revenues from:
Administrative services provided to PG&E Corporation	$	3	$	-	$	6	$	4
Gas reservation services provided to PG&E ET	2		3		8		9
Contribution in aid of construction received from PG&E NEG	-		-		-		5
Utility expenses from:
Administrative services received from PG&E Corporation	$	16	$	17	$	66	$	55
Gas commodity and transmission services received from PG&E ET	5		(14)		33		109
Transmission services received from PG&E GT	11		11		33		29

NOTE 2: THE UTILITY CHAPTER 11 FILING
Overview of Electric Industry Restructuring

In 1998, California implemented electric industry restructuring and established a market framework for electric generation in which generators and other power providers were permitted to charge market-based prices for wholesale power. The restructuring of the electric industry was mandated by the California Legislature in Assembly Bill (AB) 1890. The mandate included a retail electricity rate freeze and a plan for recovery of generation-related costs that were expected to be uneconomic under the new market framework (transition costs). Additionally, the CPUC required the Utility to divest more than 50 percent of its fossil generation facilities and discouraged the Utility from continuing to operate remaining generation facilities by reducing the allowed return on such assets. This had the effect of increasing the Utility's reliance on the wholesale electricity market. The new market framework called for the creation of the Power Exchange (PX) and the Independent System Operator ( ISO). Before it ceased operating in January 2001, the PX established market-clearing prices for electricity. The ISO's role is to schedule delivery of electricity for all market participants and operate certain markets for electricity. Until December 15, 2000, the Utility was required to sell all of its owned and contracted generation to, and purchase all electricity for its retail customers from, the PX. Customers were given the choice of continuing to buy electricity from the Utility or buying electricity from independent power generators or retail electricity suppliers (direct access). Most of the Utility's customers continued to buy electricity through the Utility.

Beginning in June 2000, wholesale spot prices for electricity sold through the PX and the ISO began to escalate. While forward and spot prices moderated somewhat in September and October 2000, such prices increased in November and December 2000 to levels substantially higher than during the summer months. The increased cost of the purchased electricity strained the financial resources of the Utility because the CPUC applied the rate freeze in a way which prohibited the Utility from passing on the increases in power costs to its customers. The Utility financed the higher costs of wholesale electric power while interested parties evaluated various solutions to the California energy crisis. Consequently, by December 31, 2000, the Utility had borrowed more than $3 billion to finance its wholesale energy purchases.

Because of escalating wholesale electricity costs and the continuing inability to pass on these costs to retail customers, the Utility accumulated approximately $6.9 billion (pre-tax) in under-collected purchased power costs and generation-related transition costs as of December 31, 2000. The under-collected purchased power costs historically were deferred for future recovery as a regulatory asset subject to future collection from customers in rates. However, due to the lack of regulatory, legislative, and judicial relief, the Utility determined that it no longer could conclude that its under-collected purchased power costs and remaining transition costs were probable of recovery in future rates. Therefore, the Utility charged $6.9 billion to expense for its under-collected purchased power costs and its remaining unamortized transition costs at December 31, 2000.

In January 2001, the CPUC increased electric rates by $0.01 per kilowatt-hour (kWh), and in March 2001 by another $0.03 per kWh, and applied restrictions on the use of these surcharge revenues to "ongoing procurement costs" and "future power purchases." The Utility has recorded a regulatory liability for each month that the combined revenues from both surcharges exceeded procurement costs. At September 30, 2002, the total amount of the regulatory liability was approximately $75 million (pre-tax).

Although the CPUC authorized the $0.03 per kWh surcharge on March 27, 2001, the Utility did not begin collecting the revenues until June 2001. In May 2001, the CPUC authorized an "incremental system average surcharge of $0.005 per kWh" for a 12-month period beginning June 1, 2001. This "half-cent" surcharge had been projected to end May 31, 2002. In an advice letter dated April 15, 2002, the Utility proposed to eliminate the half-cent surcharge in accordance with the May 2001 decision. On June 6, 2002, the CPUC instead issued a resolution ordering the Utility to continue collecting the half-cent surcharge and to begin recording the surcharge in a balancing account beginning June 1, 2002, until further consideration by the CPUC. The Utility has recorded a regulatory liability for the surcharge beginning June 1, 2002. The total amount of this regulatory liability was approximately $147 million (pre-tax) at September 30, 2002.

On November 7, 2002, the CPUC voted to approve a decision lifting restrictions on the use of revenues generated by the $0.01 and $0.03 surcharges on retail electric rates authorized in January and March 2001, respectively. Although a final written decision is not yet available, the draft decision that the CPUC voted out amends the previous decisions in order to authorize the Utility to use the surcharge revenues not only for ongoing procurement costs, but also for the purpose of securing or restoring its reasonable financial health, as the CPUC determines to be necessary in other proceedings, such as proceedings relating to ratemaking for the CPUC proposed plan of reorganization in the Utility's bankruptcy proceeding, or relating to the determination by the CPUC of the end of the AB 1890 rate freeze and the disposition of undercollected costs remaining at the end of the rate freeze. The draft decision specifically cites recovery of the Utility's remaining transition costs as a potential use of the surch arge revenues, and states that AB 1890 does not preclude recovery of such costs after the rate freeze, since the Utility's retained generation-related costs are no longer uneconomic within the meaning of the restrictions in AB 1890 on the recovery of such costs. The draft decision also clarifies that the use of the surcharge revenues for ongoing procurement costs is intended to be only for those ongoing procurement costs that exceed the revenues available for the recovery of such costs and other operating costs during the term of the AB 1890 rate freeze, which the draft decision states ended no later than March 31, 2002. Based on this draft decision, it is possible that subsequent decisions by the CPUC may affect the amount and timing of the "headroom" revenues recovered by the Utility through the CPUC surcharge decisions, and it is possible that a portion of "headroom" revenues recovered by the Utility during the period between June 2001 and March 31, 2002, the latest possible end date for the AB 1890 rat e freeze, may be subject to refund to the extent not offset by costs authorized by the CPUC for recovery during the rate freeze or otherwise recoverable under other law, such as pursuant to the Utility's Rate Recovery Litigation. If such refunds are ordered, they could have a material adverse impact on the Utility's earnings.

As a result of the increases in electric rates in 2001, and the stabilization of the price of wholesale electricity, the Utility's total generation-related electric revenues were greater than its generation-related costs. In 2001, this resulted in additional earnings of $458 million (after-tax), which represented a partial recovery of previously written-off under-collected purchased power and transition costs, and included $327 million (after-tax) related to the market value of terminated bilateral contracts. During the nine months ended September 30, 2002, the Utility's total generation-related revenues exceeded its generation-related costs by approximately $1.3 billion (after-tax), which includes a net reduction of 2001 accrued purchased power costs of approximately $352 million (after-tax) and includes an offset of $180 million (after-tax) in additional pass-through revenues accrued in the third quarter of 2002 related to the amounts to be remitted to the California Department of Water Resources (DWR ) in connection with the DWR's proposed amendment to the CPUC's May 16, 2002, servicing order. (See further discussion below under "Electricity Purchases.") The Utility's previously written-off under-collected purchased power and transition costs amounted to $2.4 billion and $3.7 billion (after-tax) at September 30, 2002, and December 31, 2001, respectively. The recovery of these remaining under-collected purchased power costs and transition costs will depend on a number of factors, including, but not limited to, the ultimate outcome of the Utility's bankruptcy and future regulatory and judicial proceedings, including the outcome of the Utility's filed rate doctrine litigation and, potentially, the California Supreme Court's consideration of questions certified to it by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) regarding the legality of recovery of similar under-collected costs by another California utility, Southern California Edison Company (SCE), under a settlement and stipulated federal court judgment with the CPUC.

Under AB 1890, the rate freeze was scheduled to end on the earlier of March 31, 2002, or the date that the Utility recovered all of its generation-related transition costs as determined by the CPUC. However, on January 2, 2002, the CPUC issued a decision finding that new California legislation, AB 6X, had materially affected the implementation of AB 1890. Therefore, the CPUC scheduled further proceedings to address the impact of AB 6X on the AB 1890 rate freeze for the Utility and to determine the extent and disposition of the Utility's remaining unrecovered transition costs. Additionally, on January 11, 2002, in a court proceeding involving the SCE/CPUC settlement, the CPUC represented to the court that, in part as a result of AB 6X, it has the authority to allow the Utility and SCE to recover their under-collected purchased power and transition costs beyond the end of the AB 1890 rate freeze. In fact, the settlement reached by the CPUC and SCE stipulated that SCE would maintain rates at their c urrent levels (beyond the end of the AB 1890 rate freeze) until the earlier of the date that SCE recovered its previously incurred transition costs or December 31, 2003. To the extent SCE's costs are not recovered by December 31, 2003, they are to be amortized and recovered over a period ending December 31, 2005. Several parties, including The Utility Reform Network (TURN), a consumer group, have challenged the SCE/CPUC settlement and the ratemaking adopted by the CPUC to implement the settlement, arguing, among other things, that the recovery of SCE's under-collected costs in retail rates under the settlement violates the rate freeze provisions of AB 1890 prohibiting post-freeze recovery of transition and procurement costs. On September 23, 2002, the Ninth Circuit issued an opinion questioning whether the settlement violated AB 1890 and whether the CPUC had the authority to enter into the settlement. The Ninth Circuit has certified the state law issues for review by the California Supreme Court. SCE an d the CPUC both have formally requested that the California Supreme Court consider the certified questions and find that the settlement is lawful and that the CPUC has authority to enter into the settlement. TURN also has pending before the CPUC a request that the CPUC rehear and reconsider its implementing decisions relating to the settlement.

On April 15, 2002, the CPUC filed an alternative plan of reorganization (Alternative Plan) in the Utility's bankruptcy proceeding in U.S. Bankruptcy Court, proposing that the Utility's overall retail electric rates be maintained at current levels through January 31, 2003, in order to generate cash to repay in part the Utility's creditors under the CPUC's plan. The CPUC represented to the Bankruptcy Court that it was authorized to propose and implement its plan under state law. On July 12, 2002, in response to a lawsuit filed in state court by a consumer group challenging the legal authority of the CPUC to propose its plan, the CPUC represented that since utilities are now required under state law to retain their generating assets and the CPUC has regained its traditional rate authority over those assets, costs associated with those assets may be recovered by the utilities in the traditional way, under cost-based regulation. In addition, the CPUC represented that its failure to exercise its discretion t o change rates to reflect changes in the Utility's costs after the AB 1890 rate freeze does not violate procedural requirements of state law. Based on these CPUC decisions and representations, the Utility believes it can continue to record revenues collected under its existing overall retail rates, subsequent to the statutory end of the rate freeze. However, the CPUC's further proceedings to consider the impact of AB 6X on the AB 1890 rate freeze and the disposition of the Utility's unrecovered transition costs are still pending, and it is possible that at some future date the CPUC, on its own initiative or in response to judicial decisions, including the California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the legality of recovery of similar under-collected costs by SCE, may change its interpretation of law or otherwise seek to change the Utility's overall retail electric rates retroactively. Any such change could materially affect the Utility's earnings.

In a March 2001 decision, the CPUC adopted an accounting proposal by TURN that retroactively restates the way in which the Utility's transition costs are recovered. This retroactive change had the effect of extending the AB 1890 rate freeze and reducing the amount of past wholesale power costs that could be eligible for recovery from customers. The CPUC denied the Utility's application for rehearing of this retroactive accounting change. The Utility also filed a petition for a writ of review with the California Court of Appeal that also was denied. In August 2002, the California Supreme Court denied the Utility's petition seeking review of the appellate court action. Further, the Bankruptcy Court denied the Utility's request for an order enjoining the CPUC from enforcing its retroactive order. The Utility has appealed the Bankruptcy Court's denial of injunctive relief to the U.S. District Court for the Northern District of California (U.S. District Court). The Utility cannot predict the outcome of this matter.

Electricity Purchases

As a result of the Utility's inability to pass through wholesale electricity costs to customers and the resulting impact on the Utility's financial resources, the Utility's credit rating deteriorated to below investment grade in January 2001. This credit downgrade precluded the Utility from access to capital markets. The Utility had no credit under which it could purchase wholesale electricity on behalf of its customers on a continuing basis. Consequently, generators were selling to the Utility only under emergency action taken by the U.S. Secretary of Energy.

In January 2001, the California Legislature and the Governor of California authorized the DWR to begin purchasing wholesale electric energy on behalf of the Utility's retail customers. On February 1, 2001, the Governor signed into law California AB 1X authorizing the DWR to purchase power to meet the Utility's net open position (the amount of power needed by retail electric customers that cannot be met by utility-owned generation or power under contract to the Utility) and to issue revenue bonds to finance electricity purchases. The DWR purchased energy on the spot market until it was able to negotiate long-term contracts for the supply of electricity. In addition to certain contracts that it subsequently entered into, the DWR continues to purchase power on the spot market at prevailing market prices.

Initially, the DWR indicated that it intended to buy power only at "reasonable prices" to meet the Utility's net open position, leaving the ISO to purchase the remainder in order to avoid blackouts. The ISO billed the Utility for its costs to purchase power to cover the amount of the Utility's net open position not covered by the DWR. In 2001, the Utility accrued approximately $1 billion for these ISO purchases for the period from January 17, 2001, through April 6, 2001. However, in February, April, and November 2001, the FERC issued a series of orders directing the ISO to buy power only on behalf of creditworthy entities. In its November 7, 2001, order, the FERC directed the ISO to invoice the DWR for all ISO transactions that the ISO entered into on behalf of the Utility. On December 7, 2001, the DWR filed an application for rehearing of the November 7, 2001, FERC order alleging, among other things, that the FERC order was illegal and unconstitutional because it restricted the DWR's unilateral disc retion to determine the prices it would pay for the third-party power under the ISO invoices. On March 27, 2002, the FERC denied the DWR's application for rehearing and reaffirmed its previous orders finding that the DWR is responsible for paying such ISO charges.

On February 21, 2002, the CPUC approved decisions adopting rates for the DWR, and allowing the DWR to collect power charges and financing charges from ratepayers to pay for the $19 billion in revenues needed by the DWR to procure electricity for the customers of the Utility and the other California investor-owned utilities (IOUs) for the two-year period ending December 31, 2002. The revenues needed by the DWR will be financed partially through a DWR bond issuance and partially through the DWR's total statewide revenue requirement, which is allocated among the Utility and the other California IOUs. The CPUC's February 21, 2002, decision established a total statewide revenue requirement of $9 billion for power charges of the DWR for the two-year period ending December 31, 2002, and allocated $4.5 billion to the Utility's customers. The February 21, 2002, CPUC decision noted that the DWR had been found by the FERC to be responsible for ISO imbalance energy (energy obtained from the market) purchases for 2001, and authorized the DWR to collect rates from the Utility's customers sufficient to reimburse the DWR for these costs.

On March 21, 2002, the CPUC modified its February 21, 2002, revenue requirement decision, effectively lowering the amount allocated to the Utility's customers to $4.4 billion for the period from January 2001 through December 2002. The Utility believes that the DWR's revenue requirement incorporates the procurement charges previously billed by the ISO and accrued by the Utility. In light of the March 27, 2002, FERC order and the February 21 and March 21, 2002, CPUC decisions, in the first quarter of 2002 the Utility reversed the excess of the ISO accrual (for the period from January 17, 2001, through April 6, 2001) over the amount of the DWR revenue requirement applicable to 2001, for a net reduction of accrued purchased power costs of approximately $595 million (pre-tax).

On October 8, 2002, the DWR filed a proposed amendment to the CPUC's May 16, 2002, servicing order requesting changes to the calculation that determines the amount the Utility is required to pass through to the DWR for electricity provided by the DWR to the Utility's customers. This proposed amendment more specifically defines the methodology used to calculate remittances to the DWR. It also specifies that the Utility should use the more specific methodology to true-up previous remittances of revenues passed through to the DWR as well as future remittances. Under its statutory authority, the DWR may request the CPUC to order utilities to implement amendments to the servicing orders and arrangements that the DWR has with California utilities, and the CPUC has approved such amendments in the past without significant change. Based on the DWR's proposed amendment, during the third quarter of 2002, the Utility accrued an additional $303 million (pre-tax) liability for pass-through revenues for electricity provided by the DWR to the Utility's customers through September 30, 2002.

The CPUC's February 21, 2002, DWR revenue requirement decision, as modified by the March 21, 2002, decision, requires the DWR to submit true-ups of differences between forecast and actual data contained in its 2001-2002 revenue requirement when it submits its 2003 revenue requirement. In August 2002, the DWR determined that its 2001, 2002, and 2003 statewide revenue requirements were "just and reasonable" as required by AB 1X, and filed with the CPUC its updated 2003 statewide revenue requirement which totaled $5.8 billion ($4.7 billion in power charge related costs and $1.1 billion in bond charge related costs). In its filing, the DWR also requested an increase in its 2001-2002 revenue requirement to $9.1 billion, a slight increase from the $9.0 billion originally forecast. This revenue requirement reflects actual costs through March 2002 and projected costs for the remainder of 2002. On October 24, 2002, the CPUC issued a decision to establish a DWR bond charge to be collected from the customers of the California IOUs to ensure repayment of the DWR bonds and related costs.

Before the DWR filed its 2003 statewide revenue requirement and its updated 2001-2002 revenue requirement with the CPUC in August 2002, the Utility had filed comments with the DWR alleging that major portions of the DWR's revenue requirement were not "just and reasonable" as required by AB 1X, and that the DWR was not complying with the procedural requirements of AB 1X in making its determination. In part, the Utility based its allegations on the fact that the State of California (State) has pending a petition before the FERC seeking to set aside many of the same contracts on the basis that they are not "just and reasonable." On August 26, 2002, the Utility and SCE filed at the DWR a motion for reconsideration of the DWR's determination that its revenue requirements were "just and reasonable." The DWR denied these motions on October 8, 2002. On October 17, 2002, the Utility filed a lawsuit in a California court asking the court to find that the DWR's revenue requirements had not been demonstrated to be "just and reasonable" and lawful, and that the DWR has violated the procedural requirements of AB 1X in making its determination. The Utility asked the court to order the DWR's revenue requirement determination be withdrawn as invalid, and that the DWR be precluded from imposing its revenue requirements on the Utility and the DWR's customers until it has complied with the law. No schedule has yet been set for consideration of the lawsuit.

Senate Bill 1976

Under AB 1X, the DWR is prohibited from entering into new agreements to purchase power to meet the net open position of the California IOUs after January 1, 2003. Under current FERC tariffs, in order to purchase power through the ISO, the IOUs must meet the ISO's creditworthiness standards for third-party transactions, which require that the IOUs have an investment grade credit rating or meet certain collateral or prepayment requirements.

On September 24, 2002, California Senate Bill 1976 (SB) 1976 was signed into law. SB 1976 requires the CPUC to allocate the electricity subject to existing DWR contracts among the customers of the IOUs, including the Utility's customers, and further requires that each IOU submit, within 60 days of the CPUC's allocation, an electricity procurement plan specifying the date that the IOU intends to resume procurement of electricity for its retail customers. As part of the resumption of the procurement function, each IOU would procure power for that portion of its customers' needs that is not covered by the combination of the allocation of power from existing DWR contracts to that IOU's customers and the IOU's own power resources and contracts (referred to as the residual net open position). SB 1976 requires that each procurement plan include one or more of the following features:

A competitive procurement process under a format authorized by the CPUC, with the costs of procurement obtained in compliance with the authorized bidding format being recoverable in rates;
A clear, achievable, and quantifiable incentive mechanism that establishes benchmarks for procurement and authorizes the IOUs to procure from the market subject to comparison with the CPUC-authorized benchmarks; and/or
Upfront and achievable standards and criteria to determine the acceptability and eligibility for rate recovery of a proposed transaction and an expedited CPUC pre-approval process for proposed bilateral contracts to ensure compliance with the individual utility's procurement plan.

SB 1976 also provides that the CPUC may not approve a feature or mechanism in a procurement plan if it finds that the feature or mechanism would impair the restoration of the IOU's creditworthiness or would lead to a deterioration of the IOU's creditworthiness. SB 1976 also indicates that procurement activities in compliance with an approved procurement plan will not be subject to after-the-fact reasonableness review, although SB 1976 does permit a regulatory process to verify and assure that each contract was administered in accordance with the terms of the contract and that contract disputes that arise are resolved reasonably. SB 1976 authorizes the CPUC to create power procurement balancing accounts to track the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC would be required to review, at least semi-annually, the balancing accounts, and to adjust rates or order refunds, as necessary to properly amortize a balancing account.

Until January 1, 2006, SB 1976 requires the CPUC to establish the schedule for amortizing the over-collections or under-collections in the power procurement balancing accounts so that the aggregate over-collection or under-collection reflected in the accounts does not exceed 5 percent of the utility's actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. Mandatory semi-annual review of the balancing accounts and the need for rate adjustments will lapse on January 1, 2006, but the CPUC will still be required to conduct power procurement balancing account reviews and adjust amortization schedules for the balancing accounts in a manner consistent with the objectives of SB 1976. Under SB 1976, the CPUC has final authority to accept, reject, or modify each IOU's procurement plan.

On October 24, 2002, the CPUC issued a decision ordering the Utility to resume full procurement on January 1, 2003. The decision requires the Utility to submit modifications to its short-term procurement plan for 2003 to the CPUC by November 12, 2002, and to submit its long-term procurement plan by April 1, 2003.

Allocation of DWR Electricity to the Investor-Owned Electric Utilities

Consistent with applicable law, the Utility currently acts as a billing and collection agent pursuant to a servicing order adopted by the CPUC for the DWR's sales to the Utility's retail customers. The Utility does not take title to the DWR electricity or have any financial responsibility for the sale of DWR electricity.

On September 19, 2002, the CPUC issued a decision that allocates the electricity subject to the DWR contracts among the customers of the three California IOUs. The power available under the contracts is to be dispatched in conjunction with the IOU's existing resources on a least-cost basis. Some of the DWR contracts are firm commitments requiring the DWR to make purchases of specified quantities of electricity; others give the DWR the option as to whether to purchase the quantity of electricity set forth in the contract; and others have a combination of mandatory and optional purchases.

The CPUC's allocation generally assigns to the customers of the Utility the quantities under contracts with specified delivery points north of the Path 15 transmission facilities. The CPUC has indicated that this allocation will not be changed in the future. The IOUs will assume all of the day-to-day scheduling, dispatch, and administrative functions for the DWR contracts allocated to their customers by January 1, 2003. The DWR will retain legal title, and financial reporting and payment responsibility associated with these contracts. Under the September 19, 2002, decision, the IOUs will, however, be required to become responsible for scheduling and dispatch of the quantities subject to the allocated contracts and for many administrative functions associated with those contracts. The IOU's will be operationally responsible for disposition of power from the combined DWR contract/Utility power resources portfolio that is surplus to the IOUs customers' needs. The IOUs would continue to act as billing a nd collection agents for the DWR.

The September 19, 2002, CPUC decision orders the DWR to allocate its variable costs on a contract-by-contract basis. The allocation of both fixed and variable costs will be decided in an annual DWR revenue requirement proceeding. Under AB 1X, the CPUC has no reasonableness review authority over the procurement prices in the DWR's contracts. However, under the CPUC decision, the CPUC has indicated that it would review annually the reasonableness of the IOUs' administration of the operationally allocated DWR contracts, including how the IOUs elected to dispatch the DWR contracted-for power in their portfolios relative to other resources in their portfolios. While the IOUs would not bear the risk of being unable to fully pass through the procurement costs associated with these contracts because they would be recoverable through the DWR's revenue requirement, the IOUs will be held to a reasonableness standard in their scheduling and dispatch decision-making and their administration of the contracts. If t he Utility's scheduling or dispatch decisions or its administration of these allocated contracts were found by the CPUC to be unreasonable in conjunction with the scheduling and dispatch of the Utility's retained generation, the Utility could bear the risk of not being able to fully recover its costs in the Utility's rates or otherwise be held responsible for its action. Because the Utility believes that it cannot be compelled to administer and bear the risks associated with the DWR's contracting, including the obligation to dispose of significant excess purchase obligations under those contracts, among other things, the Utility filed an application for rehearing of the decision with the CPUC on October 23, 2002, challenging the decision as violating SB 1976 and other federal and state laws. The Utility cannot predict whether the CPUC will alter this aspect of the decision or whether the CPUC's position ultimately will be determined to be unlawful.

Fourth Quarter 2002 Procurement Authority to Decrease Residual Net Open Position

On August 22, 2002, the CPUC authorized the Utility to enter into transitional electricity procurement contracts before January 1, 2003, with the DWR as a co-party to cover the Utility's forecasted residual net open position, or a portion thereof, beginning January 1, 2003. All contracts must be pre-approved by the CPUC and the CPUC's decision puts in place a review framework designed to enable pre-approvals before the end of the year. So long as the DWR is the creditworthy purchaser, the DWR will retain legal and financial title to the electricity and recover costs associated with these interim procurement contracts directly from the Utility's customers under the AB 1X framework with the Utility acting as billing and collection agent. However, the contracts provide that if the Utility regains investment grade status, all legal title and responsibility for these interim contracts from that point forward will pass from the DWR to the Utility.

This interim procurement authorization only extends to contracts entered into before January 1, 2003, although it allows multi-year procurement arrangements of up to five years in length. Under the authorization, electric utilities are required to:

Obtain pre-approval of proposed contracts and hedging products from the CPUC;

Demonstrate, in the context of applying for that pre-approval, that the contracts are needed to meet conservatively estimated peak period net open position; and

Demonstrate, in the context of applying for that pre-approval, that the conservative methodology for forecasting the peak period net open position in the decision has been adhered to.

Although CPUC pre-approval of the contracts would constitute a determination that the costs incurred under the contracts are reasonable, the Utility's administration of the contracts would remain subject to a reasonableness review by the CPUC. The Utility may be subject to a risk of disallowance for costs arising from its actions that are found to be unreasonable.

The Utility entered into several interim procurement contracts in October 2002 that would obligate itself and the DWR upon the occurrence of certain conditions. The Utility is not obligated under the contracts until the following conditions have been met: (1) the Utility has achieved an investment grade credit rating, (2) the CPUC has approved the contracts as just and reasonable for their entire term, (3) the Bankruptcy Court has approved the contracts, and (4) the DWR has agreed to be financially and legally obligated under the contracts until such time as the Utility is investment grade. The terms of the interim procurement contracts range from one to three years commencing on or after January 1, 2003. The Utility estimates that the total cost to be incurred under the contracts will not exceed $42 million in 2003, $37 million in 2004, and $33 million in 2005. These amounts will be paid by the DWR until the Utility attains an investment grade credit rating and would be recov ered as an addition to the DWR's revenue requirement. The DWR is not obligated to enter into the contracts, and therefore the Utility is unable to predict whether the Utility will be obligated under the contracts and whether the contracts will become effective prior to January 1, 2003, when the DWR's authority to enter such contracts expires. If the DWR contracts do not go into effect, the residual net open requirements for the Utility to cover its retail electric customers' load after January 1, 2003, would be higher.

In the August 22, 2002, decision, the CPUC also directed the Utility to conduct a competitive solicitation and enter into contracts for renewable resources that would provide an additional one percent of its annual energy needs. The Utility was directed to procure the additional one percent in renewable resources with or without participation by the DWR, and irrespective of its energy needs. Contracts are to be 5, 10, or 15 years in length. The Utility was also directed to extend "Standard Offer One" contracts to QFs with expiring or terminated contracts, until implementation of a long-term procurement plan. The Utility conducted a competitive solicitation for renewable resources in September 2002, and is expecting to propose contracts for the CPUC's approval in November 2002 for the purchase of approximately 750 gigawatt-hours per year at prices up to $0.0537 per kWh, which has been deemed a reasonable benchmark by the CPUC in its August 22, 2002, decision. The Utility also expects to file for C PUC approval of Standard Offer One contract extensions in November 2002.

The SB 1976 Regulatory Structure and the Utility's Bankruptcy Plan

After the CPUC adopts the Utility's procurement plan, SB 1976 mandates that the Utility resume procurement within 60 days. The Utility's proposed bankruptcy plan of reorganization (Utility's Plan) provides that the Utility will not be obligated to accept any assignment of electricity procurement contracts executed by the DWR. It also provides that the Utility will not be obligated to assume responsibility for its net open position, including any portion that might not be satisfied, under the DWR contracts, unless certain conditions are satisfied, including the Utility's receipt of an investment grade credit rating, the existence of an objective retail rate recovery mechanism pursuant to which the Utility will be able to fully recover in a timely manner its wholesale power procurement costs, and the existence of objective standards regarding pre-approval of procurement transactions. The creation of an objective retail rate recovery mechanism and the adoption of objective standards regarding pre-approval of procurement transactions are each within the control of the CPUC. The Utility is evaluating the CPUC's October 24, 2002, decision requiring the California IOUs to resume procurement on January 1, 2003, in light of the conditions of the Utility's Plan. The Utility cannot predict at this time what steps it may or may not need to take regarding implementation of its modified short-term procurement plan and resumption of full procurement under the CPUC decision.

The DWR has stated publicly that it intends to seek to transfer full legal title and responsibility for the DWR electricity contracts to the California IOUs as soon as possible. While the Utility believes nothing in SB 1976 or in current CPUC decisions or state law supports the DWR's authority to effect such a transfer of legal title without the consent of the Utility, the Utility cannot predict whether either the DWR or the CPUC will seek to compel transfer of the DWR contracts to the Utility without its consent in the future. The Utility has informed the CPUC, the DWR, and the State that it would rigorously oppose any attempt to transfer the DWR contracts to it without its consent.

The CPUC decision implementing SB 1976 contemplates that the Utility reassume procurement responsibility for the net open position by January 1, 2003, regardless of whether the Utility's Plan is effective, whether the Utility has regained investment grade status, or whether the other preconditions to the Utility's resumption of the net open position set forth in the Plan have been satisfied. The CPUC decision states that if the Utility believes that Bankruptcy Court approval is required in order for the Utility to resume procurement of the net open position, the Utility immediately should seek such authority. The electricity to be provided under existing DWR contracts allocated to the Utility's customers and the electricity to be provided under any interim contracts that the Utility may enter into using the DWR's credit would reduce the Utility's residual net open position. The Utility currently expects its residual net open position for 2003 to be immaterial. However, resumption of procurement responsibility for the residual net open position on January 1, 2003, or at any time when the conditions of the Utility's Plan have not been satisfied, could expose the Utility to the following burdens and risks:

If the Utility is not permitted to recover procurement costs in a timely manner, the Utility's cash flow would be adversely affected;

The CPUC has authorized a conservative estimate of the Utility's post-January 1, 2003, residual peak period net open position for purposes of determining its interim procurement authority using DWR credit. If the estimate is too low, the power that the Utility contracts for under that arrangement may be insufficient to meet its actual residual peak demand after January 1, 2003;

If spot or forward prices for electricity materially increase, the magnitude of the costs exposed to regulatory-determined recovery will increase;

If the Utility must resume procurement responsibility for its residual net open position prior to regaining an investment grade credit rating, the ISO would, and energy trading counterparties may, require the Utility to post collateral or make cash prepayments, which would affect the Utility's cash flow.

Chapter 11 Filing

On April 6, 2001, as a result of (1) the failure of the DWR to assume the full procurement responsibility for the Utility's net open position, (2) the negative impact of a CPUC decision that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) the lack of progress in negotiations with the State to provide a solution for the energy crisis, and (4) the adoption by the CPUC of a retroactive accounting change that attempted to eliminate the ratemaking accrual of the Utility's actual under-collected wholesale electricity costs, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Subsidiaries of the Utility, including PG&E Funding LLC (which holds Rate Reduction Bonds) and PG&E Holdings, LLC (which holds stock of the Utility), are not included in the Utility's petition. While the Utility's parent, PG&E Corporation, and PG&E NEG have not filed for relief under Chapter 11 and are not included in the Utility's petition, PG&E Corporation is a co-proponent of the Utility's proposed Plan of Reorganization (the Plan).

Certain claims against the Utility in existence prior to its filing for bankruptcy are stayed while the Utility continues business operations as a debtor-in-possession. The Utility has reflected its total estimate of all such valid claims on the September 30, 2002, Consolidated Balance Sheets as $9.1 billion of Liabilities Subject to Compromise and as $3.0 billion of Long-Term Debt. The following schedule summarizes the activity of the Utility's Liabilities Subject to Compromise from the period of December 31, 2001, to September 30, 2002 (in billions).

Liabilities Subject to Compromise at December 31, 2001

$

11.4

Interest accrual for the nine months ended September 30, 2002

0.3

Claims paid pursuant to Bankruptcy Court orders

(1.2)

Claims and Interest authorized by the Bankruptcy Court to be paid
(transferred to accounts payable or interest payable)

(0.7)

Reclassification of debt upon liquidation of trust holding solely Utility
Subordinated Debentures (Note 5)

0.3

Reversal of first quarter 2001 ISO accrual

(1.0)

---------------

Liabilities Subject to Compromise at September 30, 2002

$

9.1

=========

Additional claims or changes to Liabilities Subject to Compromise may subsequently arise from, among other things, resolution of disputed claims and Bankruptcy Court actions. Payment terms for these amounts will be established through the bankruptcy proceedings. Secured claims also are stayed, although the Utility has received authorization from the Bankruptcy Court to make certain principal payments that have matured. Secured claims are secured primarily by liens on substantially all of the Utility's assets and by pledged accounts receivable from natural gas customers. The Bankruptcy Court has approved certain payments and actions necessary for the Utility to carry on its normal business operations (including payment of employee wages and benefits, refunds of certain customer deposits, use of certain bank accounts and cash collateral, assumption of various hydroelectric contracts with water agencies and irrigation districts, certain qualifying facilities (QF) payments, interest on secured debt, and c ontinuation of environmental remediation and capital expenditure programs) and to fulfill certain post-petition obligations to suppliers and creditors. In addition, the Bankruptcy Court has authorized the payment of pre- and post-petition interest and low-dollar items on certain claims prior to the Utility's emergence from bankruptcy under a confirmed plan.

Substantially all claims have been filed with the Bankruptcy Court and total approximately $49.1 billion through September 30, 2002. Total claims filed include claims filed by generators and by certain financial creditors (some of which have been disallowed by the Bankruptcy Court, based on a finding that such claims are duplicative of claims filed by indenture trustees and other claimants or, in the case of commercial paper, claims scheduled by the Utility). These claims also contain governmental claims which include, but are not limited to, contingent environmental claims, claims for federal, state and local taxes, and claims submitted by the DWR for approximately $430 million of energy purchases made on behalf of the Utility's retail customers.

Analysis is continuing on all claims. Of the $49.1 billion of claims filed, approximately $25.0 billion of claims have been determined to be duplicative or withdrawn. Of the remaining $24.1 billion, approximately $6.7 billion are claims which under the Plan will pass through the bankruptcy proceeding (primarily litigation, which under the Plan will be determined under applicable non-bankruptcy law in the appropriate court after the date on which the Plan becomes effective (Effective Date) and other financial claims), approximately $4.0 billion are proposed objections (primarily generator claims), and approximately $1.0 billion are pending objections (primarily contingent insurance claims for which the Utility has no current liability and other generator claims). The Utility believes future Bankruptcy Court rulings will further reduce the amount of the claims. As discussed above, the Utility has recorded its estimate of all valid claims at September 30, 2002, as $9.1 billion of Liabilities Subject to C ompromise and $3.0 billion of Long-term Debt. The Utility has also made payment for certain claims authorized by the Bankruptcy Court, as discussed below, thereby reducing the amount of outstanding claims. In addition, the Utility has accrued interest on all claims the Utility considers valid since filing for bankruptcy. This additional interest accrual is not included in the original $49.1 billion of claims filed.

The claims resolution process in bankruptcy involves the determination by the Bankruptcy Court of the validity of the claim. In addition, it is common to negotiate with creditors to achieve settlement. The Utility intends to explore settlement of claims wherever possible.

Since December 2001, the Bankruptcy Court has approved supplemental agreements entered into between the Utility and most QFs to resolve the issue of the applicable interest rate to be applied to pre-petition amounts owed to QFs. The supplemental agreements (1) set the interest rate for pre-petition payables at 5 percent, (2) provide for a "catch-up payment" of all accrued and unpaid interest through the initial payment date, and (3) depending on the amount owed, either provide for the immediate payment of the principal amount of the pre-petition payables (and interest thereon) or payment in 12 or 6 equal monthly payments commencing on the last business day of the month during which Bankruptcy Court approval was granted, and continuing for 11 or 5 subsequent months. In the event the Effective Date of the Plan occurs before the last monthly payment is made, the remaining unpaid principal and accrued but unpaid interest thereon shall be paid in full on the Effective Date. Additionally, since January 2002, the Utility has entered into agreements with additional QFs to assume their power purchase agreements, which agreements also contained the same interest and payment terms contained in the supplemental agreements described above. At September 30, 2002, $704 million and $61 million in principal and interest, respectively, have been paid to the QFs. Through September 30, 2002, 263 of 313 QFs have signed assumption and/or supplemental agreements. The Utility believes that some of the remaining QFs also will wish to enter into similar supplemental agreements.

On March 27, 2002, the Bankruptcy Court authorized payment of pre- and post-petition interest to holders of certain other undisputed claims, including creditors holding certain financial instruments issued by the Utility (including certain senior debtholders, as described above), trade creditors, and other general unsecured creditors, and authorized payment of fees and expenses of indenture trustees and other paying agents (subject to a procedure to permit objections to fees to be made and resolved). Through October 1, 2002, the Utility has paid approximately $686 million in pre- and post-petition interest related to these claims. The Utility also repaid advances and interest on advances of $23 million, through October 1, 2002, to banks providing letters of credit backing pollution control bonds, which were separately authorized by the Bankruptcy Court.

On March 25, 2002, the Bankruptcy Court authorized the Utility to pay all undisputed creditor claims that are $5,000 or less and undisputed mechanics' liens and reclamation claims. Through September 30, 2002, the majority of these payments had been made and totaled approximately $10 million.

The Utility and PG&E Corporation Plan of Reorganization

On September 20, 2001, the Utility and its parent company, PG&E Corporation, jointly filed with the Bankruptcy Court a proposed Plan of Reorganization (the Plan) for the Utility under the Bankruptcy Code and a related disclosure statement. The Utility and PG&E Corporation filed amendments to the Plan and the disclosure statement on several occasions after the initial filing in an effort to resolve objections filed by various parties, to respond to the Bankruptcy Court's February 7, 2002, decision regarding federal preemption of state law, and to update the information in the Plan and related disclosure statement to reflect other developments with respect to the Utility's business and restructuring efforts. On April 24, 2002, the Bankruptcy Court entered an order approving the Utility's disclosure statement dated April 19, 2002.

Pursuant to the Bankruptcy Court's February 27, 2002, order, the CPUC was permitted to submit an alternative plan of reorganization (Alternative Plan). This order confirmed that no other party, other than the CPUC and the Utility, was permitted to submit a proposed plan of reorganization. This exclusivity period was scheduled to end on June 30, 2002. In response to a motion filed by the Utility to extend the exclusivity period until December 31, 2002, the Official Committee of Unsecured Creditors (OCC) requested that the exclusivity period be modified to enable the OCC to formulate and be in a position to file an alternative plan of reorganization if the proponents of the Utility's Plan and the CPUC's Alternative Plan fail to come to terms on a consensual plan and it appears that neither plan as currently proposed is likely to be confirmed by the Bankruptcy Court or implemented in an expeditious fashion. On July 9, 2002, the Bankruptcy Court issued an order granting both the OCC's request and the Util ity's motion extending the exclusivity period to December 31, 2002, except as to the CPUC and the OCC.

If the Utility's Plan, as amended, is confirmed and becomes effective, it would allow the Utility to restructure its businesses and refinance the restructured businesses.

The Utility's Plan proposes that all allowed creditor claims would be paid in full with interest. The majority of creditors would receive payment using a combination of cash and long-term notes as follows:

On the Effective Date of the Plan, Creditors Would Receive Payment In

---------------------------------

Cash

Long-term
Notes

------------

--------------

Majority of secured creditors

100%

-

Majority of unsecured creditors with allowed claims of $100,000 or less

100%

-

Unsecured creditors with allowed claims in excess of $100,000

60%

40%

QUIDS (Note 5)

-

100%

As specified in the Plan, the Utility has agreed to pay the holders of certain allowed claims pre- and post-petition interest on the principal amount of such claims at rates of interest as follows:

Amount Owed
(in millions)

Agreed Upon Rate
(per annum)

--------------------

-----------------------

Commercial Paper Claims

$

873

7.466%

Floating Rate Notes

1,240

7.583%

(Implied yield of 7.690%)

Senior Notes

680

9.625%

Medium-Term Notes

287

5.810% to 8.450%

Revolving Line of Credit Claims

938

8.000%

In addition, if the Effective Date of the Plan does not occur on or before February 15, 2003, these interest rates will be increased by 37.5 basis points. If the Effective Date does not occur on or before September 15, 2003, the agreed rates will be increased by an additional 37.5 basis points. Finally, if the Effective Date does not occur on or before March 15, 2004, the agreed rates will be increased by an additional 37.5 basis points. For other claims, the Utility has recorded the contractual or FERC-tariffed interest rate or, when those rates do not apply, the federal judgment rate.

The Utility's Plan is designed to align the businesses under the regulators that best match the business functions. Retail assets would remain under the retail regulator, the CPUC, and wholesale assets would be placed under wholesale regulators, the FERC and the Nuclear Regulatory Commission (NRC). After this alignment, the retail-focused, state-regulated business would be a gas and electric distribution company (Reorganized Utility) representing approximately 70 percent of the book value of the Utility's assets and having approximately 16,000 employees. The wholesale businesses, which would be federally regulated (as to price, terms, and conditions), would consist of electric transmission (ETrans), interstate gas transmission (GTrans), and generation (Gen).

The Utility's Plan proposes that certain other assets of the Utility deemed not essential to operations would be sold to third parties or transferred to Newco Energy Corporation (Newco), a consolidated subsidiary created by the Utility to hold the investments in ETrans, GTrans, and Gen. Additionally, the Utility would declare and, after the assets are transferred to the newly formed entities, pay a dividend to PG&E Corporation of all of the outstanding common stock of Newco. Each of ETrans, GTrans, and Gen would continue to be an indirect wholly owned subsidiary of PG&E Corporation.

The Utility's 18,500 circuit miles of electric transmission lines and cable would be transferred to ETrans, a California company. ETrans would operate as an independent transmission company selling transmission services to wholesale customers (utilities) and to electric generators.

The Utility's 6,300 miles of gas transmission pipelines and three gas storage facilities would be transferred to GTrans, a California company. GTrans would hold the majority of the land, rights of way, and access rights currently associated with Utility gas transmission pipelines. GTrans also would assume certain continuing contractual obligations currently held by the Utility's gas transmission operation. In addition, the Reorganized Utility would hold a 10- to 15-year transportation and gas storage contract with GTrans.

Substantially all of the Utility's hydroelectric and nuclear generation assets, and associated lands, and the power contracts with irrigation districts would be transferred to Gen, a California company. In total, Gen would have approximately 7,100 megawatts (MW) of generation. The facilities would be operated in accordance with all current FERC and NRC licenses. Gen would sell its power back to the Reorganized Utility under a 12-year contract at a stable market-based rate approved by the FERC.

The Utility's Plan relies on the FERC and the Bankruptcy Court to authorize certain actions. These actions include allowing a shift in regulatory jurisdiction of certain of the Utility's assets to be transferred to the newly formed entities, approving contracts between and among the newly formed entities, and preempting certain state and local laws. Specifically, the Plan asks the Bankruptcy Court to issue a confirmation order which would:

Approve the Utility's Plan, authorizing the Utility to execute, implement, and take all actions necessary or appropriate to give effect to the transactions contemplated by the Plan and the Plan documents;

Approve the execution of, and find reasonable the terms and conditions of, the proposed service and sales contracts between the Reorganized Utility and one or more of the disaggregated entities;

Find that the CPUC affiliate transaction rules are not applicable to the restructuring transactions contemplated under the Plan; and

Find that neither PG&E Corporation nor the Utility is required to comply with certain provisions of the California Corporations Code relating to corporate distributions and the sale of substantially all of a corporation's assets because the Bankruptcy Code preempts such state law.

Further, if the Bankruptcy Court determines that the CPUC and/or the State as a whole have not waived their sovereign immunity with respect to the Utility's Plan, PG&E Corporation and the Utility intend to amend the conditions to confirmation of the Utility's Plan to substitute findings of fact or conclusions of law for any declaratory or injunctive relief presently sought against the CPUC or the State.

Finally, the Utility's Plan contemplates that on or as soon as practicable after the Effective Date, PG&E Corporation would distribute the shares of the Reorganized Utility's common stock that it holds to the holders of PG&E Corporation common stock on a pro-rata basis (Spin-Off). The preferred stock of the Utility that is currently outstanding would remain outstanding preferred stock of the Reorganized Utility. It is contemplated that holders of preferred stock of the Utility would receive in cash on the Effective Date any dividends unpaid and sinking fund payments accrued in respect of such preferred stock through the last scheduled payment date occurring before the Effective Date. The common stock of the Reorganized Utility would be registered under federal securities laws, and would be freely tradable by the recipients on the Effective Date or as soon as practicable thereafter. The Reorganized Utility would apply to list the common stock of the Reorganized Utility on the New York Stock Exc hange.

Key aspects of the Utility's Plan include: (1) the issuance of investment grade registered debt by ETrans, GTrans, and Gen, the proceeds of which, along with additional notes, would be distributed to the Reorganized Utility so that it could pay creditors, (2) a 12-year bilateral contract whereby Gen would provide the Reorganized Utility firm capacity and energy at an average rate of approximately $51 per megawatt-hour (MWh), and (3) the assumption by the Reorganized Utility of responsibility for the net open position only after certain conditions specified in detail below are met.

The Plan provides that the following conditions must be fulfilled before the Reorganized Utility will reassume the responsibility to purchase power to meet the net open position not already provided through the DWR's power purchase contracts:

The Reorganized Utility receives an investment grade credit rating and receives assurances from the rating agencies that its credit rating will not be downgraded as a result of the reassumption of the obligation to meet the net open position;
There is an objective retail rate recovery mechanism in place pursuant to which the Reorganized Utility is able to fully recover in a timely manner its wholesale costs of purchasing electricity to satisfy the net open position;
There are objective standards in place regarding pre-approval of procurement transactions; and
After reassumption of the obligation to meet the net open position, the conditions in clauses (2) and (3) remain in effect.

SB 1976, which was signed by the Governor of California on September 24, 2002, and the CPUC's October 24, 2002, decision, address the Utility's reassumption of the net open obligation by January 1, 2003 (see "Electricity Purchases" above).

On November 30, 2001, the Utility and PG&E Corporation, on behalf of their subsidiaries ETrans, GTrans, and Gen, filed various applications with the FERC seeking approval to implement the proposed reorganization and the securities issuances and debt financings contemplated by the Plan. The FERC also must approve some of the various service agreements to be entered into between the Reorganized Utility and one or more of the disaggregated entities. On October 10, 2002, a FERC administrative law judge issued an initial decision finding that Gen had provided sufficient evidence to provide a basis for a decision regarding whether the 12 year contract under which Gen would resell its power to the Reorganized Utility was just and reasonable. There is no specific time by which the FERC is required to take final action on the initial decision. Additionally, the SEC, as administrator of the Public Utility Holding Company Act (PUHCA), must approve the Plan. An application under PUHCA was filed with the SEC on January 31, 2002.

Also, on November 30, 2001, the Utility filed applications with the NRC for approval to transfer the NRC operating licenses for the Diablo Canyon Nuclear Power Plant (Diablo Canyon) to Gen and one of its subsidiaries, and for the indirect transfer of the license for the Humboldt Bay Nuclear Power Plant, which is in the early stages of decommissioning, to the Reorganized Utility. The NRC found that an indirect transfer of the license for the Humboldt Bay Nuclear Power Plant is unnecessary. The NRC has not taken actions on the Diablo Canyon license transfer.

Additionally, because the reorganization is intended to qualify as a tax-free reorganization and the Spin-Off is intended to qualify as a tax-free spin-off, PG&E Corporation and the Utility sought a private letter ruling from the Internal Revenue Service (IRS) confirming the tax-free treatment of these transactions. On August 2, 2002, the Utility received confirmation from the IRS that these transactions would constitute a tax-free reorganization.

During 2002, the Utility undertook several initiatives to prepare for separation under the Plan. The Utility has spent approximately $20 million through September 30, 2002, and expects to spend an additional $84 million through the Effective Date of the Plan.

As recently amended, the Utility's Plan provides that it will not become effective unless and until the following conditions have been satisfied or waived:

The Effective Date shall have occurred on or before May 30, 2003;
All actions, documents, and agreements necessary to implement the Plan shall have been effected or executed;
PG&E Corporation and the Utility shall have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions, or documents that are determined by PG&E Corporation and the Utility to be necessary to implement the Plan;
Standard & Poor's (S&P) and Moody's Investors Service (Moody's) shall have established credit ratings for each of the securities to be issued by the Reorganized Utility, ETrans, GTrans, and Gen of not less than BBB- and Baa3, respectively;
The Plan shall not have been modified in a material way since the confirmation date; and
The registration statements pursuant to which the new securities will be issued shall have been declared effective by the SEC, the Reorganized Utility shall have consummated the sale of its new securities to be sold under the Plan, and the new securities of each of ETrans, GTrans, and Gen shall have been priced and the trade date with respect to each shall have occurred.

If one or more of the conditions described above have not occurred or been waived by May 30, 2003, the confirmation order shall be vacated and the Utility's obligations with respect to claims and equity interests shall remain unchanged.

In a February 7, 2002, decision, the Bankruptcy Court rejected PG&E Corporation's and the Utility's (collectively, Proponents) contentions that bankruptcy law permits express preemption of state law in connection with the implementation of a plan of reorganization. The Bankruptcy Court nonetheless held that "the Plan could be confirmed if Proponents are able to establish with particularity the requisite elements of implied preemption." The Bankruptcy Court stated that Proponents must show facts that would lead the Bankruptcy Court to find that the "application of those laws to the facts of the Debtor's proposed reorganization are economic in nature rather than directed at protecting public safety or other non-economic concerns, and that those particular laws stand as an obstacle to the accomplishment and execution of the purposes and objectives of Congress and the Bankruptcy Code." The Bankruptcy Court noted that if the disclosure statement were amended consistent with the court's memorandum decisi on, the court would approve it and let the Proponents test preemption at confirmation.

On March 18, 2002, the Bankruptcy Court entered an order disapproving the disclosure statement for the reasons set forth in the February 7, 2002, decision. On March 22, 2002, PG&E Corporation and the Utility appealed the Bankruptcy Court's March 18, 2002, order to the U.S. District Court.

Subsequently, the Utility's disclosure statement and Plan were amended consistent with the Bankruptcy Court's February 7, 2002, preemption decision. On April 24, 2002, the Bankruptcy Court approved the Utility's disclosure statement dated April 19, 2002, describing the Utility's Plan. The Bankruptcy Court's approval of the Utility's disclosure statement does not constitute approval of the Plan.

On August 30, 2002, the U.S. District Court reversed the March 18, 2002, Bankruptcy Court order and remanded the case back to the Bankruptcy Court for further proceedings, ruling that the Bankruptcy Code expressly preempts "nonbankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan." The U.S. District Court found that under the Bankruptcy Code, state public utility commission approval is not required to implement the transactions necessary to carry out a utility's reorganization plan, except that a plan providing for a rate change cannot be confirmed unless the rate change is approved by the appropriate regulatory commission. PG&E Corporation and the Utility believe that the Utility's Plan does not provide for a change in rates. The U.S. District Court also noted that the Utility seeks the suspension of nonbankruptcy law applying only to transactions necessary for reorganization and does not contend that the reorganized comp anies would be exempt from any laws on a going-forward basis by virtue of reorganization.

The U.S. District Court entered judgment on September 19, 2002, and the CPUC and several other parties thereafter filed a notice of appeal to the Ninth Circuit. In addition, on September 17 and 19, 2002, respectively, the CPUC, the California Attorney General (AG), on behalf of several governmental entities, the City and County of San Francisco, and the California Hydropower Reform Coalition (collectively, Appellants) filed two motions in the U.S. District Court: (1) a protective motion asking the U.S. District Court to certify its August 30, 2002, decision for immediate review to the Ninth Circuit, and (2) a motion requesting that the U.S. District Court stay the effect of its August 30, 2002, decision pending their appeal. PG&E Corporation and the Utility have informed the U.S. District Court that they have no objection to certifying its express preemption decision for review, and the motion was submitted for decision without argument. In addition, PG&E Corporation and the Utility have agreed to an expedited briefing and hearing schedule on the motion to stay the effect of the U.S. District Court's August 30, 2002, decision pending the appeal to the Ninth Circuit. Arguments on the stay motion were heard on October 8, 2002, and the U.S. District Court took the stay motion under submission. The Ninth Circuit has issued a scheduling order in the appeal pursuant to which the Appellants' opening brief will be due on January 16, 2003. On October 30, 2002, PG&E Corporation and the Utility filed a motion asking the Ninth Circuit to expedite its review of the U.S. District Court's August 30, 2002, decision and adopt a schedule that would allow briefing and argument to occur by the end of January 2003.

The CPUC's Alternative Plan of Reorganization

As authorized by the Bankruptcy Court, on April 15, 2002, the CPUC filed its proposed Alternative Plan and disclosure statement with the Bankruptcy Court, followed by an amendment on May 15, 2002. The Bankruptcy Court approved the CPUC's disclosure statement on May 17, 2002.

On August 22, 2002, the CPUC announced that it entered into an agreement with the OCC regarding modifications to its Alternative Plan. The agreement states that the OCC will become a co-proponent of the CPUC's Alternative Plan. The CPUC's Alternative Plan does not call for realignment of the Utility's business, but instead provides for the continued regulation of all of the Utility's current operations by the CPUC. The CPUC modified certain terms of its original Alternative Plan as a result of this agreement. The CPUC's Alternative Plan was further amended on November 6, 2002. The following are the significant components of the CPUC's amended Alternative Plan:

Assumes all valid claims, (together with applicable post-petition interest at the lowest non-default contract rate, or if no contract or non-default rate exists, then the federal judgment rate and, except for these claimed to be reinstated) will be satisfied in full with cash (inclusive of the net proceeds from the proposed sale of the new subordinated notes);

Proposes to raise $7.3 billion through the issuance of new senior secured debt;

Proposes to raise $1.0 billion through the issuance of new unsecured debt;

Proposes to raise $500 million through the sale of Utility preferred stock;

Proposes to reinstate nearly $1.0 billion of preferred stock and pollution control bonds;

Proposes to establish a $1.75 billion regulatory asset which would be amortized over ten years and would earn the full rate of return on rate base;

Requires the Utility to dismiss the rate recovery litigation against the state, with prejudice;

Becomes effective only if the Utility's new and reinstated debt securities receive investment grade credit ratings (however, the CPUC would retain the right to waive this condition with the Bankruptcy Court's approval);

Assumes the Utility will obtain a $1.9 billion credit facility to fund operating expenses and seasonal fluctuations of capital (a portion of this facility will be used for letters of credit that may be needed to pay collateral for post-petition workers' compensation liabilities); and

Provides for a "reorganization agreement" between the Utility and the CPUC under which the CPUC will establish retail electric rates on an ongoing basis sufficient for the Utility to achieve and maintain investment grade credit ratings and to recover in rates (1) the interest and dividends payable on, and the amortization and redemption of, the securities to be issued in connection with the CPUC's Alternative Plan, (2) certain recoverable costs (defined as the amounts the Utility is authorized by the CPUC to recover in retail electric rates in accordance with historic practice for all of its prudently incurred costs, including capital investment in property, plant and equipment, a return of capital and a return on capital and equity to be determined by the CPUC from time to time in accordance with its past practices.)

PG&E Corporation and the Utility believe the CPUC's amended Alternative Plan, as outlined above, is not credible or confirmable. PG&E Corporation and the Utility do not believe the CPUC's amended Alternative Plan, as outlined above, would restore the Utility to investment grade status if the Alternative Plan were to become effective. Additionally, PG&E Corporation and the Utility believe the amended Alternative Plan would violate applicable federal and state law.

Further, on April 22, 2002, the CPUC initiated a regulatory proceeding to consider the rate impacts of its Alternative Plan and the Utility's Plan and invited parties to file comments. The order followed a legal challenge before the California Supreme Court by the Foundation for Taxpayers and Consumer Rights (FTCR) that the CPUC did not have the authority to propose a plan in Bankruptcy Court. On August 14, 2002, the California Supreme Court declined to exercise its discretion to consider the FTCR's challenge at this stage. Also, on July 17, 2002, the CPUC instituted a proceeding regarding the securities authorization necessary to implement the CPUC's Alternative Plan. On November 7, 2002, the CPUC issued a decision approving the securities authorization under the CPUC's Alternative Plan.

Confirmation Hearings

Solicitation of creditor votes began on June 17, 2002, and concluded on August 12, 2002. The CPUC and OCC sought permission from the Bankruptcy Court to reopen the creditor voting period and resolicit the votes of certain creditors as a result of the modifications made to the Alternative Plan after the OCC became a co-proponent of the Alternative Plan. The Bankruptcy Court denied this request and declined to rule until such time as the CPUC and/or the OCC brings a renewed motion with respect to their request for an order authorizing the resolicitation of preferences regarding the CPUC's modified Alternative Plan. The Bankruptcy Court did, however, leave open the possibility of a procedure that would be used to consider the preference of creditors if both plans emerge as confirmable at the confirmation hearings.

On September 9, 2002, an independent voting agent filed the voting results with the Bankruptcy Court. Nine of the ten voting classes under the Utility's Plan approved the Utility's Plan. The CPUC's Alternative Plan was approved by one of the eight voting classes under the CPUC's Alternative Plan.

On November 6, 2002, the CPUC and the OCC filed an amended Alternative Plan and filed a motion asking the Bankruptcy Court to authorize the resolicitation of creditor votes and preferences. The Utility intends to object to the request for resolicitation. The hearing on the CPUC/OCC's motion is to set for November 27, 2002.

In determining whether to confirm either plan, the Bankruptcy Court will consider creditor and equity interests, plan feasibility, distributions to creditors and equity interests, and the financial viability of the reorganized entities. Various parties have filed objections to confirmation of either or both plans. PG&E Corporation and the Utility filed objections to the CPUC Alternative Plan stating their belief that the Alternative Plan is neither feasible nor confirmable for the reasons discussed above. The CPUC also filed an objection to the Utility's Plan.

On October 1, 2002, the Bankruptcy Court issued orders regarding the protocol for conducting discovery in preparation for the confirmation hearings as well as the scheduling of the confirmation hearings. The trial on confirmation of the CPUC Alternative Plan will begin on November 18, 2002, and is tentatively scheduled to end by December 5, 2002. The trial on the Utility's Plan is scheduled to begin no later than December 16, 2002, with objections common to both plans slated for trial during the Utility's Plan trial.

Neither the Utility nor PG&E Corporation is able to predict which plan, if any, the Bankruptcy Court will confirm. If either plan is confirmed, implementation of the confirmed plan may be delayed due to appeals, CPUC actions or proceedings, or other regulatory hearings that could be required in connection with the regulatory approvals necessary to implement that plan, and other events. The pendency of the bankruptcy proceeding and the related uncertainty around the plan of reorganization that is ultimately adopted and implemented will have a significant impact on the Utility's future liquidity and results of operations. PG&E Corporation and the Utility are not able at this time to predict the outcome of the Utility's bankruptcy case or the effect of the reorganization process on the claims of the Utility's creditors or the interests of the Utility's preferred shareholders. However, the Utility believes, based on information presently available to it, that cash and cash equivalents on hand at S eptember 30, 2002, of $3.9 billion and cash available from operations will provide sufficient liquidity to allow it to continue as a going concern through 2002.

NOTE 3: PG&E NEG LIQUIDITY AND FINANCIAL RESOURCES

As previously reported in PG&E NEG's recent filings on Form 8-K with the SEC, before July 31, 2002, most of the various debt instruments of PG&E NEG and its affiliates carried investment grade credit ratings as assigned by S&P and Moody's, two major credit rating agencies. On July 31, 2002, and August 5, 2002, S&P and Moody's, respectively, downgraded PG&E NEG's credit ratings, as previously reported. On October 8, 2002, October 16, 2002, and October 18, 2002, Moody's further downgraded the senior unsecured debt rating, issuer rating, and syndicated bank credit facilities of PG&E NEG. On October 11, 2002, S&P further downgraded certain of PG&E NEG's debt facilities. The result of these downgrades had left all of PG&E NEG's rated entities and debt instruments at below investment grade. The following table shows the credit ratings of the various debt instruments of PG&E NEG and its affiliates, as well as credit ratings assigned for general creditworthiness of ind ividual entities, updated for the most recent issued ratings.

Standard
& Poor's

Moody's Investors
Service

-----------------

----------------------

Rated Entities:

PG&E NEG

B-

B3

PG&E GTN

BB-

Ba1

PG&E ET

B-

Not Rated

PG&E Gen

B-

Not Rated

USGen New England (USGenNE)

B-

B2

Rated Debt Instruments:

Senior Unsecured Notes, due 2011 (PG&E NEG)

B-

B3

Senior Unsecured Notes, due 2005 (PG&E GTN)

BB-

Ba1

Senior Unsecured Debentures, due 2025 (PG&E GTN)

BB-

Ba1

Senior Unsecured Notes, due 2012 (PG&E GTN)

BB-

Ba1

Medium-term Notes - nonrecourse (PG&E GTN)

BB-

Ba1

Term loans (GenHoldings I, LLC)

CC

B3

The credit ratings assigned to PG&E NEG and its affiliates by both S&P and Moody's are under review for possible further downgrade.

The downgrade of PG&E NEG's credit ratings impacts various guarantees and financial arrangements that require PG&E NEG to maintain certain credit ratings from S&P and/or Moody's. These provisions are referred to as "ratings triggers" and are generally linked to one or more investment grade ratings. When a downgrade event activates a contractual "ratings trigger," PG&E NEG's counterparties may demand that PG&E NEG provide additional security for performance in the form of cash, letters of credit, acceptable replacement guarantees, or advanced funding of obligations. If PG&E NEG fails to provide this additional collateral within defined cure periods, PG&E NEG may be in default under contractual terms. In addition to agreements containing ratings triggers, other agreements allow counterparties to seek additional security for performance whenever the counterparty becomes concerned about PG&E NEG's or its subsidiaries' creditworthiness.

In addition to various requirements to post additional collateral as described above, PG&E NEG's credit downgrades constrain its access to additional capital and trigger increases in the cost of indebtedness under many of its outstanding debt arrangements.

The effects of the credit downgrades on PG&E NEG's debt facilities and other contractual arrangements are described below. Amounts required to be paid under debt agreements and other significant contractual commitments are also described below.

Short-Term Borrowings and Long-Term Debt

The schedule below summarizes PG&E NEG's outstanding short-term borrowings and long-term debts as of September 30, 2002, and December 31, 2001:

(in millions)

Outstanding Balance of

Description

Maturity

Interest
Rates

September 30,
2002

December 31,
2001

-----------------------------------------------------

--------------

--------------------------------

------------------

-----------------

PG&E NEG Senior Unsecured Notes

2011

10.375%

$

1,000

$

1,000

PG&E NEG Credit Facility -
Tranche B (364-day)

11/14/02

LIBOR plus credit spread

431

330

Turbine and Equipment Facility

12/31/03

LIBOR plus credit spread

205

221

PG&E GTN Senior Unsecured Notes

2005

7.10%

250

250

PG&E GTN Senior Unsecured Debentures

2025

7.80%

150

150

PG&E GTN Senior Unsecured Notes

2012

6.62%

100

-

PG&E GTN Medium-Term Notes

Thru 2003

6.83% to 6.96%

6

39

PG&E GTN Credit Facility

5/2/05

LIBOR plus credit spread

-

84

GenHoldings Construction Facility

12/21/06

LIBOR plus credit spread

1,025

450

LaPaloma Construction Facility

3/7/05

LIBOR plus credit spread

646

588

Lake Road Construction Facility

8/28/04

LIBOR plus credit spread

446

417

USGenNE Credit Facility

9/1/03

LIBOR plus credit spread

75

75

Plains End Construction Facility

9/6/06

LIBOR plus credit spread

44

23

Other non-recourse project term loans

Various

Principally LIBOR plus
credit spread

94

100

Mortgage loan payable

2010

CP rate + 6.07%

7

8

Other

Various

Various

17

17

-----------------

-----------------

Total short-term borrowings and long-term debt

$

4,496

$

3,752

==========

==========

Amounts classified as:

Short-term borrowings

$

431

$

330

Long-term debt, classified as current

773

48

Long-term debt

3,292

3,374

-----------------

-----------------

Total short-term borrowings and Long-term debt

$

4,496

$

3,752

==========

==========

Interest is capitalized as a component of projects under construction. For the nine months ended September 30, 2002, and 2001, PG&E NEG capitalized interest of approximately $141 million and $87 million, respectively.

As of September 30, 2002, scheduled maturities of long-term debt were as follows (in millions):

Three months ended December 31, 2002

$

27

Three months ended March 31, 2003

604

Three months ended June 30, 2003

27

Three months ended September 30, 2003

115

Three months ended December 31, 2003

105

2004

24

2005

51

2006

297

2007

1,018

Thereafter

1,797

------------

   Total Long-term debt

4,065

   Short-term borrowings

431

------------

   Total Short-term borrowings and Long-term debt

$

4,496

=======

Through August 22, 2002, PG&E NEG had a $1.25 billion working capital and letter of credit facility consisting of $750 million with a 364-day term and $500 million with a two-year term. The $750 million 364-day revolving credit facility was scheduled to expire and be renewed on August 22, 2002. On August 22, 2002, PG&E NEG and the lenders under the revolving credit facilities entered into an amendment to the credit facilities, which extended the expiration and renewal date of the 364-day facility to October 21, 2002, and reduced the available commitments under that facility to $500 million. As of September 30, 2002, $431 million had been drawn against the 364-day revolving credit facility and $277 million of letters of credit had been issued against the two-year facility.

On October 21, 2002, PG&E NEG and the lenders under the 364-day and two-year revolving credit facilities entered into a further amendment to the credit facilities, which extended the expiration and renewal date to November 14, 2002. The amendment (1) reduces the lenders' commitments under the 364-day facility and the two-year facility to $431 million and $273 million, respectively, which are the amounts outstanding as of October 21, 2002, (2) prohibits PG&E NEG from making any payment for the Athens, Covert, Harquahala and La Paloma generating projects under construction, and (3) changes the interest payment schedule from quarterly to monthly. PG&E NEG does not expect to repay the 364-day tranche on November 14, 2002, nor does PG&E NEG expect a further extension of the maturity date.

PG&E NEG also has other revolving credit facilities held by subsidiaries, including a $125 million facility held by PG&E GTN, a $100 million facility held by USGenNE, and a $205 million equipment revolving credit facility held by PG&E NEG Construction Company, a subsidiary of PG&E NEG. These facilities relate specifically to funding requirements of these entities and are not available to PG&E NEG.

Under the terms of the various revolving credit facilities, the credit spread component of the interest rates and fees charged for borrowings was increased as a result of PG&E NEG's credit downgrades. PG&E NEG's credit downgrades through October 18, 2002, did not trigger any acceleration of payments due under its long-term debt arrangements.

On May 2, 2002, PG&E GTN entered into a three-year $125 million revolving credit facility at an interest rate based on the London Interbank Offer Rate (LIBOR) plus a credit spread of initially 0.725 percent that, as a result of the downgrades, has increased to 1.45 percent. The credit spread percentage corresponds to a rating issued from time to time by S&P or Moody's on PG&E GTN's senior unsecured long-term debt. This three-year facility replaced a $100 million bank facility that was scheduled to expire. At September 30, 2002, there were no outstanding borrowings under this facility.

On June 6, 2002, PG&E GTN issued $100 million of 6.62 percent Senior Notes due on June 6, 2012. Proceeds were used to repay $90 million of debt on its revolving credit facility, and the balance retained to meet general corporate needs. A commitment from a financial institution for a back-up 364-day bank facility, obtained in the event PG&E GTN had decided to postpone such long-term financing, was correspondingly terminated.

On April 5, 2002, GenHoldings I, LLC (GenHoldings), an indirect subsidiary of PG&E NEG, increased its committed financing from $1.075 billion to $1.460 billion. At September 30, 2002, the outstanding balance under this facility was $1.025 billion. The increase in the facility was intended to provide for additional borrowing capacity for, and be secured by, an additional project, Covert, which is currently under construction.

PG&E NEG's efforts to reduce debt or raise cash through various efforts, including asset sales, have failed to produce adequate sources of liquidity for PG&E NEG to meet its obligations. PG&E NEG, therefore, has been in active negotiations with the lenders under the Corporate Revolver, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities and the Turbine Revolver as well as with representatives of the holders of the Senior Notes. PG&E NEG has proposed a global restructuring of these debt facilities which would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG's merchant assets and reduce energy trading operations. If agreed to by PG&E NEG's lenders and implemented by PG&E NEG, these various asset transfers, sales and abandonments would cause substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

If the restructuring cannot be achieved by agreement with PG&E NEG's creditors, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. Notwithstanding the restructuring efforts above, if PG&E NEG abandons, sells or transfers assets in an effort to meet current liquidity needs or other strategic efforts, PG&E NEG would incur substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

Letters of Credit

In addition to outstanding balances under the above credit facilities PG&E NEG has commitments available under these facilities and other facilities to issue letters of credit. The following table lists the various facilities that have the capacity to issue letters of credit:

(in millions)
Borrower

Maturity

Letter of
Credit
Capacity

Letter of Credit
Outstanding
September 30, 2002

----------------

--------------

-------------------

-------------------------

PG&E NEG

8/03 ⁽¹⁾

$

279

$

277

USGenNE

8/03

25

15

PG&E Gen

12/04

10

7

PG&E ET

12/02

25

24

PG&E ET

- ⁽²⁾

50

49

PG&E ET

11/03

35

34

⁽¹⁾
On October 21, 2002, PG&E NEG and the lenders under the two-year revolving credit facility entered into an amendment which reduced the lenders' commitments to $273 million, which is the amount outstanding at October 21, 2002.

⁽²⁾
This letter of credit facility provides for up to $50 million of non-domestic letters of credit to be issued, available to PG&E Energy Trading, Canada Corporation, an indirect subsidiary of PG&E NEG, to use to post non-domestic letters of credit to support counterparty obligations. There is no term for the facility, but the bank can review it for termination each year.

Construction-Related Equity Commitments

GenHoldings Equity Commitment

Under the GenHoldings credit facility, GenHoldings is committed to make equity contributions to fund construction of the Harquahala, Covert, and Athens generating projects. This credit facility is secured by these projects in addition to the Millenium generating facility. PG&E NEG has guaranteed GenHoldings' equity commitment. Due to the downgrade to below investment grade by both S&P and Moody's, PG&E NEG, as guarantor, became required to fund construction draws under the GenHoldings credit facility entirely with equity, until GenHoldings' full equity commitment was fulfilled. After GenHoldings fulfilled its equity commitment, the lenders were to fund construction draws in accordance with the credit facility. In August and September 2002, PG&E NEG funded approximately $150 million of the equity commitments, with the outstanding equity commitment at September 30, 2002, remaining at $355 million. In October 2002, PG&E NEG notified the lenders under the GenHoldings credit facility that it would not make further equity contributions on behalf of GenHoldings. On October 24, 2002, GenHoldings and the lenders entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders waived through November 14, 2002, existing defaults under the GenHoldings credit agreement, permitted GenHoldings to borrow up to $50 million, and agreed to issue specified letters of credit in a face amount not to exceed $36 million. On October 25, 2002, the lenders funded GenHoldings' pending draw request for the Athens, Covert, and Harquahala construction projects. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. PG&E NEG does not expect an extension to this forbearance.

La Paloma Equity Commitment

PG&E NEG guaranteed the repayment of certain debt representing La Paloma's equity commitment in the aggregate amount of $379 million, which is due in March 2003. Due to the downgrade to below investment grade by both S&P and Moody's, PG&E NEG, as guarantor, became required to make equity contributions under the La Paloma credit facility to fund construction costs. In October 2002, PG&E NEG funded $4.5 million of construction costs reducing the outstanding equity commitment at October 31, 2002, to $374.5 million. In October 2002, PG&E NEG notified the lenders under the La Paloma credit facility that it would not make further payments of construction costs for La Paloma. On November 8, 2002, PG&E NEG and the La Paloma lenders entered into a waiver agreement pursuant to which, among other things, the lenders waived existing defaults and funded, on November 8, 2002, the pending draw request to pay construction costs. PG&E NEG does not currently expect to have sufficient funds to make the $374.5 million payment in March 2003.

Lake Road Equity Commitment

PG&E NEG guaranteed the repayment of certain debt representing Lake Road's equity commitment in the aggregate amount of $230 million, which is due in March 2003. Lake Road entered commercial operation in May 2002. PG&E NEG does not currently expect to have sufficient funds to make this payment in March 2003.

Activities Related to Merchant Portfolio Operations

PG&E NEG and certain subsidiaries have provided guarantees to approximately 250 counterparties in support of PG&E ET's energy trading and non-trading activities related to PG&E NEG's merchant energy portfolio in the face amount of $2.8 billion (including $69 million in guarantees pursuant to pipeline tariff provisions and $89 million in guarantees to power pools which have an aggregate exposure of less than $1 million). Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully utilized at any time. As of September 30, 2002, PG&E NEG and its rated subsidiaries' aggregate exposure under these guarantees was approximately $200 million, as follows: PG&E NEG $80 million, PG&E GTN $79 million, PG&E ET $39 million, and USGenNE $2 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, so me counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its various subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At September 30, 2002, PG&E ET's estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $95 million.

To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged default. No demand has been made upon the guarantors of PG&E ET's obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET's liquidity. The actual calls for collateral will depend largely upon counterparties' responses to the ratings downgrades, mutual forbearance as many counterparties also have been downgraded, pre- and early-pay arrangements, the continued performance of PG&E NEG companies under the u nderlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties' other commercial considerations. PG&E NEG's and its subsidiaries' ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG's financial condition and the degree of liquidity in the energy markets.

Tolling Agreements

The face amount of PG&E NEG's and its subsidiaries guarantees relating to PG&E ET's tolling agreements is approximately $600 million. The five tolling agreements are with (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million, (2) DTE-Georgetown, L.P. (DTE) guaranteed by PG&E GTN for up to $24 million, (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place, (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $176 million, and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty

Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to post security in the amount of $150 million. PG&E ET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of the guarantees to Liberty for the aggregate $150 million, Liberty must first proceed against PG&E NEG's guarantee, and can demand payment under PG&E GTN's guarantee only if (1) PG&E NEG is in bankruptcy, or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has the right to t erminate the agreement and seek recovery of a termination payment.

DTE

By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

Calpine

The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement, and construction contractor for the Otay Mesa facility. On October 16, 2002, PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002, that it was terminating the tolling agreement effective November 29, 2002. PG&E NEG was required to provide in December 2002, a guarantee of PG&E ET's payment obligations under a 10-year tolling agreement with Calpine involving the Otay Mesa facility. The guarantee amount was not to exceed $40 million. As a result of the termination of the tolling agreement, PG&E NEG believes it is no longer obligated to provide a guarantee.

Southaven

PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade, as defined in the agreement. The amount of the guarantee now does not exceed $176 million. The original maximum amount of the guarantee was $250 million, but this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002, pursuant to a subordinated loan agreement between PG&E ET and Southaven entered into as of that date. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the agreement and because PG&E ET ha d failed to provide, within 30 days from the downgrade, substitute credit support that meets the requirement of the agreement. Under the agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition PG&E ET has provided Southaven with a notice of default respecting Southaven's performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Caledonia

PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade, as defined in the agreement. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the agreement and because PG&E ET had failed to provide, within 30 days from the affiliate's downgrade, substitute credit support that meets the requirement of the agreement. Under the agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia's performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG believes that its exposure under these guarantees will be less than $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to be able to pay all of the termination payments if they become due.

Other Guarantees

PG&E NEG has provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction and equipment procurement contracts. In the event PG&E NEG is unable to provide any additional or replacement security which may be required as a result of the downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG's power plants and pipelines. These guarantees are described below.

PG&E NEG has issued guarantees for the performance of the contractors building the Harquahala and Covert power projects for up to $555 million. Any exposure under the guarantees for construction completion is mitigated by guarantees in favor of PG&E NEG from the constructor and equipment vendors related to performance, schedule, and cost. The constructor and various equipment vendors are performing under their underlying contracts. On August 8, 2002, PG&E NEG replaced the ratings triggers contained in $555 million of guarantees for the performance of the contractors building the Harquahala and Covert power projects with financial covenants that are consistent with those contained in PG&E NEG's revolving credit and other loan facilities.

PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. Failure to perform under those separate cost-sharing arrangements or the related guarantees would not have an impact on the constructor's obligations to complete the Harquahala and Covert projects pursuant to the construction contracts. However, in the event that the construction contractor incurs certain unreimbursed project costs or cost overruns, the contractor could assert a claim against PG&E NEG's subsidiary or PG&E NEG under its guarantees. PG&E NEG believes that no claim can be validly asserted by the construction contractor as of the date hereof.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly-owned subsidiary, Attala Energy Company, has entered into with Attala Generating Company. Attala Generating Company entered into a $340 million sale-leaseback transaction. The tolling payments provide the lessee with sufficient cash flows to pay rent under the lease. PG&E may stop making cash infusions to Attala Energy Company, which could cause a default under the Attala sale-leaseback financing. Attala Energy Company is currently experiencing a negative cash flow performing under this agreement and requires cash infusions in order to perform its obligation.

To support PG&E NEG's electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG has issued guarantees with an aggregate face value of up to approximately $175 million in connection with these equipment commitments. PG&E NEG's commitment to purchase combustion turbines and related equipment exceeds its current planned development activities. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due in January and July 2003. Beginning in September 2003, PG&E NEG must either restart equipment payments or, for equipment requiring progress payments, terminate such commitments and pay the associated termination costs. PG&E NEG estimates these termination costs, and its exposure under these guarantees, to be approximate ly $53 million as of October 31, 2002 (including the $14 million as of October 31, 2002).

The balance of the guarantees are for commitments undertaken by PG&E NEG or subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

Other Commitments

PG&E NEG's subsidiary has entered into a construction contract for the Mantua Creek project and released the contractor to perform early construction activities; however, full mobilization of the construction contractor has not taken place and unrestricted construction has not occurred. On October 8, 2002, PG&E NEG's subsidiary suspended all construction activities related to Mantua Creek. As of September 30, 2002, PG&E NEG's subsidiary had recorded assets of $269 million for Mantua Creek, representing equipment payments, construction activities, development costs and gas transmission deposits. If PG&E NEG's subsidiary terminates construction of this project, its construction contractor and other equipment and service providers would be entitled to termination costs estimated to be $64 million. PG&E NEG's subsidiary would receive a refund due from its turbine vendor of approximately $31 million. The construction contractor and other equipment and service providers are the be neficiaries of letters of credit issued on behalf of Mantua Creek by PG&E NEG in the amount of approximately $37 million. The termination costs do not include remediation costs estimated to be $1 million.

PG&E NEG's subsidiary has executed construction contracts for its Smithland and Cannelton projects for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. As of September 30, 2002, PG&E NEG's subsidiary had recorded assets of $1.8 million for these projects, representing equipment payments and development costs. PG&E NEG's subsidiary had commenced construction of the first 16 MW of turbines for the Smithland project, but had suspended construction because recently stated seismic requirements caused a re-evaluation of the project's design in connection with the Army Corps of Engineers permit. The re-evaluation is complete and the U.S. Army Corps of Engineers concurs that the new seismic criteria will not require any design changes. PG&E NEG's subsidiary has not resumed construction. The construction contractor is the beneficiary of a letter of credit securing PG&E NEG's subsidiary's termination payment obligations. If PG&E NEG's subsidiary terminates construction of this project, the construction contractor will be entitled to draw on the letter of credit for approximately $7 million.

Material Notices

PG&E NEG and its subsidiaries have received various notices under major contracts (other than the tolling agreements described above) alleging anticipatory breaches of contract and defaults resulting from PG&E NEG's downgrades and its public statements regarding its decisions not to make certain payments. These notices include claims from at least one counterparty to a power supply agreement. In most cases, PG&E NEG or its subsidiary has disputed these allegations. In all cases, the counterparties have refrained from attempting to pursue remedies. The Shaw Group, Inc. (Shaw) has alleged anticipatory breaches of the construction contracts for each of the Covert and Harquahala projects based upon PG&E NEG's announcement that it would not further fund the GenHoldings projects, including the Covert and Harquahala projects. Covert and Harquahala have disputed these notices because they are current in their payments to Shaw. Shaw also has sought reinstatement of pre-financing guarantee s ($50 million each) originally issued in connection with the Covert and Harquahala projects. PG&E NEG has denied that the guarantees are reinstated because the financing arrangements remain in place. Finally, Shaw also has sought cash collateralization of PG&E NEG's $100 million of guarantees supporting Shaw's cost-sharing agreements with a subsidiary. PG&E NEG has reviewed the guarantees and informed Shaw that the guarantees do not contain any collateralization requirement.

Bechtel Power Corporation (BPC) has alleged a default based upon PG&E NEG's announcement that it would not further fund the GenHoldings projects, including the Athens project. Athens has disputed this notice because the lenders have continued to fund and BPC is the beneficiary of an escrow account covering future costs that is currently over-funded. BPC has also alleged a default for nonpayment at the Mantua Creek project. Mantua Creek has 30 days to cure this nonfunding. If it does not do so, BPC is the beneficiary of a letter of credit posted on behalf of the Mantua Creek project which is sufficient to cover such payment.

Mitsubishi Power Systems, Inc. (MPS) has alleged a default under its contract for the sale and purchase of gas turbines and other equipment for failure to pay $14 million. PG&E NEG's subsidiary has disputed this default notice because the payments are not due until January and July 2003. MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG has informed MPS that no such collateral would be delivered. Non-performance under the guarantee is not a default under the turbine purchase agreement.

Costs Incurred in a Restructuring

In the third quarter of 2002, PG&E NEG initiated a restructuring effort in order to adopt a new organizational structure that more closely reflects PG&E NEG's business strategies. The termination benefits accrued and charged to earnings in the third quarter were $9.3 million and are principally included in "Operating and Maintenance" in the operating expenses of PG&E Corporation's Consolidated Statements of Income. There were 178 employees who were affected by this restructuring of which 161 were terminated as of September 30, 2002 (for which $8.5 million of termination benefits were charged against the liability). All employee groups were impacted by this restructuring with the primary focus on employees involved in project development.

In addition to these termination costs, PG&E NEG accrued and charged to earnings $9.4 million due to the closing of certain regional offices associated with project development and other third party costs related to the organizational restructuring efforts. These costs were recorded in the third quarter of 2002 and are included in "Operating and Maintenance" in the operating expenses of PG&E Corporation's Consolidated Statements of Income for the three and nine months ended September 30, 2002.

Subsequent Events

Sale of Interest in Hermiston

On November 4, 2002, affiliates of PG&E NEG entered into an agreement to sell 49.9 percent of its ownership interest in Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo Corporation of America. The buyer was granted an option to purchase, during the three month period beginning thirteen months immediately following the closing date, an additional 0.1 percent interest (at the fair market value at the date of exercise). HGC owns an undivided 50 percent interest in a 474 MW gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned by PacifiCorp who also purchases the output of the plant under a long-term contract. The sale is expected to be completed by December 31, 2002, following the receipt of necessary regulatory approvals. At September 30, 2002, book value of PG&E NEG's investment in HGC was approximately $44 million. PG&E NEG anticipates a pre-tax gain of approximately $23 million upon completion of the sale.

Closing of Spencer Station

On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating plant located in Denton, Texas. PG&E NEG acquired the 178 MW gas-fired plant in June 2001 and in addition PG&E ET entered into a contract to provide the full service power requirements of the city of Denton for a period of five years beginning July 1, 2001. Despite the closing of the Spencer Station plant, PG&E ET will continue to provide the power requirements under this contract. Completion of the shut down is expected by December 2002. PG&E NEG will incur a pre-tax loss upon shut down of approximately $4 million which includes costs associated with decommissioning the plant and employee terminations.

NOTE 4: DEBT FINANCING
PG&E Corporation

In November 2001 and March 2002, PG&E Corporation amended its March 1, 2001, Credit Agreement (Old Credit Agreement) with GECC and Lehman Commercial Paper Inc. (LCPI) and their assignees (Existing Lenders). The amendments provided PG&E Corporation the option to extend the original $1 billion aggregate term loan credit facility for two one-year periods so that the maturity date could be extended until as late as March 2, 2006, contingent upon PG&E Corporation making a principal repayment of $308 million by June 3, 2002. On June 3, 2002, PG&E Corporation made the principal repayme nt of $308 million, utilizing current working capital and reducing the principal balance outstanding under the Old Credit Agreement to $692 million.

On June 25, 2002, PG&E Corporation entered into an Amended and Restated Credit Agreement with GECC, LCPI and other lenders, which amended and restated the Old Credit Agreement. This Agreement provided for loans in two tranches. Tranche A had a principal amount of $600 million, and the same maturity date and extension provision as the Old Credit Agreement; Tranche B had a principal of $420 million, which consisted of $92 million of the Old Credit Agreement balance and $328 million of new borrowings.

As a result of various downgrades by S&P of PG&E NEG's and its various subsidiaries' credit ratings on July 31, 2002, PG&E Corporation sought and obtained on August 4, 2002, from the Tranche A and Tranche B lenders a waiver of the requirement in the June 25, 2002, Amended and Restated Credit Agreement that PG&E NEG maintain investment grade credit ratings with either S&P or Moody's. On August 5, 2002, Moody's also downgraded the credit ratings of PG&E NEG and PG&E NEG's other operating subsidiaries. Because a waiver was in place, no event of default was triggered under the Amended and Restated Credit Agreement.

On August 30, 2002, PG&E Corporation made a voluntary prepayment of Tranche A aggregate principal of $600 million, plus interest totaling approximately $6.7 million to GECC. The prepayment released PG&E Corporation from maintaining a $90 million restricted cash requirement of interest income. The remaining lenders extended until October 4, 2002, the waiver of the Amended and Restated Credit Agreement requirement that PG&E NEG continue to maintain investment grade ratings with either S&P or Moody's, and later extended this further to October 18, 2002. As a result of the Tranche A prepayment, PG&E Corporation wrote off $83 million of unamortized loan fees and reversed $38 million of unamortized loan discount associated with unvested options, netting to a $45 million charge to interest expense. In relation to the Tranche B loan, PG&E Corporation also recorded $70 million of debt extinguishment losses to interest expense, as a result of the new waiver extension.

On October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement (Credit Agreement), with the lenders party thereto, LCPI, as Administrative Agent, and others. Under the terms of the Credit Agreement, the existing $420 million Tranche B loan previously made by certain of the lenders has been modified (as modified, the Tranche B Loan) and certain of the lenders have made new incremental loans in the aggregate principal amount of $300 million (New Loans) with the same terms and conditions as those applicable to the Tranche B Loan. The Tranche B loan and the New Loans are collectively referred to herein as the "Loans." The New Loans have been funded into a separate escrow account and will be released to PG&E Corporation on January 17, 2003, unless a bankruptcy proceeding has been commenced by or against PG&E Corporation. The Loans are payable in a single installment on September 2, 2006, unless prepaid earlier in accordance with the Credit Agreement.

The interest rate for the continued Tranche B loan is the Eurodollar Rate plus 10.0 percent. The first interest payment of the continued Tranche B loan is payable on January 17, 2003.

On January 17, 2003, upon the release of the New Loan from escrow, PG&E Corporation must pay a funding fee on the New Loan escrowed amount calculated using the Eurodollar Rate plus 10.0 percent. The funding fee is estimated to be approximately $9 million, calculated using an estimated Eurodollar rate of 1.83 percent plus 10.0 percent, over a 91-day period.

After January 17, 2003, the interest rate for both the continued Tranche B and the New Loan will be the Eurodollar Rate plus 10.0 percent. PG&E Corporation can elect an interest period of one, two, three, or six months, with accrued interest payable on the last day of each interest period, at least on a quarterly basis.

In addition, at the start of both first interest periods, after the extension of the continued Tranche B loan and the receipt from escrow of the New Loan funds, the principal amount is charged by the Payment-in-Kind (PIK) interest per annum of 4.0 percent. The PIK interest is included subsequently within the principal amount, and for each of the interest periods thereafter, upon which the Eurodollar Rate plus 10.0 percent and additional PIK interest rates are applied.

The Tranche B loan and the New Loans are senior unsubordinated obligations of PG&E Corporation, which are pari passu with each other. Notwithstanding the foregoing, so long as the options granted to certain lenders of PG&E Corporation to purchase shares of PG&E NEG pursuant to the Amended and Restated Option Agreement entered into on June 25, 2002 (Option Agreement) remain outstanding, the obligations of PG&E Corporation in respect of such options are senior to its obligations in respect of the Loans to the extent provided in the Intercreditor Agreement previously entered into on June 25, 2002, among the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002. So long as the options remain outstanding, the Intercreditor Agreement will remain in effect to define the extent to which the obligations of PG&E Corporation in respect of such options are senior to its obligations in respect of the Loans. On September 3, 2002, GECC gave PG&E Corporation notic e that it would put its options to PG&E Corporation under the Option Agreement, and GECC and PG&E Corporation were engaged in a process of appraising the options as provided under the Option Agreement. Before completion of the appraisal process, GECC gave PG&E Corporation on October 30, 2002, a notice purporting to rescind its earlier put notice. PG&E Corporation is currently engaged in discussions with GECC with respect to the latter notice. PG&E Corporation and PG&E National Energy Group, LLC, (PG&E NEG LLC), a subsidiary of PG&E Corporation which owns 100 percent of the common stock of PG&E NEG, have agreed with the other holders of options under the Option Agreement that they may exercise their put option on the same terms as those received by GECC within 45 days after the closing of GECC's put option, and that, if not exercised within such 45-day period, the put option is exercisable any time prior to March 1, 2003.

All obligations of PG&E Corporation with respect to the Loans are secured by a perfected first priority security interest in 100 percent of the equity interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG, and all proceeds thereof (collectively, PG&E NEG Collateral); such security interests secure equally and ratably the portions of the Loans held by each lender. PG&E Corporation is not permitted to dispose of the PG&E NEG Collateral except under certain circumstances. Any proceeds to PG&E Corporation of a permitted disposition of the PG&E NEG Collateral must be applied to prepay the Loans. PG&E Corporation may spin off the PG&E NEG Collateral only with the consent of lenders holding more than 50.1 percent of the aggregate outstanding principal amount of the Loans.

In addition, all obligations of PG&E Corporation with respect to the Loans are secured by a perfected first priority security interest in the outstanding common stock of PG&E Corporation's subsidiary, the Utility, and all proceeds thereof. With respect to 35 percent of such common stock pledged for the benefit of the lenders, the lenders have customary rights of a pledgee of common stock, provided that certain regulatory approvals may be required in connection with any foreclosure on such stock. With respect to the remaining 65 percent, such common stock has been pledged for the benefit of the lenders, but the lenders 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 lenders do have the right to receive any cash proceeds received upon a disposition of such common stock.

In connection with the consummation of the Utility's proposed plan of reorganization (Utility's Plan) in the Utility's bankruptcy proceeding pending in the Bankruptcy Court, the Utility has formed a new corporation (Newco) to hold the equity interests in three limited liability companies (Reorganization Subsidiaries) formed to hold certain assets of the Utility. The Utility's Plan contemplates that, after the transfer of such assets to the Reorganization Subsidiaries, the Utility will distribute the common stock of Newco to PG&E Corporation (the Newco Spin) and PG&E Corporation will distribute the common stock of the Utility to the shareholders of PG&E Corporation (collectively, the Spin). Pursuant to the Credit Agreement and the Pledge Agreements pledging the common stock of the Utility, PG&E Corporation may substitute common stock of Newco for the common stock of the Utility in connection with the consummation of the Utility's Plan.

Finally, all obligations of PG&E Corporation with respect to the Loans are secured by a perfected first priority security interest in substantially all other personal property assets of PG&E Corporation with certain exceptions, including, without limitation, deposit accounts, securities accounts, and cash equivalents (other than proceeds of other collateral).

PG&E Corporation is required to make an offer to prepay the Loans (including prepayment premiums) upon a change in control of PG&E Corporation. PG&E Corporation also is required to make an offer to prepay the Loans (including prepayment premiums), at least 45 days before (1) a spin-off under any plan of reorganization: (a) to the shareholders of PG&E Corporation of (i) all or any portion of the Utility, Newco, or any of the Reorganization Subsidiaries or (ii) any of the material assets that are contemplated by the Utility's Plan to be transferred to Newco or any Reorganization Subsidiary or retained by the Utility (Material Reorganization Assets), or (b) to PG&E Corporation of (i) all or any portion of Newco or any of the Reorganization Subsidiaries or (ii) any Material Reorganization Assets, or (2) the sale or issuance of more than 15 percent of the capital stock of the Utility pursuant to a plan of reorganization.

In addition, if on the date 31 days after confirmation of any plan of reorganization that does not involve a spin-off or sale of more than 15 percent of the capital stock of the Utility or on the first day of any calendar quarter thereafter, the ratio of (i) the aggregate market value of the common stock of PG&E Corporation for the preceding 30 trading days to (ii) the aggregate outstanding amount of the Loans is less than 5.0:1.0, then PG&E Corporation is required to make an offer to prepay the Loans (including prepayment premiums) on the date 30 days thereafter.

PG&E Corporation is required to maintain an interest reserve account of at least $130 million until September 2, 2005, and thereafter, an amount equal to the lesser of $130 million or the interest to accrue on the Loans through maturity.

The Credit Agreement continues to contain certain limitations on the ability of PG&E Corporation and certain of its subsidiaries to grant liens, consolidate, merge, purchase or sell assets, declare or pay dividends, incur indebtedness, or make advances, loans, and investments. However, the Credit Agreement does not limit (1) the ability of PG&E NEG LLC, PG&E NEG, or their respective subsidiaries to grant liens or incur debt, or (2) PG&E Corporation's and the Utility's ability to consummate the transactions contemplated in the Utility's Plan. The Credit Agreement generally permits PG&E NEG LLC, PG&E NEG, and their respective subsidiaries to enter into sales and other disposition of assets in the ordinary course of business and in certain qualified transactions. In addition, in connection with certain sales and debt restructuring transactions of PG&E NEG and its subsidiaries, PG&E Corporation is permitted to use existing cash to make investments in PG& amp;E NEG. The amount of such investments is limited to 75 percent of the net cash tax savings (less certain costs and expenses) actually received by PG&E Corporation after October 1, 2002, as a result of certain transactions of PG&E NEG and its subsidiaries. PG&E Corporation also is permitted to make investments funded from existing cash, and to pay obligations of PG&E NEG and its subsidiaries (including, without limitation, any obligations for which PG&E Corporation becomes a surety or a guarantor) up to a cumulative amount not to exceed $15 million, provided that no default or event of default has occurred under the Credit Agreement, and provided further that PG&E NEG LLC and PG&E NEG are not in bankruptcy. The proceeds of the New Loans may not be used to make investments in PG&E NEG LLC or PG&E NEG, or any of their subsidiaries.

The Credit Agreement has been amended to delete provisions that required PG&E NEG to maintain certain credit ratings and required that a certain ratio of fair market value of PG&E NEG to the aggregate amount of the outstanding Loans be maintained. Further, the Credit Agreement no longer provides that a default or event of default under agreements of PG&E NEG or its subsidiaries constitutes a cross-default under the Credit Agreement.

Among other events, the Credit Agreement provides that an event of default occurs if PG&E Corporation fails to pay any indebtedness of $100 million or more when due, if the holders of PG&E Corporation indebtedness of $100 million or more become entitled to accelerate such indebtedness, or if any PG&E Corporation indebtedness of $100 million or more is accelerated. Upon the occurrence of an event of default, the lenders may declare the Loans immediately due and payable.

The Loans may be prepaid upon payment of a prepayment fee equal to (1) if such prepayment is made on or prior to October 1, 2003, the discounted present value of 2.50 percent of the principal amount of such prepayment plus the aggregate amount of interest that would accrue on the principal amount of such prepayment from the date of such prepayment to October 1, 2003, (2) if such prepayment is made after October 1, 2003 and on or prior to October 1, 2004, 2.50 percent of the principal amount prepaid, and (3) if such prepayment is made after October 1, 2004, 0.50 percent of the principal amount prepaid.

The Credit Agreement also generally requires mandatory prepayments of the Loans with the net cash proceeds from (1) incurrence of indebtedness, (2) issuance or sale of equity by PG&E Corporation or the Utility, (3) sales of assets by PG&E Corporation, PG&E NEG, PG&E NEG LLC, or any subsidiary of PG&E NEG (with a carve-out for proceeds retained by PG&E NEG), (4) the receipt of condemnation or insurance proceeds, (5) and distributions or dividends paid to PG&E Corporation or PG&E NEG LLC. PG&E Corporation also must pay a prepayment fee upon mandatory prepayment.

PG&E Corporation also has issued to the lenders additional warrants to purchase 2,669,390 shares of common stock of PG&E Corporation. The number of warrants was calculated by dividing 3.5 percent of the aggregate principal amount of the Loans ($25.2 million) by the average of the volume-weighted average price of PG&E Corporation common stock as reported on the New York Stock Exchange for each of the 10 trading days beginning on October 10, 2002, and ending October 24, 2002. The terms and provisions of the warrants, including a warrant exercise price of $0.01 per share, are substantially identical to the warrants previously issued to the Tranche B lenders on June 25, 2002. PG&E Corporation has agreed to provide, following consummation of a plan of reorganization of the Utility, registration rights in connection with the shares issuable upon exercise of these warrants.

The net proceeds of the New Loans will be used to fund corporate working capital and for general corporate purposes and may not be used to make investments in PG&E NEG LLC, PG&E NEG, or any of their respective subsidiaries or, except as required by applicable law or the conditions adopted by the CPUC with respect to holding companies, in the Utility.

PG&E Corporation's 7.50 percent Convertible Subordinated Notes due 2007 in the aggregate principal amount of $280 million issued on June 25, 2002, (Notes) and the Indenture relating to the Notes have been amended to delete certain cross-default provisions which provided that a non-payment or an acceleration of indebtedness of PG&E NEG or any of its subsidiaries, or a bankruptcy event with respect to PG&E NEG or any of its subsidiaries, constituted a default or event of default under the Notes and the Indenture. Further, the Indenture and the Notes have been amended, among other things, to increase the interest rate on the Notes to 9.50 percent from 7.50 percent, to extend the maturity of the Notes to June 30, 2010, from June 30, 2007, and to provide the holder of the Notes with a one-time right to require PG&E Corporation to repurchase the Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including any liquidated damages and pass-t hrough dividends, if any).

Under the Option Agreement discussed above, certain lenders were granted warrants to purchase certain quantities of PG&E NEG shares. These warrants are marked to market on a monthly basis. In the third quarter of 2002, PG&E Corporation recorded other income of $71 million, as a result of the change in market value of the PG&E NEG warrants during that period. As discussed above, the appraisal process to determine the value of PG&E NEG has not concluded. If it is determined that PG&E NEG's value is greater than the value currently reflected in the mark-to market accounting, PG&E Corporation would be required to incur a charge to earnings as a result of the increased valuation.

NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES

On November 28, 1995, PG&E Capital I (Trust), a wholly owned subsidiary of the Utility, issued 12 million shares of 7.90 percent Cumulative Quarterly Income Preferred Securities (QUIPS) with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of $9 million. The Trust, in turn, used the net proceeds from the QUIPS offering and the proceeds from issuance of the common stock securities to purchase 7.90 percent Deferrable Interest Subordinated Debentures (QUIDS), due 2025, issued by the Utility with a face value of $309 million.

Distribution may be deferred up to 20 consecutive quarters under the terms of the indenture. Pursuant to the indenture, investors will accumulate interest on the unpaid distributions at a rate of 7.90 percent. Upon liquidation or dissolution of the Utility, holders of QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment.

On March 16, 2001, the Utility deferred quarterly interest payments on the QUIDS until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90 percent QUIPS issued by the Trust, due on April 2, 2001, similarly were deferred.

As discussed in Note 2, on March 27, 2002, the Bankruptcy Court issued an order authorizing the Utility to pay pre- and post-petition interest to holders of certain undisputed claims, including QUIPS, within 10 business days after Bankruptcy Court approval of the Utility's disclosure statement. The disclosure statement was approved on April 24, 2002. On May 6, 2002, and May 31, 2002, the Utility made payments to holders of QUIPS representing interest accrued through February 28, 2002, and for the month ended March 31, 2002, respectively. On July 1, 2002, and September 30, 2002, the Utility made additional interest payments covering the three-month periods ended June 30, 2002, and September 30, 2002, respectively; the Utility will continue to make quarterly interest payments as scheduled.

On April 12, 2001, Bank One, N.A., as successor-in-interest to The First National Bank of Chicago (Trustee), gave notice that an event of default exists under the Trust Agreement due to the Utility's Chapter 11 filing on April 6, 2001 (see Note 2). As a result of the event of default, the Trust Agreement required the Trust to be liquidated by the Trustee by distributing the QUIDS, after satisfaction of liabilities to creditors of the Trust, to the holders of the QUIPS. 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 QUIDS. The terms and interest payments of the QUIDS correspond to the terms and dividend payments of the QUIPS.

The QUIDS are included in financing debt classified as a liability subject to compromise in the accompanying PG&E Corporation and Utility Consolidated Balance Sheets at September 30, 2002.

NOTE 6: PRICE RISK MANAGEMENT

PG&E Corporation, primarily through its subsidiaries, engages in price risk management (PRM) activities for both non-trading and trading purposes. Non-trading activities are conducted to optimize and secure the return on risk capital deployed within PG&E NEG's existing asset and contractual portfolio. PG&E Corporation conducts trading activities principally through its unregulated lines of business. Trading activities are conducted to generate profit, create liquidity, and maintain a market presence. Net open positions often exist or are established due to PG&E NEG's assessment of and response to changing market conditions. In addition, non-trading activities existed within the Utility in prior years to hedge against price fluctuations of electricity and natural gas.

Derivative instruments associated with non-trading activities are accounted for in accordance with SFAS No. 133, and ongoing interpretations of the FASB's DIG. Derivatives and other financial instruments associated with trading activities in electric power and other energy commodities are accounted for using the mark-to-market method of accounting in accordance with EITF 98-10.

Derivatives associated with both trading and non-trading activities include forward contracts, futures, swaps, options, and other contracts.

A forward contract is a commitment to purchase or sell energy commodities at a specified future date at a specified price.

A futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell an energy commodity or financial instruments at a specified future date at a specified price.

A swap agreement requires payments for a quantity of an energy commodity based upon the difference between agreed upon prices.

An option contract provides the right, but not the obligation, to buy or sell the underlying commodity at a predetermined price in the future.

Non-Trading Activities

At September 30, 2002, PG&E Corporation had cash flow hedges of varying durations associated with commodity price risk, foreign currency risk, and interest rate risk, the longest of which extend through December 2011, December 2004, and March 2014, respectively. The amount of commodity hedges included in Accumulated Other Comprehensive Income or Loss (OCI), net of taxes, at September 30, 2002, was a loss of $4 million. The amount of interest rate hedges included in OCI, net of taxes, at September 30, 2002, was a loss of $192 million. The amount of foreign currency hedges included in OCI, net of taxes, at September 30, 2002, was a loss of $2 million.

PG&E Corporation's net derivative losses included in OCI at September 30, 2002, were $198 million, of which net losses of $56 million are expected to be reclassified into earnings within the next 12 months. The actual amounts reclassified from accumulated other comprehensive loss to earnings will differ as a result of market price changes. The Utility did not have any cash flow hedges for the three and nine months ended September 30, 2002. The Utility's ineffective portion of changes in amounts of cash flow hedges was immaterial for the three and nine months ended September 30, 2001.

The schedule below summarizes the activities affecting accumulated other comprehensive income (loss), net of tax, from derivative instruments:

(in millions)

Three months ended
September 30, 2002

Nine months ended
September 30, 2002

------------------------------

-----------------------------

PG&E
Corporation

Utility

PG&E
Corporation

Utility

----------------

-----------

----------------

-----------

Derivative gains (losses) included in accumulated other
   comprehensive income (loss) at beginning of period

$

(43)

$

- -

$

36

$

- -

Net gain (loss) from current period hedging transactions
   and price changes

(153)

- -

(237)

- -

Net reclassification to earnings

(2)

-

3

-

---------------

------------

---------------

------------

Derivative losses included in accumulated other
   comprehensive loss at end of period

(198)

- -

(198)

- -

Foreign currency translation adjustment

(2)

-

(2)

-

Other

(1)

-

(1)

-

---------------

------------

---------------

------------

Accumulated other comprehensive loss at end of period

$

(201)

$

-

$

(201)

$

-

=========

=======

=========

=======

(in millions)

Three months ended
September 30, 2001

Nine months ended
September 30, 2001

------------------------------

----------------------------

PG&E
Corporation

Utility

PG&E
Corporation

Utility

----------------

-----------

----------------

-----------

Derivative gains (losses) included in accumulated other
   comprehensive income (loss) at beginning of period

$

(106)

$

(41)

$

- -

$

- -

Cumulative effect of adoption of SFAS No. 133

-

-

(243)

90

Net gain (loss) from current period hedging transactions
   and price changes

21

1

170

(6)

Net reclassification to earnings

43

40

31

(84)

---------------

------------

---------------

------------

Derivative losses included in accumulated other
   comprehensive loss at end of period

(42)

- -

(42)

- -

Foreign currency translation adjustment

(5)

(2)

(5)

(2)

---------------

------------

---------------

------------

Accumulated other comprehensive loss at end of period

$

(47)

$

(2)

$

(47)

$

(2)

=========

=======

=========

=======

For most non-trading activities, earnings are recognized on an accrual basis as revenues are earned and as expenses are incurred. Thus, most non-trading activities do not affect earnings on a mark-to-market basis. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in PRM assets and liabilities and OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings.

However, there are a few instances where non-trading activities affect PG&E NEG's earnings on a mark-to-market basis. PG&E NEG recognizes the ineffective portion of the fair value of cash flow hedges in earnings. PG&E NEG also has certain derivative contracts which, while they are meant for non-trading purposes, do not qualify for cash flow hedge accounting or for the normal purchases and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis. These contracts primarily consist of those derivative commodity contracts for which normal purchases and sales treatment was disallowed upon PG&E NEG's implementation of DIG C15 and C16 effective April 1, 2002.

The effects on pre-tax earnings of non-trading activities that are reflected in income on a mark-to-market basis are as follows:

Three months ended September 30,

Nine months ended September 30,

--------------------------

--------------------------

(in millions)

2002

2001

2002

2001

-----------

----------

----------

----------

Ineffective portion of cash flow hedges

$

2

$

(2)

$

5

$

(2)

Non-trading derivatives marked-to-market through earnings

4

-

(105)

-

----------

----------

----------

----------

Total

$

6

$

(2)

$

(100)

$

(2)

======

======

======

======

Of the $105 million pre-tax loss attributable to non-trading derivatives marked to market through earnings for the nine months ended September 30, 2002, a $3 million pre-tax loss is included in the cumulative effect of adoption of DIG C15 and C16, as well as a $101 million pre-tax impairment charge also recognized in that line item. The remainder of the non-trading mark-to-market effects on earnings are classified in operating income.

Trading Activities

Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1. PG&E Corporation has reviewed its trading activities for 2001 and for the first five months of 2002 for potential instances of so-called "wash trades," and determined that such trades in the aggregate did not have a significant impact on revenues or expenses in any of the quarters in that period.

Gains and losses on trading contracts affect PG&E Corporation's gross margin in the accompanying PG&E Corporation unaudited Consolidated Statements of Income on an unrealized, mark-to-market basis as the fair value of the forward positions on these contracts fluctuate. Settlement or delivery on a contract is generally not an event that results in incremental net income recognition, as the profit or loss on a contract is recognized in income on an unrealized, mark-to-market basis during the periods before settlement occurs.

Gains and losses on trading contracts affect PG&E Corporation's cash flow when these contracts are settled. Net realized gains reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods but are considered realized when the related options are exercised or expire.

PG&E Corporation's net gains (losses) on trading activities, recognized on a fair value basis, are as follows:

Three months ended

Nine months ended

September 30,

September 30,

-----------------------------

-----------------------------

(in millions)

2002

2001

2002

2001

------------

------------

----------

-----------

Trading activities:

Unrealized gains (losses), net

$

(27)

$

(43)

$

(80)

$

(29)

Realized gains, net

84

87

165

195

------------

------------

------------

------------

Total

$

57

$

44

$

85

$

166

=======

=======

=======

=======

Price Risk Management Assets and Liabilities

PRM assets and liabilities on the accompanying PG&E Corporation Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark-to-market basis for contracts that will be settled in future periods. PRM assets and liabilities at September 30, 2002, include amounts for trading and non-trading activities, as described below.

Assets

Liabilities

Net Assets
(Liabilities)

--------------------------

---------------------------

--------------

(in millions)

Current

Noncurrent

Current

Noncurrent

-----------

--------------

-----------

--------------

Trading activities

$

235

$

288

$

(228)

$

(285)

$

10

Non-trading activities:

  Cash flow hedges - offset to OCI

356

194

(473)

(320)

(243)

  Derivatives marked to market through earnings

24

68

(40)

(231)

(179)

-----------

-------------

-------------

-------------

------------

Total consolidated PRM Assets and
  Liabilities

$

615

$

550

$

(741)

$

(836)

$

(412)

=======

=======

=======

=======

=======

Non-trading activities include certain long-term contracts that are not included in PG&E Corporation's trading portfolio but that, due to certain pricing provisions and volumetric variability, are unable to receive hedge accounting treatment or the normal purchases and sales exception, as outlined by interpretations of SFAS No. 133. PG&E Corporation has certain other non-trading derivative commodity contracts for the physical delivery of purchases and sales quantities transacted in the normal course of business. These other non-trading activities include contracts that are exempt from SFAS No. 133 fair value requirements under the normal purchases and sales exemption, as described previously. Although the fair value of these other non-trading contracts is not required to be presented on the balance sheet, revenues and expenses generally are recognized in income using the same timing and basis as are used for the non-trading activities accounted for as cash flow hedges. Hence, revenues are reco gnized as earned and expenses are recognized as incurred.

Credit Risk

Credit risk is the risk of an accounting loss that PG&E Corporation and the Utility would incur if counterparties fail to perform their contractual obligations (net accounts receivable, notes receivable, and PRM assets reflected on the balance sheet). PG&E Corporation and the Utility conduct business primarily with customers in the energy industry, such as investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies, located in the United States and Canada. This concentration of counterparties may impact PG&E Corporation's and the Utility's overall exposure to credit risk in that their counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E Corporation and the Utility manage credit risk pursuant to their respective Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These p rocedures include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E Corporation and the Utility rely heavily on master agreements that contain credit support provisions requiring the counterparty to post security 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.

PG&E Corporation and the Utility calculate gross credit exposure by counterparty as the current mark-to-market value (what would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of credit collateral. In the past year, PG&E Corporation's and the Utility's credit risk has increased partially due to credit rating downgrades of some of the counterparties in the energy industry to below investment grade.

At September 30, 2002, PG&E Corporation had no single counterparty that represents greater than 10 percent of PG&E Corporation's net credit exposure. At September 30, 2002, the Utility had one investment grade counterparty that represents 17 percent of the Utility's net credit exposure, and one below investment grade counterparty that represents 15 percent of the Utility's net credit exposure.

The schedule below summarizes the exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), at September 30, 2002:

(in millions)

Gross
Exposure ⁽¹⁾

Credit
Collateral ⁽²⁾

Net
Exposure ⁽²⁾

---------------

----------------

----------------

PG&E Corporation

$

1,266

$

221

$

1,045

Utility ⁽³⁾

236

102

134

⁽¹⁾ Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), 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, model, or credit reserves.

^{(2) Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit).
⁽³⁾ The Utility's gross exposure includes wholesale activity only. Retail activity and payables prior to the Utility's bankruptcy filing are not included. Retail activity at the Utility consists of the accounts receivable from the sale of gas and electricity to millions of residential and small commercial customers.}

At September 30, 2002, approximately $228 million or 22 percent of PG&E Corporation's net credit exposure is to entities that have credit ratings below investment grade. Approximately $54 million or 40 percent of the Utility's net credit exposure is to below investment grade entities. Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. Approximately $86 million or 8 percent of PG&E Corporation's net credit exposure at PG&E NEG is not rated. PG&E Corporation's regional concentrations of credit exposure are to counterparties that conduct business primarily in the western United States and also to counterparties that conduct business primarily throughout North America. In addition to the Utility's concentration of credit risk due to receivables from residential and small commercial customers in the northern California, the Utility has a net regional concentration of credit exposure totaling $134 million to counter parties that conduct business primarily throughout North America.

NOTE 7: COMMITMENTS AND CONTINGENCIES

Commitments

PG&E Corporation has substantial financial commitments in connection with agreements entered into supporting the Utility's and PG&E NEG's operating, construction, and development activities. These commitments are discussed more fully in the PG&E Corporation and Utility combined 2001 Annual Report on Form 10-K. The following summarizes commitments with significant changes since the combined 2001 Annual Report on Form 10-K was filed.

Utility

Natural Gas Supply and Transportation Commitments - Under current CPUC regulations, the Utility purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. The Utility has long-term gas transportation service agreements with various Canadian and interstate pipeline companies. The total demand charges that the Utility will pay each year may change due to changes in tariff rates. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines.

The Utility also has gas supply contracts with various Canadian and interstate gas companies. The contracts commit the Utility to purchase gas through December 2003, and total $474 million.

At September 30, 2002, the Utility's obligations related to natural gas transportation and supply commitments were as follows (in millions):

2002

$

223

2003

412

2004

98

2005

82

2006

26

Thereafter

10

--------------

Total

$

851

========

On March 6, 2002, the CPUC authorized the Utility to pledge its gas customer accounts receivable and core gas inventory for the purpose of procuring core gas supplies until the earlier of:

May 1, 2003,

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 the Plan of Reorganization, or

The dismissal or conversion of the Utility's bankruptcy proceeding.

At September 30, 2002, total gas accounts receivable pledged amounted to $197 million.

The Utility uses a $10 million standby letter of credit to facilitate natural gas purchases in addition to other credit arrangements with natural gas suppliers.

El Paso Capacity Decision - In May 2002, a FERC order directed El Paso Natural Gas Company (El Paso) to change the way it allocates space on its pipeline. El Paso's customers that are east of California had to decide by July 31, 2002, how much El Paso capacity rights they need in contract demand and how much capacity they would give up.

In July 2002, the CPUC issued a decision that required California IOUs to sign up for El Paso pipeline capacity given up by the shippers, and pre-approved such costs as just and reasonable. The IOUs were required to purchase a proportionate amount of the released capacity. The decision ordered that current capacity held by the IOUs on any interstate pipeline must be retained for the benefit of California ratepayers. Any capacity in excess of the IOUs' need should be released under short-term capacity release arrangements. The decision also finds that to the extent the IOUs complied with the decision, they also shall receive full cost recovery for their costs associated with existing capacity contracts on all gas transmission pipelines.

In Phase II of this proceeding, the CPUC will address other issues that relate to these rules, including:

Cost allocation of El Paso capacity among the Utility's customers,

Short-term capacity releases, and

Details about the guaranteed rate recovery of the IOUs' costs for subscription to interstate pipeline capacity.

Since the July 2002 CPUC decision was issued, the Utility signed contracts for El Paso pipeline capacity rights totaling approximately $50.7 million beginning November 2002 and ending December 2007. The Utility has filed advice letters proposing to recover both prepayments made to El Paso and ongoing capacity costs on the Transwestern Pipeline Company (Transwestern). Under the Gas Accord, the Utility could not recover any costs paid to Transwestern for gas pipeline capacity through 1997 and would have limited recovery during the period 1998 through 2002. Based on the El Paso decision, the Utility expects to fully recover its future purchases of gas pipeline capacity under the existing contract, resulting in additional revenues of approximately $90 million over the remaining contract period that begins in July 2002 and ends in March 2007.

The CPUC's Office of Ratepayer Advocates (ORA) and TURN filed protests arguing that the Utility acted "prematurely" in putting these pipeline capacity costs into rates and asked that they be backed out of rates until Phase II of the proceeding. In August 2002, the Utility filed a response to the protests with the CPUC. The Utility believes that immediate cost recovery in rates is appropriate based on the CPUC decision.

In September and October 2002, the CPUC issued two alternate draft resolutions that would delay the Utility's recovery of some of these costs. The first draft resolution would delay recovery of prepayments made to El Paso and ongoing capacity costs for the Transwestern pipeline. The alternate draft resolution would delay only the recovery of ongoing capacity costs for the Transwestern pipeline (and allow current recovery of prepayments made to El Paso). The Utility does not expect the outcome of the matter to have a material adverse impact on its Consolidated Statement of Income or financial position.

PG&E NEG

Attala Lease - On May 10, 2002, Attala Generating Company, an indirect subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its facility to a third-party special purpose entity. The related lease is being accounted for as an operating lease and will amortize a deferred gain of approximately $13 million from the sale over the lease period, which is 37 years. The payment obligations under this agreement are as follows (in millions):

2002

$

-

2003

38

2004

28

2005

29

2006

27

2007

29

Thereafter

602

--------------

Total

$

753

========

Attala Generating Company entered into a tolling agreement with Attala Energy Company, another wholly-owned subsidiary of PG&E NEG. Attala Energy Company's obligations under this tolling agreement are guaranteed by a $300 million PG&E NEG guarantee.

Contingencies
PG&E Corporation Guarantees

At September 30, 2002, PG&E Corporation had a net guarantee of $9.7 million for an office lease relating to PG&E NEG's San Francisco office, a guarantee related to PG&E NEG's indemnification obligations to the purchaser of PG&E NEG's gas transmission assets in Texas, and a $4.0 million guarantee related to PG&E NEG's indemnification obligations to the purchaser of PG&E Energy Services. PG&E Corporation also has a $0.9 million guarantee supporting the Utility's investment in low-income housing projects at September 30, 2002.

Utility

Nuclear Insurance - The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $25 million (property damage) and $8 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL.

The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection, which provides an additional $9.2 billion in coverage, which is mandated by the Price-Andersen Act. Under the Price-Andersen Act, secondary financial protection is required for all nuclear reactors having a rated capacity of 100 MW licensed to operate and designed for production of electrical energy. It provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident.

Nuclear Decommissioning - The Utility estimates its total obligation for the decommissioning of its nuclear facilities based on a tri-annual study, including costs associated with the act of permanently removing from service and disposing of a nuclear generating facility after the end of its useful life. Actual decommissioning costs may vary from this estimate based on changes in assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and increases in the costs of labor, materials, and equipment. The estimated total obligation is being recognized proportionately over the license terms of the facilities. As of September 30, 2002, the total accrued decommissioning obligation is $1.3 billion and is included in accumulated depreciation and decommissioning in the Utility's Consolidated Balance Sheets.

Decommissioning costs are placed in external trust funds. These funds, along with accumulated earnings, will be used exclusively for decommissioning and cannot be released from the trusts until authorized by the CPUC. The CPUC has authorized the qualified trust to invest up to a maximum of 50 percent of its funds in publicly traded equity securities, of which up to 20 percent may be invested in publicly traded non-U.S. securities. The nonqualified trust may be invested in equities up to a 60 percent maximum. The balance of the trusts are invested in investment grade fixed income securities. In general, investment securities are exposed to various risks, such as interest rate, credit and overall market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of investment securities could occur in the near term, and such changes could materially affect the amounts reported in the trust funds' balance. Declines in t he trust funds' balance due to investment losses may require the Utility to seek increases in nuclear decommissioning revenue requirements or otherwise provide funding to the plan.

Workers' Compensation Security - The Utility must deposit collateral with the State Department of Industrial Relations (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, or securities. The Utility currently provides collateral in the form of approximately $365 million in surety bonds.

In February 2001, several surety companies provided cancellation notices, citing concerns about the Utility's financial situation. The DIR has not agreed to release the canceling sureties from their obligations for claims occurring prior to the cancellation and has continued to apply the cancelled bond amounts, totaling $185 million, towards the $365 million amount of collateral. The Utility was able to supplement the difference through three additional active surety bonds totaling $180 million. The cancelled bonds have not, to date, impacted the Utility's self-insured status under California law. PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with these surety bonds and the Utility's underlying obligation to pay workers' compensation claims.

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 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 or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of likely clean-up costs can be reasonably estimated. The Utility reviews its remediation liability quarterly for each identified site. 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) 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 lower end of this range.

The Utility had an environmental remediation liability of $330 million and $295 million (undiscounted) at September 30, 2002, and December 31, 2001, respectively. The $330 million accrued at September 30, 2002, includes (1) $139 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) $191 million related to remediation costs for those generation facilities that the Utility still owns, manufactured gas plant sites, gas gathering sites, and compressor stations. Of the $330 million environmental remediation liability, the Utility has recovered $190 million through rates, and expects to recover approximately $82 million of the balance in future rates. The Utility also is recovering its costs from insurance carriers and from other third parties as appropriate.

The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility's future cost could increase to as much as $445 million. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or expected outcomes change.

On June 28, 2001, the Bankruptcy Court authorized the Utility to continue its hazardous waste remediation program and to expend:

Up to $22 million in each calendar year in which the Chapter 11 case is pending to continue its hazardous substance remediation programs and procedures; and

Any additional amounts necessary in emergency situations involving post-petition releases or threatened releases of hazardous substances subject to the Bankruptcy Court's specific approval.

The California AG, on behalf of various state environmental agencies, filed claims in the Utility's bankruptcy proceeding for environmental remediation at numerous sites aggregating approximately $770 million. For most if not all of these sites, the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the clean-up or would be doing so in the future in the normal course of business. In addition, for the majority of the remediation claims, the State would not be entitled to recover these costs unless it accepts responsibility to clean up the sites, which is unlikely. Since the Utility's proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular course of business, and since the Utility has not argued that the bankruptcy proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the claims seeking s pecific cash recoveries are invalid.

Moss Landing - In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that the Utility had violated the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). A tentative settlement has been reached with the Central Coast Board. Under the settlement, the Utility will fund approximately $5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in the California Superior Court. A claim has been filed by the California AG in the Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties.

Diablo Canyon - In October 2000, the Utility reached a tentative settlement with the Central Coast Board concerning alleged violations under the Utility's NPDES permit. Under the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in the California Superior Court. A claim has been filed by the California AG in the Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon's operation of its cooling water system.

Additionally, on April 9, 2002, the U.S. Environmental Protection Agency (EPA) proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day (mgd), typically including some form of "once-through" cooling. The Utility's Diablo Canyon, Hunters Point, and Humboldt Bay power plants are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed regulations call for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards if the regulations are adopted as proposed. The final regulations are scheduled to be promulgated in August 2003. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities. It is possible that the regulations may allow greater flexibility in achieving specified permit limits and thereby reduce the cost of compliance.

The Utility believes the ultimate outcome of these matters will not have a material impact on its consolidated financial position or results of operations.

Pension Funding - PG&E Corporation and its subsidiaries provide qualified and non-qualified non-contributory defined benefit pension plans for their employees, retirees, and non-employee directors. Amounts that PG&E Corporation and the Utility recognize as obligations to provide pension benefits under SFAS No. 87, "Employers Accounting for Pensions," are based on certain assumptions used by actuaries. Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases, and the expected return on plan assets. While PG&E Corporation and the Utility believe the assumptions used are appropriate, significant differences in actual experience, plan changes, or significant changes in assumptions may materially affect the amount of pension obligations and their future expenses.

Pension funds are held in an external trust fund. Trust assets, along with accumulated earnings, must be used exclusively for pension benefit payments. Consistent with the trust's investment policy, assets are invested in U.S. equities, non-U.S. equities, and fixed income securities. In general, investment securities are exposed to various risks, such as interest rate, credit, and overall market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trust's current value and the future level of pension expense.

PG&E NEG

Environmental Matters - In May 2000, USGenNE, an indirect subsidiary of PG&E NEG, received an Information Request from the EPA, pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. Management believes that it is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood that the EPA will bring an enforcement action.

As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants and estimates that capital expenditures on these environmental projects could approximate $332 million over the next five years. These estimates currently are under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, more stringent emission limitations for sulfur dioxide and ni trogen oxide by 2006. However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these limitations by 2004. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. USGenNE believes it may not be feasible to comply by 2004, and that in any event DEP improperly applied the 2004 deadline to the Salem Harbor emission control plan. USGenNE filed with the DEP a revised plan for Salem Harbor in April that it believes meets the DEP requirements for the 2006 compliance date. USGenNE also has filed an administrative appeal of the DEP's ruling that Salem Harbor meet the 2004 compliance date.

Various aspects of the DEP's regulations allow for public participation in the process through which the DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A local environmental group has made various filings with the DEP requesting such participation.

The EPA is required under the CAA to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the CAA required that they be promulgated by November 2000. Another provision in the CAA requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants, if the EPA fails to finalize regulations within 18 months past the deadline. On April 5, 2002, the EPA promulgated a regulation that extends this deadline for the case-by-case permits until May 2004. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. PG&E NEG will not be able to accurately quantify the economic impact of the future regulations until more details are available through the rulemaking process.

PG&E NEG's existing power plants are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and the DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay. Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $248 million through 2005, but this is a preliminary estimate. T here are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final and these proceedings are not expected to be completed during 2002. In addition, it is possible that the new permits for Salem Harbor and Manchester Street also may contain more stringent limitations than prior permits, and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. In addition, the issuance of any final NPDES permits may be affected by the EPA's proposed regulations under Section 316(b) of the Clean Water Act, which are discussed below.

On March 27, 2002, Rhode Island AG, Sheldon Whitehouse, notified USGenNE of his belief that Brayton Point "is in violation of applicable statutory and regulatory provisions governing its operations," including "protections accorded by common law" respecting discharges from the facility into Mount Hope Bay. He stated that he intended to seek judicial relief "to abate these environmental law violations and to recover damages" within the next 30 days. The notice purportedly was provided pursuant to Section 7A of Chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws, and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island AG stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued its draft permit on July 22, 2002, and the Rhode Island AG has since stated that he has no intention of pur suing this matter until he reviews USGenNE's response to the draft permit, which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG's financial condition or results of operations.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using more than 50 mgd typically including some form of "once-through" cooling. The Brayton Point, Salem Harbor, and Manchester Street generating facilities are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed regulations call for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in August 2003. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities. It is possible that the regulations may allow greater flexibility in achieving specified permit limits and thereby reduce the cost of compliance.

During April 2000, an environmental group served USGenNE and other PG&E NEG subsidiaries with a notice of its intent to file a citizen's suit under the Resource Conservation and Recovery Act (RCRA). In September 2000, PG&E NEG signed a series of agreements with the DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities.

PG&E NEG began the activities during 2000, and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of approximately $4 million through September 2002, $2 million in 2001, and $6 million in 2000. In addition to the costs previously incurred in 2000 and 2001, PG&E NEG maintains a reserve in the amount of $6 million relating to its estimate of the remaining environmental expenditures needed to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable for amounts it believes are probable of recovery from insurance proceeds.

PG&E NEG believes that it may be required to spend up to approximately $592 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. In the event PG&E NEG does not spend required amounts as of each facility's compliance deadline to maintain environmental compliance, PG&E NEG may not be able to continue to operate one or all of these facilities.

Legal Matters

In the normal course of business, PG&E Corporation, the Utility, and PG&E NEG are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. The Utility's Chapter 11 bankruptcy filing on April 6, 2001, discussed in Note 2 of the Notes to the Consolidated Financial Statements, automatically stayed the litigation described below against the Utility, except as otherwise noted.

Chromium Litigation - There are 15 civil suits pending against the Utility in several California state courts. One of these suits also names PG&E Corporation as a defendant. One additional civil suit, Kearney v. Pacific Gas and Electric Company, was filed against the Utility and PG&E Corporation after the Utility's bankruptcy filing and was dismissed without prejudice while the plaintiffs seek the right to file and pursue late claims in the Bankruptcy Court. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock, California. Currently, there are claims pending on behalf of approximately 1,250 individuals.

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.

There have been approximately 1,260 claims filed with the Bankruptcy Court (by most of the plaintiffs in the 15 cases and other individuals) alleging that exposure to chromium in soil, air, or water near the Utility's compressor stations at Hinkley, Kettleman, or Topock, California, caused personal injuries, wrongful death, or other injuries. 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." On November 14, 2001, the Utility filed objections to these claims and requested the Bankruptcy Court to transfer the chromium claims to the federal District Court. On January 8, 2002, the Bankruptcy Court denied the Utility's request to transfer the chromium claims and granted certain claimants' motion for relief from stay so that the state court lawsuits pending before the Utility filed its bankruptcy petition can proceed.

In the case of Adams v. Pacific Gas and Electric Company and Betz Chemical Company, after a hearing on July 17, 2002, the state court dismissed 35 plaintiffs with prejudice because their claims are barred by the statute of limitations. The state court dismissed another 65 plaintiffs without prejudice, so these plaintiffs may attempt to prove that their claims are not barred by the statute of limitations. Thirty of these plaintiffs filed a Fourth Amended Complaint on October 16, 2002.

In the case of Kearney v. Pacific Gas and Electric Company, the Bankruptcy Court ruled that six adult plaintiffs could not file untimely bankruptcy claims against the Utility. The court also ruled that 24 minor plaintiffs in the case could file untimely bankruptcy claims against the Utility.

The Utility has recorded a reserve in its financial statements in the amount of $160 million for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at September 30, 2002, 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 and PG&E GTN. 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, acting through the 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 U.S. 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 Indian 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 bankruptcy 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.

Federal Securities Lawsuit - A complaint, Gillam, et al. v. PG&E Corporation, et al., is pending in the U.S. District Court. An executive officer of PG&E Corporation also has been named as a defendant. The first amended complaint, purportedly brought on behalf of all persons who purchased PG&E Corporation common stock or certain shares of the Utility's preferred stock between July 20, 2000, and April 9, 2001, claimed that the defendants caused PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws as a result of recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect from customers. On January 14, 2002, the District Court granted the defendants' motion to dismiss the plaintiffs' first amended complaint, finding that the complaint failed to state a claim in light of the public disclosures by PG&E Corporation, the Utility, and others regarding the under-collections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery.

On February 4, 2002, the plaintiffs filed a second amended complaint that, in addition to containing many of the same allegations as appeared in the first amended complaint, contains many of the same allegations that appear in the California AG's complaint discussed below. The plaintiffs seek an unspecified amount of compensatory damages, plus costs and attorneys' fees. On March 11, 2002, the defendants filed a motion to dismiss the second amended complaint. After a hearing held on June 24, 2002, the District Court issued an order on June 25, 2002, dismissing the second amended complaint with prejudice. Plaintiffs have filed a notice of appeal of the District Court's order with the appellate court.

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

Order Instituting Investigation (OII) into Holding Company Activities and Related Litigation - On April 3, 2001, the CPUC issued an OII into whether the California IOUs, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. 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 holding 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 investor-owned energy utilities 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 appl ying 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 proposed Plan of Reorganization would violate the first priority condition. The utilities' applications for rehearing were denied on July 17, 2002.

The holding companies have filed petitions for review of each of the CPUC's capital requirements and jurisdiction decisions in several state appellate courts, and the utilities also have filed petitions for review of the capital requirements decision. The CPUC has moved to consolidate all proceedings in the San Francisco state appellate court and has requested that the court extend the deadline by which the CPUC must file its responses to the petitions for review until after the consolidation occurs.

On January 10, 2002, the California AG filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, alleging that PG&E Corporation violated various conditions established by the CPUC in decisions approving the holding company formation, among other allegations. The AG also alleges that the December 2000 and January and February 2001 ringfencing transactions by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions.

Among other allegations, the AG alleges that, through the Utility's bankruptcy proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices in alleged violation of California Business and Professions Code Section 17200 by seeking to implement the transactions contemplated in the proposed Plan of Reorganization filed in the Utility's bankruptcy proceeding. The complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. On February 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the AG's complaint to the Bankruptcy Court. On February 15, 2002, a motion to dismiss the lawsuit or in the alternative to stay the suit, was filed. Subsequently, the AG filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court held that the AG's allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceeding s were preempted by federal law. The Bankruptcy Court directed the AG to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties have appealed the Bankruptcy Court's remand order.

On August 9, 2002, the AG filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceedings. PG&E Corporation and the directors named in the complaint have filed a motion to strike certain allegations of the amended complaint. PG&E Corporation and the directors also have moved to partially consolidate the case with the case brought by the City and County of San Francisco discussed below. Those motions are pending.

On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the AG's complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took at least $5.2 billion from the Utility," and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to ratepayers, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit.

On March 4, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the City's complaint to the Bankruptcy Court. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand stating that the Bankruptcy Court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties have appealed the Bankruptcy Court's remand order.

Following remand, PG&E Corporation brought a motion to strike, which is pending and is scheduled to be heard on November 18, 2002. PG&E Corporation has moved to partially consolidate this case with the Section 17200 case brought by the AG.

In addition, a third case, entitled Cynthia Behr v. PG&E Corporation, et al., has been filed by a private plaintiff (who also has filed a claim in bankruptcy) in Santa Clara Superior Court also alleging a violation of California Business and Professions Code Section 17200. The Behr complaint also names the directors of the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the AG's complaint but also include allegations of fraudulent transfer and violation of the California bulk sales laws. Plaintiff requests the same remedies as the AG's case and in addition requests damages, attachment, and restraints upon the transfer of defendants' property. On March 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the complaint to the Bankruptcy Court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the AG's and the City's cases, the Bankruptcy Court rejected jurisdiction over Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the debtor's estate. The Bankruptcy Court remanded Behr's Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the Bankruptcy Court's remand order.

Following remand, PG&E Corporation moved to have the Behr case coordinated with the City's case described above. A hearing on that motion is scheduled for November 12, 2002, in the San Francisco Superior Court.

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. PG&E Corporation will vigorously respond to and defend the litigation. PG&E Corporation cannot predict whether the outcome of the litigation will have a material adverse effect on its 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 kWh in allegedly excessive electric rates and a refund of alleged recent over-collections in electric revenue since June 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. (In January 2001, the CPUC authorized a $0.01 per kWh increase to pay for energy procurement costs. In March 2001, the CPUC authorized an additional $0.03 per kWh electric rate increase as of March 27, 2001, to pay for energy procurement costs, which the Utility began to collect in June 2001.) The only alleged over-collection amount calculated in the complaint is approximately $400 million during t he 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. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse effect on their financial condition or results of operation.

Recorded Liability

In accordance with SFAS No. 5, "Accounting for Contingencies," PG&E Corporation makes 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, rulings, advice of legal counsel, and other information and events pertaining to a particular case. The following table reflects the current year's activity to the recorded liability for legal matters for PG&E Corporation and the Utility:

(in millions)

2002

------------

Beginning balance, January 1,

$

209

Provision for liabilities

17

Payments

(11)

Adjustments

(13)

------------

Ending balance, September 30,

$

202

=======

NOTE 8: IMPAIRMENT AND WRITE-OFFS

Impairment of Project Development, Turbine, and Other Related Equipment Costs

PG&E NEG has reviewed its growth plans for its electric generating business in light of the recent changes in the energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices, electric generating industry fundamentals, and financial market support for competitive energy companies have significantly declined, thereby constraining access to funds at acceptable terms to PG&E NEG. Oversupply of electric generation now and in the near future has significantly decreased the value of planned future development projects. In response to these market changes and considering the expected level of future electric generating supply, PG&E NEG has reconsidered the extent of, and reduced its planned investment activities in, electric generating development projects. PG&E NEG has analyzed the potential cash flow from those projects that it no longer anticipates pursuing and has recognized an impairment of the asset value it is carrying for those development projects . The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment costs discussed below) is $19 million in the second quarter of 2002. The remaining asset value (recorded in Other Noncurrent Assets) that PG&E NEG had retained as of September 30, 2002, for its portfolio of development projects is $49 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal. PG&E NEG has no material commitments (excluding equipment costs discussed below) for the projects under continuing development.

To support PG&E NEG's electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG's commitment to purchase combustion turbines and related equipment exceeds the new planned development activities discussed above. The current electric generating market is faced with an oversupply of facilities in operation and under construction. The current and future market for combustion turbines and related equipment also has seen an oversupply and large cancellation of turbine orders. The net realizability of PG&E NEG's investment in, and future committed payments for, its excess combustion turbine and related equipment portfolio, in light of current development plans, is doubtful. Based upon PG&E NEG's current development plans and analysis of future market prices for combustion turbines and related equipment, PG&E NEG has recognized a charge of $246 million in the se cond quarter of 2002. The charge consists of the impairment of previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $58 million for future termination payments required under the turbine and related equipment contracts. Although PG&E NEG has impaired the value of these turbines and related equipment, it has terminated its commitments or options with respect to only three turbines and related equipment. The remaining asset value (recorded in Other Noncurrent Assets) that PG&E NEG had retained as of September 30, 2002, for its investment in turbines and related equipment is approximately $34 million. These turbine and equipment commitments have been retained to support the equipment needs for PG&E NEG's current portfolio of advanced development projects discussed above. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligation s (except for $19 million as of September 30, 2002) for at least the next nine months. Thereafter, PG&E NEG must either restart equipment payments or, for equipment requiring progress payments, terminate such commitments and pay the associated termination costs.

Goodwill Write-Off

As described in Note 1, on January 1, 2002, PG&E NEG adopted SFAS No. 142, "Goodwill and Other Intangible Assets." Upon implementation of this Statement, the transition impairment test was performed as of January 1, 2002 and no impairment loss was recorded. SFAS No. 142 requires that goodwill be reviewed at least annually for impairment. Due to significant adverse changes within the national energy markets, PG&E NEG has elected to test its goodwill for possible impairment in the third quarter of 2002. Based upon the results of the fair value test, PG&E NEG recognized a goodwill impairment loss of $95 million on September 30, 2002. The fair value of the segment was estimated using the discounted cash flows method. This charge is included in the impairments and write-offs line item on the PG&E Corporation Consolidated Statements of Income for the three and nine months ended September 30, 2002.

Impairment of Dispersed Generation Assets

In PG&E NEG's Dispersed Generation operations, equipment (turbines, generators, transformers, metering equipment etc.) was purchased and/or refurbished and held for future expansions at current Dispersed Generations facilities. During the third quarter of 2002, based on the changes in national energy markets and specifically the markets in which Dispersed Generation's assets operate, PG&E NEG assessed the probability of utilizing these assets for expansion. PG&E NEG measured the estimated capital investment necessary for expansion against the future estimated cash flows to be generated. It was determined that such investments would be uneconomical and that PG&E NEG cannot characterize these expansion projects as probable. The book value of this equipment was approximately $46 million at September 30, 2002. Based on recent market quotes and expected net salvage values, PG&E NEG has recorded an impairment charge of approximately $30 million in the third quarter of 2002. This charge is included in the impairments and write-offs line item on PG&E Corporation's Consolidated Statements of Income for the three and nine months ended September 30, 2002.

NOTE 9: SEGMENT INFORMATION

Segment information for the three and nine months ended September 30, 2002, and 2001, was as follows:

								PG&E National Energy Group
								------------------------------------------------------------------
(in millions)			Utility					Total PG&E NEG		Integrated Energy & Marketing		Interstate Pipeline Operations		PG&E NEG Elimi- nations		PG&E Corpora- tion & Other Elimi- nations⁽³⁾		Total
		-------------						------------		----------------		--------------		------------		--------------		------------
Three months ended September 30, 2002
Operating revenues ⁽¹⁾		$		2,947				$	1,071	$	1,025	$	51	$	(5)	$	-	$	4,018
Intersegment revenues ⁽²⁾		2						16		5		11		-		(18)		-
		-------------						------------		----------------		--------------		------------		--------------		------------
Total operating revenues		2,949						1,087		1,030		62		(5)		(18)		4,018

Income from continuing operations							520	(18)		(36)		21		(3)		(36)		466
Net income		520						(18)		(36)		21		(3)		(36)		466

Three months ended September 30, 2001
Operating revenues ⁽¹⁾		2,934						785		747		46		(8)		-		3,719
Intersegment revenues ⁽²⁾		3						(3)		(14)		11		-		-		-
		-------------						------------		----------------		--------------		------------		--------------		------------
Total operating revenues		2,937						782		733		57		(8)		-		3,719

Income from continuing operations					737			77		64		19		(6)		(43)		771
Net income		737						77		64		19		(6)		(43)		771

Nine months ended September 30, 2002
Operating revenues ⁽¹⁾		8,108						2,372		2,244		142		(14)		-		10,480
Intersegment revenues ⁽²⁾		8						66		33		33		-		(74)		-
		-------------						------------		----------------		--------------		------------		--------------		------------
Total operating revenues		8,116						2,438		2,277		175		(14)		(74)		10,480

Income (loss) from continuing operations					1,573			(161)		(200)		56		(17)		(36)		1,376
Net income (loss)		1,573						(222)		(261)		56		(17)		(36)		1,315

Nine months ended September 30, 2001
Operating revenues ⁽¹⁾		7,799						2,086		1,933		157		(4)		-		9,885
Intersegment revenues ⁽²⁾		9						138		109		29		-		(147)		-
		-------------						------------		----------------		--------------		------------		--------------		------------
Total operating revenues		7,808						2,224		2,042		186		(4)		(147)		9,885

Income from continuing operations						433		202		152		57		(7)		(65)		570
Net income		433						202		152		57		(7)		(65)		570

Total assets at September 30, 2002 ⁽⁴⁾			$		24,942			$	11,434	$	10,004	$	1,318	$	112	$	259	$	36,635

Total assets at September 30, 2001 ⁽⁴⁾			$		24,891			$	9,785	$	8,447	$	1,198	$	140	$	217	$	34,893

⁽¹⁾	Operating revenues and operating expenses for the three months and nine months ended September 30, 2002, reflect the adoption of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 2001 have been reclassified to conform with the new net presentation.

⁽²⁾	Intersegment electric and gas revenues are recorded at market prices, which for the Utility and PG&E NEG's Interstate Pipeline Operations business segment are tariffed rates prescribed by the CPUC and the FERC, respectively.

⁽³⁾	Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries.

⁽⁴⁾	Assets of PG&E Corporation are included in amounts under the "PG&E Corporation & Other Eliminations" column exclusive of investment in its subsidiaries.

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

OVERVIEW

PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's energy utility subsidiary, Pacific Gas and Electric Company (the Utility), delivers electric service to approximately 4.9 million customers and natural gas service to approximately 4.1 million customers. On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). Under Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing 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 Consolidated Financial Statements.

PG&E Corporation's other significant subsidiary is PG&E National Energy Group, Inc. (PG&E NEG), headquartered in Bethesda, Maryland. PG&E NEG is an integrated energy company with a strategic focus on power generation, power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. PG&E NEG and its subsidiaries have integrated their generation, development, and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from their operations, and identify and capitalize on opportunities to increase their generating and pipeline capacity. PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG's principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, PG&E Gen), PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, PG&E Energy Trading or PG&E ET), and PG&E Gas Transmission Corporation and its subsidiaries (collectively, PG&E GTC), which include PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively, PG&E GTN) and North Baja Pipeline, LLC (NBP). PG&E NEG also has other less significant subsidiaries.

PG&E Corporation has identified three reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution, the regulatory environment, and how information is reported to PG&E Corporation's key decision-makers. The Utility is one reportable operating segment. The other two reportable operating segments are the Integrated Energy and Marketing (PG&E Energy) segment and the Interstate Pipeline Operations (PG&E Pipeline) segment of PG&E Corporation's subsidiary, PG&E NEG. These three reportable operating segments provide different products and services, and are subject to different forms of regulation or different jurisdictions. Financial information about each reportable operating segment is provided in this MD&A and in Note 9 of the Notes to the Consolidated Financial Statements.

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. It includes separate Consolidated Financial Statements for each entity. The Consolidated Financial Statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. This MD&A should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this combined Quarterly Report on Form 10-Q should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to the Consolidated Financial Statements incorporated by reference in their combined 2001 Annual Report on Form 10-K.

This combined Quarterly Report on Form 10-Q, including this MD&A, contains forward-looking statements, including statements regarding management's guidance regarding 2002 earnings per share, 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," 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 of the factors that may affect future results, some of the factors that could cause future results to differ materially from historical results or those expressed or implied by the forward-looking statements include:

whether the Utility can continue to record "headroom" (the current recovery in the Utility's existing electric rates of prior uncollected costs previously written off in accordance with accounting principles generally accepted in the United States) and changes in the quarterly amount of such headroom, which may be affected by many factors, including:

-	the outcome of regulatory proceedings and other regulatory actions;
-	sales volatility and the level of direct access customers;
-	the impact of the end of the rate freeze period and post-rate freeze ratemaking;
-	changes in the application of the surcharge revenues accrued by the Utility under rate increases approved by the California Public Utilities Commission (CPUC) in January and March 2001;
-	the impact of potential judicial decisions interpreting the permissible use of headroom revenue; and
-	the impact of the proceedings to determine the level of revenue requirements for the California Department of Water Resources' (DWR) power procurement costs;

the pace and outcome of the Utility's bankruptcy case, which will be affected by:

-	whether the Bankruptcy Court confirms the Utility's proposed plan of reorganization (Utility Plan) or the CPUC's competing alternative proposed plan of reorganization, as it has been modified (Alternative Plan);
-	whether regulatory or governmental approvals required to implement either plan are obtained and the timing of such approvals;
-	the impact of any delays in implementation of a plan due to litigation related to regulatory, governmental, or Bankrupcy Court orders;
-	future equity or debt market conditions, future interest rates, future credit ratings, and other factors that may affect the ability to implement either plan or affect the amount and value of the securities proposed to be issued under either plan; and
-	the impact of judicial or regulatory decisions on the use of the amount of cash generated by headroom revenues;

whether the Utility is required to re-assume the obligation to purchase power for its retail customers, or take assignment of the DWR's contracts, or both, under circumstances that threaten to undermine the Utility's creditworthiness, financial condition, or results of operations;

whether and the extent to which the CPUC determines, in reviewing the Utility's prospective administration of the allocated DWR contracts, that the Utility's dispatch decisions or decisions regarding sales of excess power are not reasonable, which may result in disallowance of the Utility's costs if the CPUC decides that the DWR power should have been dispatched instead of the Utility's power or that the Utility should have disposed of excess power differently;

the effect of CPUC decisions implementing recently enacted California Senate Bill (SB) 1976, which requires the California investor-owned utilities (IOUs) to resume procuring power for their retail customers on January 1, 2003, or the ability of the Utility to finally recover in full its procurement costs;

the outcome of the CPUC's pending investigation into whether the California IOUs, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing the formation of their respective holding companies, the outcomes of the lawsuits brought by the California Attorney General (AG) and the City and County of San Francisco against PG&E Corporation alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC's holding company decisions, and the outcome of the California AG's petition requesting revocation of PG&E Corporation's exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on PG&E Corporation, the Utility, and PG&E NEG;

the outcome of the Utility's various regulatory proceedings pending at the CPUC and at the Federal Energy Regulatory Commission (FERC) and the potential for new proceedings and investigations;

whether the Utility will be successful in its filed rate doctrine litigation and other claims against the CPUC and the State of California (State) for recovery of power procurement and transition costs that were not collected from retail ratepayers;

the CPUC's determination of the end of the rate freeze and the amount of under-collected power procurement and transition costs the Utility is allowed to collect from its customers after the end of the rate freeze;

the threat of municipalization on the Utility, which may result in stranded Utility investment and loss of customer growth, and create additional barriers to cost recovery;

the Utility's ability to transition successfully from its existing customer billing system to a new customer billing system, currently undergoing implementation and testing, without suffering significant business interruption loss;

legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries and changes to rules and tariffs applicable to energy marketing and trading transactions, the market in which PG&E NEG operates, and changes in the accounting treatment of such transactions;

the volatility of commodity fuel and electricity prices and the spread between them (which may result from a variety of factors, including weather, the supply and demand for energy commodities, the availability of competitively priced alternative energy sources, the level of production and availability of natural gas, crude oil, and coal, transmission or transportation constraints, federal and state energy and environmental regulation and legislation, the degree of market liquidity, and natural disasters, wars, embargoes, and other catastrophic events), any resulting increases in the cost of producing power and decreases in prices of power sold, and whether the Utility's and PG&E NEG's strategies to manage and respond to such volatility are successful;

PG&E NEG's ability to continue to obtain extensions of the maturity date of its revolving credit facility, now due to expire on November 14, 2002, in light of PG&E NEG's below-investment grade credit ratings, liquidity constraints, conditions in the general economy, the energy markets, or the capital markets, and the market's perceptions of the energy industry;

the results of negotiations with PG&E NEG's construction lenders to fund completion of certain generating projects beyond November 14, 2002;

the extent to which PG&E NEG's current or planned construction of generation, pipeline, and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these construction projects are delayed or prevented because of financial or liquidity constraints; changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others, or by various development and construction risks, such as PG&E NEG's failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated and the potential loss of permits or other rights in connection with PG&E NEG's decision to delay or defer construction;

whether market conditions will require further impairment or write-off of PG&E NEG assets, which may cause PG&E NEG to fail to comply with the net worth requirements of its loan agreements;

the outcome of PG&E NEG's negotiations with its lenders under PG&E NEG's revolving credit facilities, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities, and the Turbine Revolver, as well as with representatives of the holders of the Senior Notes, to reach a global restructuring of this debt, which would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG's merchant assets and reduce energy trading operations;

future sales levels which are affected by general economic and financial market conditions, changes in interest rates, weather, conservation efforts, outages, and, in the case of the Utility, adjustments to or the discontinuance of the exit fees that are imposed on direct access customers;

volatility in income resulting from mark-to-market accounting, and the extent to which the assumptions underlying PG&E NEG's and the Utility's mark-to-market accounting and risk management programs are not realized;

the extent to which PG&E NEG incurs a charge to earnings as a result of the abandonment, sale or transfer of assets, whether such transactions occur in connection with the implementation of a global debt restructuring as may be agreed to by the lenders or otherwise;

the effectiveness of PG&E NEG's and the Utility's risk management policies and procedures;

the ability of PG&E NEG's and the Utility's counterparties to satisfy their financial commitments to PG&E NEG and the Utility, respectively, and the impact of counterparties' nonperformance on PG&E NEG's and the Utility's liquidity position;

the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;

the extent to which counterparties seek to terminate tolling agreements based upon the credit downgrades and seek termination damages and their ability to recover such damages;

heightened regulatory and enforcement agency focus on the merchant energy business including investigations into "wash" or "round-trip" trading, specific trading strategies and other industry issues, with the potential for changes in industry regulations and in the treatment of PG&E NEG by state and federal agencies;

the extent to which counterparties demand collateral in connection with PG&E ET's trading activities, which can be affected by the counterparties' responses to the ratings downgrades of PG&E NEG's and its subsidiaries' credit ratings, mutual forbearance as many counterparties also have been downgraded, pre- and early-pay arrangements, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of the exposure, and the counterparties' other commercial considerations, and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made;

the effect of the Utility bankruptcy proceedings upon PG&E Corporation and upon PG&E NEG;

the effect of new accounting pronouncements; and

the outcome of pending litigation and environmental matters.

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

In this MD&A, we first discuss our earnings guidance. Second, we discuss the impact of market conditions and business environment and the Utility's bankruptcy on our liquidity, and then PG&E NEG's liquidity. Third, we discuss statements of cash flows and financial resources, risk management activities, and our results of operations for the three and nine months ended September 30, 2002, and 2001. Finally, we discuss our competitive and regulatory environment, accounting and tax matters, and various uncertainties that could affect future earnings. Our MD&A applies to both PG&E Corporation and the Utility.

2002 Guidance

PG&E Corporation expects 2002 corporate earnings from operations, excluding headroom, to be in the range of $2.25 to $2.35 per share on a fully diluted basis. Earnings from operations, including headroom, are expected to exceed $4.75 per share for 2002. Earnings from operations with and without headroom exclude items impacting comparability, and should not be considered an alternative to net income as prescribed by accounting principles generally accepted in the United States of America.

Items impacting comparability for the year-to-date period ended September 30, 2002, include the net effect of incremental interest costs of $263 million ($0.69 per share), from the increased amount and cost of debt resulting from California's energy crisis and the Utility's Chapter 11 filing; costs related to the Utility's Chapter 11 filing and generally consisting of external legal consulting and financial advisory fees of $64 million ($0.17 per share); other costs related to California's energy crisis of $11 million ($0.03 per share); write-off of $68 million ($0.18 per share), of previously capitalized debt costs and discounts associated with PG&E Corporation's pre-payment of its Tranche A loan and changes in the terms of its Tranche B loan in conjunction with its loan waiver extension; the cumulative effect of a change in accounting principle related to PG&E NEG of $61 million ($0.16 per share); impairments and write-offs of long-term turbine prepayments and related capitalized development cos ts related to PG&E NEG of $159 million ($0.42 per share); goodwill impairment related to PG&E NEG Integrated Energy and Marketing segment of $71 million ($0.18 per share); PG&E NEG's combined cost of staff reduction and severance and outplacement services as well as costs associated with various office closures of $11 million ($0.03 per share); and impairment of dispersed generation equipment of $18 million ($0.05 per share). Offsetting these decreases were the Utility's net reversal of wholesale energy charges of $352 million ($0.93 per share); the change in the mark-to-market value of PG&E NEG warrants of $42 million ($0.11 per share); recognition of the full value of certain synthetic fuel tax credits of $43 million ($0.11 per share); and a change in PG&E NEG's mark-to-market methodology of $6 million ($0.02 per share).

MARKET CONDITIONS AND BUSINESS ENVIRONMENT

Utility

The California energy crisis described in Note 2 of the Notes to the Consolidated Financial Statements has had a significant negative impact on the liquidity and capital resources of the Utility. Beginning in June 2000, the wholesale price of electric power in California steadily increased to an average cost of $0.182 per kilowatt-hour (kWh) for the seven-month period June 2000 through December 2000, as compared to an average cost of $0.042 per kWh for the same period in 1999. During this period, retail electric rates were frozen. The Utility was permitted to collect only approximately $0.054 per kWh in frozen retail rates from its customers to pay for the Utility's generation-related costs. While seeking rate relief from the CPUC, the Utility financed the difference between its wholesale electricity costs and the amount collected through frozen retail rates. By December 31, 2000, the Utility had borrowed more than $3 billion. At December 31, 2000, the Utility had accumulated a total of approximately $6.9 billion in under-collected purchased power costs and generation-related transition costs. This amount was charged to earnings at December 31, 2000, because the Utility could no longer conclude that such costs were probable of collection through regulated rates.

In January 2001, the CPUC granted an interim rate increase of $0.010 per kWh. This increase, which could not be used to recover past procurement costs, was not sufficient to cover the ongoing high wholesale electricity costs then being experienced. As a result of the higher energy prices and the insufficient rate increase, PG&E Corporation's and the Utility's credit ratings deteriorated to below investment grade. These credit downgrades, which occurred on January 16 and 17, 2001, caused the Utility to default on maturing commercial paper obligations. In addition, the Utility no longer was able to meet its obligations to generators, qualifying facilities (QFs), the California Independent System Operator (ISO), and the Power Exchange (PX), and began making partial payments of amounts owed.

As of January 19, 2001, the Utility had no credit to purchase power for its customers, and generators were selling to the Utility only under emergency actions taken by the U.S. Secretary of Energy. As a result, the State authorized the DWR to purchase electricity for the Utility's customers. California Assembly Bill (AB) 1X was passed on February 1, 2001, authorizing the DWR to enter into contracts for the supply of electricity and to issue revenue bonds to finance electricity purchases, although the DWR indicated that it intended to buy power only at reasonable prices to meet the Utility's net open position, leaving the ISO to purchase the remainder in order to avoid blackouts. (The net open position is the amount of power needed by retail electric customers that cannot be met by utility-owned generation or power under contract to the Utility).

Throughout this energy crisis, the Utility sought relief through various regulatory proceedings and through efforts to reach a negotiated solution with the State. In late March and early April 2001, the CPUC issued a series of decisions that increased the Utility's inability to recover past debts and increased its exposure to significant additional costs. On March 27, 2001, the CPUC ruled on the Utility's November 20, 2000, request for rate relief. This decision made permanent the $0.010 per kWh interim increase authorized in January 2001 and granted an additional $0.030 per kWh energy surcharge that would be effective immediately, but that would not be included in customer bills until June 2001. As a result, in May 2001, the CPUC authorized an "incremental system average surcharge of $0.005 per kWh" for a 12-month period beginning June 1, 2001, to recover revenues not collected between March 27, 2001, when the three-cent surcharge was approved, and June 1, 2001, when the Uti lity began collecting the three-cent surcharge. The revenue generated by all of these surcharges was to be used only for electric power procurement costs incurred after March 27, 2001. On November 7, 2002, the CPUC voted to approve a decision that removes the restrictions on applying these surcharge revenues to "ongoing procurement costs" and "future power purchases." The CPUC decision stated that it revised these restrictions so that the surcharge revenues might be used, if necessary as authorized by the CPUC, to return the Utility to reasonable financial health. See further discussion in the Regulatory Matters sections of this MD&A.

The CPUC also ordered the Utility to pay the DWR the full generation-related portion of retail rates for every kWh of electricity sold by the DWR without regard to whether overall retail rates were adequate to recover the remainder of the Utility's cost of service. In the same decision, the CPUC adopted an accounting proposal by The Utility Reform Network (TURN) which retroactively restates the way in which transition costs are recovered. This retroactive change had the effect of extending the rate freeze and reducing the amount of past wholesale power costs that could be eligible for recovery from customers. The CPUC denied the Utility's application for rehearing of this retroactive accounting change. The Utility also filed a petition for a writ of review with the California Court of Appeal, which also was denied. In August 2002, the California Supreme Court denied the Utility's petition seeking review of the appellate court action. The Utility's request filed with the Bankruptcy Court for an order enjoining the CPUC from enforcing its order was denied by the Bankruptcy Court. The Utility has appealed the Bankruptcy Court's denial of injunctive relief to the U.S. District Court for the Northern District of California. This appeal is still pending.

On March 27, 2001, the CPUC issued another ruling that required the Utility to begin paying the QFs in full and within 15 days of the end of a QF's billing cycle. On April 3, 2001, the CPUC issued a ruling that adopted a methodology for the Utility to reimburse the DWR for power purchases made to meet the Utility's net open position.

As a result of (1) the failure of the DWR to assume the full procurement responsibility for the Utility's net open position, (2) the negative impact of a CPUC decision that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the State to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true under-collected purchased power costs, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code on April 6, 2001. Since filing for relief under Chapter 11, the Utility is proceeding on an expedited basis to develop and obtain approval of its plan of reorganization.

On June 17, 2002, disclosure statements relating to competing proposed plans of reorganization for the Utility were mailed to creditors and equity interest holders. The plan of reorganization proposed by PG&E Corporation and the Utility would allow the Utility to restructure its businesses, refinance the restructured businesses, and use the proceeds from the refinancing to pay all allowed claims, with interest. The competing Alternative Plan of reorganization was proposed by the CPUC. The Utility's creditors were allowed to vote for or against the Utility Plan, the Alternative Plan, or both plans. Voting classes were allowed to express a preference if they voted for both plans. In September 2002, an independent voting agency informed the Bankruptcy Court that 9 of the 10 voting classes had approved the Utility Plan. (One of eight voting classes approved the Alternative Plan.) After the voting period ended, the Alternative Plan was amended and the Official Creditors' Committee became a sponsor o f the amended Alternative Plan. On November 18, 2002, the Bankruptcy Court will begin the confirmation trial in which one of the reorganization plans may be approved. If the requirements for confirmation are met by both plans, the Court will consider the preferences of creditors in deciding which plan to confirm. PG&E Corporation and the Utility are not able to predict the ultimate outcome of the Utility's bankruptcy proceeding, including which plan, if any, the Bankruptcy Court may confirm.

Under AB 1X, the DWR is prohibited from entering into new agreements to purchase power to meet the net open position of the California IOUs' customers after January 1, 2003.

On September 24, 2002, California SB 1976 was signed into law. SB 1976 requires the IOUs to file and implement electricity procurement plans on or before January 1, 2003, for the portion of their net open position not covered by existing DWR contracts and utility-owned resources and contracts (referred to as the residual net open position). It requires the CPUC to allocate the electricity subject to existing DWR contracts among the customers of the IOUs, including the Utility, and further requires that each IOU submit, within 60 days of the CPUC's allocation, an electricity procurement plan to meet the residual net open position for its customers' needs after taking into account the quantities of electricity under the DWR contracts allocated to it by the CPUC. SB 1976 requires that each procurement plan include one or more of the following features:

A competitive procurement bidding process under a format authorized by the CPUC, with the costs of procurement obtained in compliance with the authorized bidding format being recoverable in rates;

A clear, achievable, and quantifiable incentive mechanism that establishes benchmarks for procurement and authorizes the IOUs to procure from the market subject to comparison with the CPUC-authorized benchmarks; and/or

Upfront and achievable standards and criteria to determine the acceptability and eligibility for rate recovery of a proposed transaction and an expedited CPUC pre-approval process for proposed contracts to ensure compliance with the individual utility's procurement plan.

SB 1976 also provides that the CPUC may not approve a feature or mechanism in a procurement plan if it finds that the feature or mechanism would impair the restoration of the IOU's creditworthiness or would lead to a deterioration of the IOU's creditworthiness. SB 1976 also eliminates after-the-fact reasonableness reviews of the IOU's actions in compliance with an approved procurement plan, although SB 1976 does permit a regulatory process to verify and ensure that each contract was administered in accordance with the terms of the contract and that contract disputes that arise are resolved reasonably. SB 1976 authorizes the CPUC to create power procurement balancing accounts to track the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC would be required to review, at least semiannually, the balancing accounts, and to adjust rates or order refunds, as necessary to properly amortize amounts remaining in the balancing accounts.

Until January 1, 2006, SB 1976 requires the CPUC to establish the schedule for amortizing the over- or under-collections in the power procurement balancing accounts so that the aggregate over- or under-collections in the accounts do not exceed 5 percent of a utility's actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. Mandatory semiannual review of the balancing accounts and the need for rate adjustments will lapse on January 1, 2006, but the CPUC still will be required to conduct power procurement balancing account reviews and adjust amortization schedules for the balancing accounts in a manner consistent with the objectives of SB 1976. Under SB 1976, the CPUC has final authority to accept, reject, or modify each IOU's procurement plan. On October 24, 2002, the CPUC issued a decision ordering the Utility to resume full procurement on January 1, 2003. The decision requires the Utility to submit modifications to its short-term procurement plan to the CPUC by November 12, 2002, and submit its long-term procurement plan by April 1, 2003. Under SB 1976, after the CPUC adopts the Utility's procurement plan, the Utility is required to re-assume procuring power within 60 days.

See Note 2 of the Notes to the Consolidated Financial Statements for further discussion of the California energy crisis, the Utility's voluntary petition for relief under Chapter 11 of the Bankruptcy Code, and the status of the Chapter 11 proceedings.

PG&E NEG

The national markets in which PG&E NEG participates are experiencing the first sustained downturn in the electric power commodity business cycle since electric deregulation began in the mid-1990s. Price spikes beginning in 1997 and 1998 culminated in peak prices in 2000 and early 2001. During 2001 and 2002, new supply additions begun during the high-price period, combined with a softening economy and reduced load growth, have resulted in excess energy supply in many regions. The excess supply conditions have put downward pressure on the price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets. Furthermore, the economic slowdown and a number of regulatory events, many of which were consequences of the California energy crisis and the Enron Corp. bankruptcy, have increased uncertainty in the energy sector. Prior to the economic slowdown, a number of companies, including PG&E NEG, initiated substantial growth plans. These plans includ ed construction and acquisition of new power plants and expansion of energy trading activities. In order to implement these plans, PG&E NEG secured options to purchase long lead-time equipment, acquired certain assets under construction or in operation, and completed development and commenced construction of new power plants. These plans required substantial amounts of liquidity and capital resources to support construction, working capital, and counterparty credit requirements. PG&E NEG financed these growth plans and operations using a combination of funds from operations, equity, long-term debt (secured directly by those assets without recourse to other entities), long-term corporate borrowings in the capital markets, and short- and medium- term bank facilities that provided working capital, letters of credit, and other liquidity needs. These financings and other commitments often relied on the credit support provided by PG&E Corporation. In late 2000 and early 2001, as PG&E Corporation' s credit position deteriorated due to financial difficulties of the Utility, PG&E NEG and various subsidiaries obtained their own investment grade credit rating and began providing replacement credit support for PG&E NEG's commitments to implement its growth plans. Due to these industry events, the deterioration of PG&E Corporation's credit position, collapse of the spark spread, the electric generation overbuild, the decline of energy companies' credit quality, and overall industry poor economic performance, PG&E NEG is currently unable to pay its debts under six major credit facilities as they become due.

LIQUIDITY AND FINANCIAL RESOURCES

On June 25, 2002, PG&E Corporation negotiated new terms for its Amended and Restated Credit Agreement with General Electric Capital Corporation (GECC) and Lehman Commercial Paper Inc. (LCPI). Originally, the Amended and Restated Credit Agreement had a principal balance outstanding of $1 billion; however, PG&E Corporation made an optional principal repayment of $308 million on June 3, 2002, to reduce the principal balance outstanding to $692 million. The new terms converted and incorporated the existing loan into new loans in two tranches as detailed in the table below (in millions):

New Loans

Balance From
Existing Loan

New
Borrowings

New
Loan Balance

---------------------

----------------------

-----------------

------------------

Tranche A Loan

$

600

$

-

$

600

Tranche B Loan

92

328

420

As a result of PG&E NEG's credit rating downgrade to below investment grade in July and August 2002, by Standard and Poor's (S&P) and Moody's Investors Service (Moody's), respectively, PG&E Corporation sought and obtained waivers, valid through August 30, 2002, from the Tranche A and Tranche B lenders of the requirement that PG&E NEG maintain investment grade ratings with either S&P or Moody's. In the absence of a waiver, the dual downgrade would have constituted a default under the Amended and Restated Credit Agreement.

On August 30, 2002, PG&E Corporation made a voluntary prepayment of $600 million of aggregate principal, plus interest totaling approximately $6.7 million, to GECC. This prepayment released PG&E Corporation from maintaining a $90 million restricted cash requirement of interest income. The remaining lenders extended until October 4, 2002, a waiver of the Amended and Restated Credit Agreement requirement that PG&E NEG maintain investment grade ratings with either S&P or Moody's until October 18, 2002. PG&E Corporation recorded write-offs of unamortized loan fees and discount of $83 million and $70 million relating to the Tranche A note prepayment and Tranche B debt extinguishment connected with the new waiver extension, respectively. In addition, PG&E Corporation reversed $38 million of unamortized loan discount representing the value of unvested PG&E NEG options associated with the prepayment of the Tranche A note.

On October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement (Credit Agreement), with the lenders party thereto, LCPI, as Administrative Agent, and others, pursuant to which the existing $420 million Tranche B loan previously made by certain of the lenders has been modified (as modified, the Tranche B Loan) and certain of the lenders have made new incremental loans in the aggregate principal amount of $300 million (New Loans) with the same terms and conditions as those applicable to the Tranche B Loan. The Tranche B Loan and the New Loan are collectively referred to herein as the Loans. The Loans have been funded into a separate escrow account and will be released to PG&E Corporation on January 17, 2003, unless a bankruptcy proceeding has been commenced by or against PG&E Corporation. The Loans are payable in a single installment on September 2, 2006, unless prepaid earlier in accordance with the Credit Agreement.

The Credit Agreement continues to contain certain limitations on the ability of PG&E Corporation and certain of its subsidiaries to grant liens, consolidate, merge, purchase or sell assets, declare or pay dividends, incur indebtedness, or make advances, loans, and investments. However, the Credit Agreement does not limit (1) the ability of PG&E NEG, LLC, PG&E NEG, or their respective subsidiaries to grant liens or incur debt, or (2) PG&E Corporation's and the Utility's ability to consummate the transactions contemplated in the Utility's Plan. The Credit Agreement generally permits PG&E NEG, LLC, PG&E NEG, and their respective subsidiaries to enter into sales and other disposition of assets in the ordinary course of business and in certain qualified transactions. In addition, in connection with certain sales and debt restructuring transactions of PG&E NEG and its subsidiaries, PG&E Corporation is permitted to use existing cash to make investments in P G&E NEG. The amount of such investments is limited to 75 percent of the net cash tax savings (less certain costs and expenses) actually received by PG&E Corporation after October 1, 2002, as a result of certain transactions of PG&E NEG and its subsidiaries. PG&E Corporation also is permitted to make investments funded from existing cash and to pay obligations of PG&E NEG and its subsidiaries (including, without limitation, any obligations for which PG&E Corporation becomes a surety or a guarantor) up to a cumulative amount not to exceed $15 million, provided that no default or event of default has occurred under the Credit Agreement, and provided further that PG&E NEG and PG&E NEG, LLC are not in bankruptcy. The proceeds of the Loans may not be used to make investments in PG&E NEG, LLC or PG&E NEG or any of their subsidiaries.

The Credit Agreement has been amended to delete provisions that required PG&E NEG to maintain certain credit ratings and required that a certain ratio of fair market value of PG&E NEG to the aggregate amount of the outstanding loans be maintained. Further, the Credit Agreement no longer provides that a default or event of default under agreements of PG&E NEG or its subsidiaries constitutes a cross-default under the Credit Agreement.

The Loans may be prepaid upon payment of a prepayment fee equal to (1) if such prepayment is made on or prior to October 1, 2003, the discounted present value of 2.5 percent of the principal amount of such prepayment plus the aggregate amount of interest that would accrue on the principal amount of such prepayment from the date of such prepayment to October 1, 2003, (2) if such prepayment is made after October 1, 2003, and on or prior to October 1, 2004, 2.5 percent of the principal amount prepaid, and (3) if such prepayment is made after October 1, 2004, 0.5 percent of the principal amount prepaid.

The Credit Agreement also generally requires mandatory prepayments of the Loans with the net cash proceeds from (1) incurrence of indebtedness, (2) issuance or sale of equity by PG&E Corporation or the Utility, (3) sales of assets by PG&E Corporation, PG&E NEG, PG&E NEG, LLC, or any subsidiary of PG&E NEG (with a carve-out for proceeds retained by PG&E NEG), (4) the receipt of condemnation or insurance proceeds, (5) and distributions or dividends paid to PG&E Corporation or PG&E NEG, LLC. PG&E Corporation also must pay a prepayment fee upon mandatory prepayment.

The net proceeds of the Loans will be used to fund corporate working capital and for general corporate purposes, and may not be used to make investments in PG&E NEG, LLC, PG&E NEG, or any of their respective subsidiaries or, except as required by applicable law or the conditions adopted by the CPUC with respect to holding companies, in the Utility.

PG&E Corporation's 7.50 percent Convertible Subordinated Notes due 2007 in the aggregate principal amount of $280 million issued on June 25, 2002 (Notes) and the Indenture relating to the Notes have been amended to delete certain cross-default provisions which provided that a non-payment or an acceleration of indebtedness of PG&E NEG or any of its subsidiaries, or a bankruptcy event with respect to PG&E NEG or any of its subsidiaries, constituted a default or event of default under the Notes and the Indenture. Further, the Indenture and the Notes have been amended, among other things, to increase the interest rate on the Notes to 9.50 percent from 7.50 percent, to extend the maturity of the Notes to June 30, 2010, from June 30, 2007, and to provide the holder of the Notes with a one-time right to require PG&E Corporation to repurchase the Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including any liquidated damages and pass-th rough dividends, if any).

In conjunction with the Credit Agreement and Loans, certain lenders were granted options to purchase certain quantities of PG&E NEG shares. These warrants are marked to market on a monthly basis. In the third quarter of 2002, PG&E Corporation recorded other income of $71 million, as a result of the change in market value of the PG&E NEG warrants during that period. As discussed above, the appraisal process to determine the value of PG&E NEG has not concluded. If it is determined that PG&E NEG's value is greater than the value currently reflected in the mark-to-market accounting, PG&E Corporation would be required to incur a charge to earnings as a result of the increased valuation.

Credit Ratings

Independent credit rating agencies rate various debt and equity instruments of PG&E Corporation, the Utility, and PG&E NEG. The ratings indicate the agencies' assessment of each company's ability to pay interest distributions, dividends, and principal on these instruments. These ratings affect each company's cost of borrowing, its ability to provide counterparty guarantees, its access to capital markets, and the cost of selling these instruments.

The factors that credit rating agencies consider in establishing a company's credit ratings include, but are not limited to, cash flows, liquidity, and the amount of debt as a component of total capitalization. PG&E Corporation's, the Utility's, and PG&E NEG's credit ratings on various debt and equity instruments have been downgraded on several occasions by the agencies beginning in 2001. These downgrades reflect the increased probability, given the uncertainties surrounding the California energy crisis and the general downturn in the economy, that PG&E Corporation, the Utility, and PG&E NEG may not be able to meet, or will have a harder time meeting, their financial obligations. In particular, the downgrades negatively impact certain guarantees and financial arrangements that require each company to maintain certain credit ratings from credit rating agencies, and can give rise to concerns about the companies' creditworthiness. A negative rating also may entitle lenders or counterparti es to exercise certain remedies against the company, including their rights to make demands for payment of guaranteed amounts, terminate tolling agreements, and seek damage payments.

PG&E NEG and its subsidiaries are among other companies in the energy industry which have been downgraded. The first downgrades to below investment grade occurred on July 31, 2002, three weeks prior to PG&E NEG's anticipated roll-over of its $750 million 364-day revolving credit facility. As a result of the downgrades, the facility was not renewed and instead the outstanding balance ($431 million) initially became due and payable as of August 22, 2002, and remains outstanding under a waiver, described below, which expires on November 14, 2002. As described below, PG&E NEG does not expect this waiver to be extended. Absent such extension, PG&E NEG will be in default under the Corporate Revolver. This default would constitute a cross-default under the other major debt facilities and guaranteed commitments described below. Other commitments made in connection with PG&E NEG's growth plans also are beginning to mature over the next 15 months. This series of events has materially and adversely affected PG&E NEG's liquidity position and PG&E NEG currently does not have sufficient sources of liquidity to fulfill its commitments as they mature.

The following table highlights the credit ratings assigned to various debt and equity instruments of PG&E Corporation, the Utility, and PG&E NEG, at October 31, 2002.

Credit Rating

----------------------------------------------

Standard
& Poor's

Moody's
Investors Service

-----------------

----------------------

PG&E Corporation

   LCPI Loans

Not Rated

Not Rated

   Convertible Subordinated Notes

Not Rated

Not Rated

Utility

   Mortgage Bonds

CCC

B3

   Pollution Control Bonds-Bond Insurance

AAA

Aaa

   Pollution Control Bonds-Letters of Credit

AA to AA-/A-1+

Not Rated

   Medium-Term Notes

D

Caa2

   San Joaquin Valley Power Authority Bond

Not Rated

Rating Withdrawn

   DWR Loan

Not Rated

Not Rated

   Senior 5-Year Note

D

Caa2

   Revolving Credit Line

Not Rated

Not Rated

   Floating Rate Notes

D

Not Rated

   Matured Commercial Paper

D

Not Prime

   Redeemed Pollution Control Bonds-Bank Loans

Not Rated

Not Rated

   Deferrable Interest Subordinated Debentures (QUIDS)

Rating Pending

Caa3

   Preferred Stock

D

Ca

PG&E NEG

   Rated Entities:

   PG&E NEG

B-

B3

   PG&E GTN

BB-

Ba1

   PG&E ET

B-

Not Rated

   PG&E Gen

B-

Not Rated

   USGen New England, Inc. (USGenNE)

B-

B2

   Rated Debt Instruments:

   Senior Unsecured Notes due 2011 (PG&E NEG)

B-

B3

   Senior Unsecured Notes due 2005 (PG&E GTN)

BB-

Ba1

   Senior Unsecured Debentures due 2025 (PG&E GTN)

BB-

Ba1

   Senior Unsecured Notes due 2012 (PG&E GTN)

BB-

Ba1

   Medium-Term Notes (nonrecourse) (PG&E GTN)

BB-

Ba1

   Term Loans (GenHoldings I, LLC)

CC

B3

PG&E NEG

PG&E NEG's and its subsidiaries' obligations fall into four broad categories: (1) major debt facilities and equity commitments, (2) PG&E ET's energy trading and non-trading activities related to PG&E NEG's merchant energy portfolio excluding tolling agreements, (3) tolling agreements, and (4) other guarantees and commitments. In addition to the impacts of PG&E NEG's downgrades, PG&E NEG's and its subsidiaries' ability to service these obligations is impacted by constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG's subsidiaries now must independently determine, in light of each company's financial situation, whether any proposed dividend, distribution, or intercompany loan is permitted and is in such subsidiary's interest. Therefore, consolidated statements of cash flow and consolidated balance sheets quantifying PG&E NEG's cash and cash equivalents do not reflect the cash actually available to PG&E NEG or any par ticular subsidiary to meet its obligations.

PG&E NEG's cash bank balances (net of restricted cash bank balances, international accounts and not including in-transit items) at October 31, 2002 is as follows (in millions):

PG&E NEG

$

18

PG&E ET

149

PG&E GEN

38

PG&E GTC

37

Other Subsidiaries

54

------------

Consolidated PG&E NEG

$

296

=======

Major PG&E NEG Debt Facilities and Equity Commitments

PG&E NEG is a party to, or guarantor of, six major facilities:

	Amount Outstanding ⁽¹⁾		Maturity
(in millions)	------------------		---------------------------------------
PG&E NEG Debt and Guaranteed Debt:
Senior Notes	$	1,000	May 15, 2011
Corporate Revolver	431		November 14, 2002
	273⁽²⁾		August 22, 2003
Equipment Revolver	205		Through December 31, 2003
PG&E NEG Equity Commitment Guarantees:
GenHoldings Equity Commitment	355		Through project completions during 2003
La Paloma Equity Commitment	375		March 2003
Lake Road Equity Commitment	230		March 2003

^{(1) Outstanding as of October 31, 2002}
^{(2) All amounts as of October 21, 2002 were letters of credit}

The agreements for each of these commitments provide for cross-defaults if PG&E NEG fails to pay when due or at maturity, or the lenders accelerate, an amount equal to or in excess of $50 million of any indebtedness or equity commitment. As described below, PG&E NEG expects to default in the repayment of the $431 million due on November 14, 2002, under the Corporate Revolver. This will cause a cross-default under the other five major facilities. Notwithstanding these defaults, PG&E NEG believes that the lenders will refrain from exercising remedies and or will continue to pursue negotiations to restructure PG&E NEG's obligations. If the lenders exercise their remedies or no restructuring is achieved, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. PG&E NEG is in discussions with the lenders to restructure these commitments. The current status and upcoming milestones for each facility are set forth below and a description of the restructuring discussions follows at the end of this section.

Senior Notes - Interest on the Senior Notes is payable semi-annually on May 15 and November 15 of each year. The next interest payment of approximately $52 million is due November 15, 2002. PG&E NEG does not expect to make this interest payment. The unsecured Senior Notes are due on May 15, 2011.

Corporate Revolver - The Corporate Revolver's $750 million 364-day tranche was originally due on August 22, 2002. PG&E NEG had expected to renew this tranche for another 364 days. As a result of PG&E NEG's downgrades to below investment grade at the end of July and the beginning of August, this debt was not renewed and instead the $431 million outstanding balance became due and payable on August 22, 2002. On August 22, 2002, the Corporate Revolver was amended to reduce the lenders' commitments to $500 million and to extend the maturity date to October 21, 2002. On October 21, 2002, the Corporate Revolver was amended further to extend the expiration and renewal date to November 14, 2002, and to reduce the lenders commitments under the 364-day tranche and the two-year tranche to $431 million and $273 million, respectively, which were the amounts outstanding as of October 21, 2002. PG&E NEG does not expect to repay the 364-day tranche on November 14, 2002 nor does PG& amp;E NEG expect a further extension of the maturity date. Absent such extension, PG&E NEG will be in default under the Corporate Revolver and the other five major facilities. The Corporate Revolver is an unsecured revolving credit facility.

Equipment Revolver - The commitments under the Equipment Revolver are scheduled to reduce by $25 million per quarter with the balance due at maturity on December 31, 2003. The next scheduled repayment of $25 million is due on January 1, 2003. PG&E NEG does not currently expect to make this equity payment nor its interest payment when due. Interest is payable on December 17, 2002, for approximately $3 million. The Equipment Revolver is secured by PG&E NEG's major equipment purchase agreements and is guaranteed by PG&E NEG.

GenHoldings Equity Commitment - Under the GenHoldings I, LLC (GenHoldings) credit facility, GenHoldings is committed to make equity contributions to fund construction of the Harquahala, Covert, and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. PG&E NEG has guaranteed GenHoldings' equity commitment. Due to the downgrade to below investment grade by both S&P and Moody's, PG&E NEG became required to fund construction draws under the GenHoldings credit facility entirely with equity until GenHolding's full equity commitment was fulfilled. After GenHoldings fulfilled its equity commitments, the lenders were to fund construction draws in accordance with the credit facility. In August and September 2002, PG&E NEG funded approximately $150 million of the equity commitments, with the outstanding equity commitment at September 30, 2002, remaining at $355 million. In October 2002, PG&E NEG notifi ed the lenders under the GenHoldings credit facility that it would not make further equity contributions on behalf of GenHoldings. On October 24, 2002, GenHoldings and the lenders entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders waived through November 14, 2002, existing defaults under the GenHoldings credit agreement, permitted GenHoldings to borrow up to $50 million, and agreed to issue specified letters of credit in a face amount not to exceed $36 million. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. On October 25, 2002, the lenders funded GenHoldings' pending draw request for the Athens, Covert, and Harquahala construction projects. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. PG&E NEG does not expect an extension to this forbearance.

La Paloma Equity Commitment - PG&E NEG guaranteed the repayment of certain debt representing La Paloma's equity commitment in the aggregate amount of $379 million which is due March 2003. Due to the downgrade to below investment grade by both S&P and Moody's, PG&E NEG, as guarantor, became required to make equity contributions under the La Paloma credit facility to fund construction costs. In October 2002, PG&E NEG funded $4.5 million of construction costs, reducing the outstanding equity commitment at October 31, 2002, to $374.5 million. In October 2002, PG&E NEG notified the lenders under the La Paloma credit facility that it would not make further payments of construction costs for La Paloma. On November 8, 2002, PG&E NEG and the La Paloma lenders entered into a waiver agreement pursuant to which, among other things, the lenders waived existing defaults and funded, on November 8, 2002, the pending draw request to pay construction costs. PG&E NEG does not c urrently expect to have sufficient funds to make the $374.5 million payment in March 2003.

Lake Road Equity Commitment - PG&E NEG guaranteed the repayment of certain debt representing Lake Road's equity commitment in the aggregate amount of $230 million, which is due March 2003. Lake Road entered commercial operation in May 2002. PG&E NEG does not currently expect to have sufficient funds to make this payment in March 2003.

Debt Restructuring Efforts

PG&E NEG's efforts to reduce debt or raise cash through various efforts, including asset sales, have failed to produce adequate sources of liquidity for PG&E NEG to meet its obligations. PG&E NEG, therefore, has been in active negotiations regarding a global debt restructuring of its debt with the lenders under the Corporate Revolver, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities and the Equipment Revolver as well as representatives of the holders of the Senior Notes. This global restructuring would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG's merchant assets and reduce energy trading operations. If agreed to by PG&E NEG's lenders and implemented by PG&E NEG, these various asset transfers, sales and abandonments would cause substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

If the restructuring cannot be achieved by agreement with PG&E NEG's creditors, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. Notwithstanding the restructuring efforts above, if PG&E NEG abandons, sells or transfers assets, in an effort to meet current liquidity needs, PG&E NEG would incur substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

Major Subsidiary Debt

PG&E NEG's subsidiaries are parties to three major facilities:

(in millions)	Aggregate Commitment		Amount Outstanding⁽¹⁾		Maturity
---------------------	---------------------		-------------------		----------------
PG&E GTN Notes	$	506	$	506	2003-2025
PG&E GTN Revolver	125		-		May 2005
USGenNE Revolver	100		89		August 2003

^{(1) Outstanding as of October 31, 2002}

PG&E NEG's subsidiaries are also borrowers under three other revolving credit facilities with aggregate commitments totaling $70 million.

The ratings downgrades of PG&E GTN and USGenNE have not resulted in any changes to the lenders' commitments under these facilities, adversely affected the subsidiaries' ability to draw available funds under these facilities, or materially increased such subsidiaries' costs of borrowing.

PG&E GTN Notes - PG&E GTN pays interest on the PG&E GTN Notes semiannually in June and December, with the next interest payment of approximately $15 million due in December 2002. PG&E GTN is current on its obligations under the PG&E GTN Notes.

PG&E GTN Revolver - PG&E GTN pays interest on the PG&E GTN revolver quarterly if any balances are outstanding. As of October 31, 2002, no amounts are drawn. PG&E GTN is current on its obligations under the PG&E GTN Revolver.

USGenNE Revolver - Of the $89 million outstanding under the USGenNe Revolver, as of October 31, 2002, $75 million are loans and $14 million are letters of credit. USGenNE pays interest on this facility quarterly, with the next interest payment of $0.5 million due on December 20, 2002. USGenNE is current on its obligations under the USGenNE Revolver.

Activities Related to Merchant Portfolio Operations

PG&E NEG and certain subsidiaries had provided guarantees to approximately 250 counterparties in support of PG&E ET's energy trading and non-trading activities related to PG&E NEG's merchant energy portfolio in the face amount of $2.8 billion (including $69 million in guarantees pursuant to pipeline tariff provisions and $89 million in guarantees to power pools which have an aggregate exposure of less than $1 million). Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully utilized at any time. As of October 27, 2002, PG&E NEG and its subsidiaries' aggregate net exposure under these guarantees was approximately $180 million, as follows: PG&E NEG $87 million, PG&E GTN $65 million, PG&E ET $27 million, and USGenNE $1 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, s ome counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its various subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At October 27, 2002, PG&E ET's estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) was approximately $106 million.

To date PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged default. No demands have been made upon the guarantors of PG&E ET's obligations under these trading agreements. However, the expected defaults of PG&E NEG under the debt facilities described above, will cause cross-defaults under certain master trading agreements which are guaranteed by PG&E NEG. In the past, PG&E ET also has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET's liquidity. The actual calls for collateral will depend largely upon counterparties' r esponses to the ratings downgrades, forbearance agreements, pre- and early-pay arrangements, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties' other commercial considerations. PG&E NEG's and its subsidiaries' ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG's financial condition and the degree of liquidity in the energy markets.

Tolling Agreements

The face amount of PG&E NEG's guarantees relating to PG&E ET's tolling agreements is approximately $600 million. The PG&E ET's five tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount up to $150 million, (2)) DTE-Georgetown, L.P. (DTE) guaranteed by PG&E GTN for up to $24 million, (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place, (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $176 million, and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty - Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to post security in the amount of $150 million. PG&E ET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of the guarantees to Liberty for the aggregate $150 million, Liberty must proceed first against PG&E NEG's guarantee, and can demand payment under PG&E GTN's guarantee only if (1) PG&E NEG is in bankruptcy, or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG& E ET has the right to terminate the agreement and seek recovery of a termination payment.

DTE - By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE, and that PG&E ET was required to post replacement security within 10 days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

Calpine - The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement, and construction contractor for the Otay Mesa facility. On October 16, 2002, PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002, that it was terminating the tolling agreement effective November 29, 2002. PG&E NEG was required to provide in December 2002, a guarantee of PG&E ET's payment obligations under a 10-year tolling agreement with Calpine involving the Otay Mesa facility. The guarantee amount was not to exceed $20 million. As a result of the termination of the tolling agreement, PG&E NEG believes it is no longer obligated to provide a guarantee.

Southaven - PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade, as defined in the agreement. The amount of the guarantee now does not exceed $176 million. The original maximum amount of the guarantee was $250 million, but this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002, pursuant to a subordinated loan agreement between PG&E ET and Southaven. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the agreement and because PG&E ET had failed to provide with in 30 days from the downgrade substitute credit support that meets the requirement of the agreement. Under the agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven's performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Caledonia - PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade, as defined in the agreement. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the agreement and because PG&E ET had failed to provide within 30 days from the affiliate's downgrade substitute credit support that meets the requirement of the agreement. Under the agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia's performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Under each tolling agreement determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG believes that its exposure under these guarantees will be less than $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to pay all of the termination payments if they become due.

Other Guarantees

PG&E NEG has provided guarantees related to other obligations by PG&E NEG subsidiaries and affiliates to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction and equipment procurement contracts. In the event PG&E NEG is unable to provide any additional or replacement security that may be required as a result of the downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary and affiliate obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG's power plants and pipelines. These guarantees are described below.

PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost - sharing arrangements. Failure to perform under those separate cost-sharing arrangements or the related guarantees would not have an impact on the constructor's obligations to complete the Harquahala and Covert projects pursuant to the construction contracts. However, in the event that the construction contractor incurs certain unreimbursed project costs or cost overruns, the contractor could assert a claim against PG&E NEG's subsidiary or PG&E NEG under its guarantees. PG&E NEG believes that no claim can be validly asserted by the construction contractor as of the date hereof.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy Company, has entered into with Attala Generating Company. Attala Generating Company entered into a $340 million sale-leaseback transaction. The tolling payments provide the lessee with sufficient cash flows to pay rent under the lease. Attala Energy Company is currently experiencing a negative cash flow performing under this agreement and requires cash infusions in order to perform its obligations. PG&E NEG may stop making cash infusions to Attala Energy Company, which could cause a default under the Attala sale-leaseback financing.

To support PG&E NEG's electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG has issued guarantees with an aggregate face value of up to approximately $175 million in connection with these equipment commitments. PG&E NEG's commitment to purchase combustion turbines and related equipment exceeds its current planned development activities. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due January and July 2003. Beginning in September 2003, PG&E NEG either must restart equipment payments or, for equipment requiring progress payments, must terminate such commitments and pay the associated termination costs. PG&E NEG estimates these termination costs, and its exposure under these guarantees, to be appro ximately $53 million as of October 31, 2002 (including the $14 million as of October 31, 2002).

The balance of the guarantees are for commitments undertaken by PG&E NEG or its subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

Other Commitments

PG&E NEG's subsidiary has entered into a construction contract for the Mantua Creek project and released the contractor to perform early construction activities; however, full mobilization of the construction contractor has not taken place and unrestricted construction has not occurred. On October 8, 2002, PG&E NEG's subsidiary suspended all construction activities related to Mantua Creek. As of September 30, 2002, PG&E NEG had recorded assets of $269 million for Mantua Creek, representing equipment payments, construction activities, development costs and gas transmission deposits. If PG&E NEG's subsidiary terminates construction of this project, its construction contractor and other equipment and service providers would be entitled to termination costs estimated to be $64 million. PG&E NEG's subsidiary would receive a refund due from its turbine vendor of approximately $31 million. The construction contractor and other equipment service providers are beneficiaries of letters of credit issued on behalf of Mantua Creek by PG&E NEG in the amount of approximately $37 million. The termination costs do not include remediation costs estimated to be $1 million.

PG&E NEG's subsidiary has executed construction contracts for its Smithland and Cannelton projects for up to 163 megawatts (MW) at two hydroelectric facilities on the Ohio River in Kentucky. As of September 30, 2002, PG&E NEG had recorded assets of $1.8 million for these projects, representing equipment payments and development costs. PG&E NEG's subsidiary had commenced construction of the first 16 MW of turbines for the Smithland project, but had suspended construction because recently stated seismic requirements caused a re-evaluation of the project's design in connection with the Army Corps of Engineers permit. The re-evaluation is complete and the U.S. Army Corps of Engineers concurs that the new seismic criteria will not require any design changes. PG&E NEG's subsidiary has not resumed construction. The construction contractor is the beneficiary of a letter of credit securing PG&E NEG's termination payment obligations. If PG&E NEG's subsidiary terminates construction of this project, the construction contractor will be entitled to draw on the letter of credit for approximately $7 million.

Material Notices

PG&E NEG and its subsidiaries have received various notices under major contracts (other than the tolling agreements described above) alleging anticipatory breaches of contract and defaults resulting from PG&E NEG's downgrades and its public statements regarding its decisions not to make certain payments. These notices include claims from at least one counterparty to a power supply agreement. In most cases, PG&E NEG or its subsidiary has disputed these allegations. In all cases, the counterparties have refrained from attempting to pursue remedies. The Shaw Group, Inc. (Shaw) has alleged anticipatory breaches of the construction contracts for each of the Covert and Harquahala projects based upon PG&E NEG's announcement that it would not further fund the GenHoldings projects, including the Covert and Harquahala projects. Covert and Harquahala have disputed these notices because they are current in their payments to Shaw. Shaw also has sought reinstatement of pre-financing guara ntees ($50 million each) originally issued in connection with the Covert and Harquahala projects. PG&E NEG has denied that the guarantees are reinstated because the financing arrangements remain in place. Finally, Shaw also has sought cash collateralization of PG&E NEG's $100 million of guarantees supporting Shaw's cost-sharing agreements with a subsidiary. PG&E NEG has reviewed the guarantees and informed Shaw that the guarantees do not contain any collateralization requirement.

Bechtel Power Corporation (BPC) has alleged a default based upon PG&E NEG's announcement that it would not further fund the GenHoldings projects, including the Athens project. Athens has disputed this notice because the lenders have continued to fund and BPC is the beneficiary of an escrow account covering future costs that is currently over-funded. BPC also has alleged a default for nonpayment at the Mantua Creek project. Mantua Creek has 30 days to cure this nonfunding. If it does not do so, BPC is the beneficiary of a letter of credit posted on behalf of the Mantua Creek project which is sufficient to cover such payment.

Other Matters

Sale of Interest in Hermiston - On November 4, 2002, affiliates of PG&E NEG entered into an agreement to sell 49.9 percent of its ownership interest in Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo Corporation of America. The buyer was granted an option to purchase, during the three month period beginning thirteen months immediately following the closing date, an additional 0.1 percent interest (at the fair market value at the date of exercise). HGC owns an undivided 50 percent interest in a 474 MW gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned by PacifiCorp who also purchases the output of the plant under a long-term contract. The sale is expected to be completed by December 31, 2002, following the receipt of necessary regulatory approvals. At September 30, 2002, book value of PG&E NEG's investment in Hermiston was approximately $44 million. PG&E NEG anticipates a pre-tax gain of approximately $23 million upon compl etion of the sale.

Closing of Spencer Station - On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating plant located in Denton, Texas. PG&E NEG acquired the 178 MW gas-fired plant in June 2001 and in addition PG&E ET entered into a contract to provide the power requirements under the contract. Despite the closing of the Spencer Station plant, PG&E ET will continue to provide power based on the requirements of this contract. Completion of the shut down is expected by December 2002. PG&E NEG will incur a pre-tax loss, upon shut down, of approximately $4 million which includes costs associated with decommissioning the plant and employee terminations.

PG&E NEG holds an indirect 50 percent interest in Logan Generating Company, L.P. (Logan). Logan leases and operates a 225 MW coal-fired cogeneration facility in New Jersey that sells its output to Conectiv. On October 29, 2002, the long-term coal supplier, Anker Energy Corporation, filed for protection under Chapter 11 of the Bankruptcy Code. Under the terms of Logan's non-recourse project financing, this filing constitutes a default, which Logan has sixty days to cure. The agent for Logan's lenders notified Logan that an event of default shall have occurred if not cured during the sixty day period. Logan is seeking a waiver from its lenders and hopes to either have the coal supply contract assumed by Anker in bankruptcy or, if it is rejected by Anker, replaced by a similar agreement with another supplier. Until such time as the default is cured or waived, Logan will be unable to distribute cash to its partners. In 2001, Logan distributed $11.6 million to PG&E NEG. During the nine months en ded September 30, 2002, Logan distributed $6.0 million to PG&E NEG.

Investigations are underway by state and federal authorities into energy trading matters. In response to a data request order from the FERC, PG&E NEG conducted an investigation into certain activities of its subsidiaries in the U.S. portion of the Western Systems Coordinating Council (WSCC) during the years 2000 and 2001. The FERC requested information regarding transactions in which energy traders simultaneously engaged in any purchase and sale of the same product at the same price with the same counterparty in the WSCC during the years 2000 and 2001. As a result of its investigation, PG&E NEG identified 12 such instances. In addition, PG&E NEG has reviewed its activities, including those in other regions, during the period January 2000 through May 2002 using the FERC criteria and has identified 36 additional instances. These instances had no material effect on PG&E NEG's reported revenues or financial results. Revenues associated with these instances represent an immaterial amount o f PG&E NEG's revenues during the same period.

PG&E NEG maintains an insurance program that includes coverage for power plant construction and operating risks. Recent events have adversely affected the insurance industry generally and the machinery and equipment segment in particular. This effect is especially acute for insurance covering advanced gas turbine technology, including many of those which PG&E NEG has in construction. As a result, PG&E NEG expects that its insurance coverage will be at lower levels than PG&E NEG has procured historically, certain coverage (for example, terrorism insurance) may no longer be available on commercially reasonable terms, deductibles will increase in size, and premiums will be significantly higher. Therefore, PG&E NEG likely will carry a greater percentage of self-insurance at potential risk of greater losses than in prior periods.

PG&E NEG implemented a program to reduce administrative, general and other operating costs by a minimum of $50 million measured from 2001actual costs.

Operating Activities

PG&E NEG's funds from operations come from distributions from PG&E NEG's subsidiary companies. Cash flow distributions from subsidiaries are subject to various debt covenants, organizational bylaws, and partner approvals that can restrict these entities from distributing cash to PG&E NEG unless, among other things, debt service, lease obligations, and any applicable preferred payments are current, the applicable subsidiary or project affiliate meets certain debt service coverage ratios, a majority of the participants approve the distribution, and there are no events of default. In addition, PG&E GTN and the subsidiaries that own PG&E NEG's energy trading businesses cannot pay dividends unless the subsidiary's board of directors or board of control, including its independent director, unanimously approves the dividend payment and the subsidiary either has a specified investment grade credit rating or meets a consolidated interest coverage ratio of greater than or equal to 2.25 to 1.00 and a consolidated leverage ratio of less than or equal to 0.70 to 1.00.

During the nine months ended September 30, 2002, PG&E NEG used net cash from operations of $23 million, compared to net cash generated from operations of $316 million for the same period in 2001, or a decrease of $339 million. Net income declined by $424 million between periods, but net income adjustments to reconcile net income with net cash provided in operating activities overall results in improved operating cash flow by $109 million period to period. The increase from period to period was due primarily to realization of cash from net price risk management activities. Offsetting this increase in cash flow from operations was a decrease due to the net effect of changes in operating assets and liabilities, including other net items, of $448 million period to period. The cash flows used for operating assets and liabilities, including other net items, primarily increased due to additional prepayments and deposits needed as a result of the credit rating downgrades. Include d in Cash Flows From Investing Activities for the nine months ended September 30, 2002 and 2001, is a cash flow of $61 million and $60 million, respectively, related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company that are reflected in Cash Flows From Operating Activities.

Investing Activities

PG&E NEG's cash outflows from investing activities are attributable primarily to capital expenditures on generating and pipeline assets in construction and advanced development and turbine prepayments. During the nine months ended September 30, 2002, PG&E NEG used net cash of $957 million in investing activities, compared to $1,146 million for the same period in 2001, or a decrease of $189 million. The decrease in investing activities from period to period were due primarily to proceeds from the Attala Generating Company sale-leaseback transaction providing $340 million and the repayment of a $75 million loan to PG&E Corporation from PG&E GTN, both occurring in the second quarter of 2002. Offsetting these proceeds were increased construction expenditures of $1,307 million for the nine months ended September 30, 2002, versus $957 million for the nine months ended September 30, 2001. Total capital expenditures, including construction expenditures, by segment are shown i n the below table:

		Three months ended September 30,					Nine months ended September 30,
		---------------------------					------------------------------
		2002		2001			2002		2001
(in millions)		----------		----------			-----------		------------
Capital Expenditures:
	Integrated Energy and Marketing Activities	$	346	$	459	$		1,165	$	1,008
	Interstate Pipeline Operations	45		28		163			51
		----------		----------		-----------			------------
Total Capital Expenditures		$	391	$	487		$	1,328	$	1,059
		======		======			=======		=======

Advanced development and turbine prepayments were $9 million and $216 million for the nine months ended September 30, 2002, and 2001, respectively. Also during the nine months ended September 30, 2001, several projects were moved from advanced development activities to construction work in progress for approximately $160 million, and the purchase of the Mountain View wind projects was completed for $92 million. No comparable activities occurred during the nine months ended September 30, 2002. As a result of investment downgrades, PG&E ET replaced a $74 million letter of credit issued to Southaven with cash pursuant to a subordinated loan agreement. This cash expenditure is reflected in PG&E NEG's cash used in investing activities. Included in Investing Activities for the nine months ended September 30, 2002 and 2001, is a cash flow of $61 million and $60 million, respectively, related to the long-term receivable from New England Power Company associated with the assumption of power pur chase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities. Other net expenditures were $22 million and $1 million for the nine months ended September 30, 2002, and 2001, respectively. To date, PG&E NEG has made a number of commitments associated with the planned growth of owned and controlled generating facilities and pipelines. These include commitments for projects under construction, commitments for the acquisition and maintenance of equipment needed for the projects under development, payment commitments for tolling arrangements, and forward sale and purchase commitments associated with PG&E NEG's energy marketing and trading activities.

Generating Projects in Construction - PG&E NEG currently owns five generating facilities under construction. The table below outlines the expected dates that these will be completed assuming the lenders continue to fund construction.

Projects	Location		Percentage Completion		Projected In-Service Date	MWs
----------------	---------------		---------------		-----------------------	---------------
Athens		New York	70	%	3rd quarter 2003	1,080
Covert		Michigan	61		3rd quarter 2003	1,170
Harquahala		Arizona	69		3rd quarter 2003	1,092
La Paloma		California	99		1st quarter 2003	1,031
Mantua Creek		New Jersey	22		Undetermined	897

On October 24, 2002, GenHoldings and the lenders under the GenHoldings credit facility entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders (i) waived through November 14, 2002, existing defaults under the GenHoldings credit agreement (ii) permitted GenHoldings to borrow up to $50 million, and (iii) agreed to issue specified letters of credit in a face amount not to exceed $36 million. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. On October 25, 2002, the lenders funded GenHoldings' pending draw request for the Athens, Covert, and Harquahala construction projects.

A local intervenor group has contested in federal court the issuance of a U.S. Army Corps of Engineers (ACOE) permit for the Athens facility alleging, among other things, that the ACOE violated the National Environmental Policy Act. The intervenor group sought preliminary and permanent injunctive relief. The court denied the preliminary relief requested and the intervenor group has appealed. The appeals court affirmed the lower court's denial of the preliminary relief requested.

Generating Projects in Development - PG&E NEG has reviewed its growth plans for its electric generating business in light of the recent changes in the energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices, electric generating industry fundamentals, and financial market's support for competitive energy companies have significantly declined, thereby constraining access to funds at acceptable terms to PG&E NEG. Oversupply of electric generation now and in the near future has significantly decreased the value of planned future development projects. In response to these market changes and considering the expected level of future electric generating supply, PG&E NEG has reconsidered the extent of, and reduced its planned investment activities in, electric generating development projects. PG&E NEG has analyzed the potential cash flow from those projects that it no longer anticipates pursuing and has recognized an impairment of the asset va lue that it is carrying for those development projects. The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment costs discussed below) is $19 million. The remaining asset value (recorded in Other Noncurrent Assets) that PG&E NEG has retained as of September 30, 2002, for its portfolio of development projects is $49 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal. PG&E NEG has no material commitments (excluding equipment costs discussed below) for the projects under continuing development.

Turbine Purchase Commitments - To support PG&E NEG's electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG's commitment to purchase combustion turbines and related equipment exceeds the new planned development activities discussed above. The current electric generating market is faced with an oversupply of facilities in operation and under construction. The current and future market for combustion turbines and related equipment also has seen an oversupply and large cancellation of turbine orders. The net realizability of PG&E NEG's investment in, and future committed payments for, its excess combustion turbine and related equipment portfolio, in light of current development plans, is doubtful. Based upon PG&E NEG's current development plans and analysis of future market prices for combustion turbines and related equipment, PG&E NEG has recog nized a charge of $246 million. The charge consists of the impairment of previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $53 million as of October 31, 2002, for future termination payments required under the turbine and related equipment contracts. Although PG&E NEG has impaired the value of these turbines and related equipment, it has terminated its commitments or options, with respect to only three turbines and related equipment. The remaining asset value (recorded in Other Noncurrent Assets) that PG&E NEG has retained as of September 30, 2002, for its investment in turbines and related equipment is approximately $34 million. These turbine and equipment commitments have been retained to support the equipment needs for PG&E NEG's current portfolio of advanced development projects discussed above. PG&E NEG and its equipment vendors have agreed to sus pend any PG&E NEG payment obligations (except for $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due in January and July 2003. Beginning in September of 2003, PG&E NEG either must restart equipment payments or, for equipment requiring progress payments, terminate such commitments and pay the associated termination costs.

PG&E GTN Pipeline Expansion - PG&E GTN has substantially completed its 2002 Expansion Project, expanding its system by approximately 217 MMcf per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November of 2001, and the remaining capacity was placed in service in November 2002. The total cost of the expansion is approximately $127 million. One shipper contractually committed to 175,000 Dth per day capacity of this project failed to provide PG&E GTN with adequate assurances of the shipper's ability to meet its obligations under its transportation contract. PG&E GTN and that shipper subsequently terminated the transportation contract and PG&E GTN has retained $16.8 million in collateral received from that shipper.

In response to changing market conditions, PG&E GTN subsequently reached agreement with all shippers contractually committed to a second expansion (2003 Expansion Project) to terminate their firm transportation precedent agreements. Accordingly, on October 10, 2002, PG&E GTN filed with the FERC a request to vacate its 2003 Expansion proceeding and deferred the project. To date PG&E GTN has spent $5.3 million on the project. PG&E GTN is continuing necessary development activities and expects to refile an application with FERC when market conditions improve.

Each of the former 2003 Expansion shippers has committed to take capacity on PG&E GTN's system made available as a result of the 2002 shipper termination, capacity formerly held by Enron, or other existing capacity on PG&E GTN's system. PG&E GTN anticipates that it will enter into additional contracts for capacity made available from these sources through open market sales. As of November 8, 2002, PG&E GTN has approximately 155,000 Dth per day of capacity available for subscription on a long-term basis.

PG&E GTN regularly solicits expressions of interest for the acquisition or development of additional pipeline capacity and may develop additional firm transportation, capacity as sufficient demand is demonstrated. PG&E GTN has initiated preliminary assessments of lateral pipelines that would originate on the PG&E GTN mainline system and would extend to metropolitan areas in the Pacific Northwest.

North Baja Pipeline - PG&E NEG is constructing a new 500 MMcf per day gas pipeline, North Baja, to deliver natural gas to Northern Mexico and Southern California. North Baja will consist of approximately 80 miles of pipe and 25,000 horsepower (HP) of compression. The pipeline segment of North Baja was placed into service in September 2002, and the compression facilities are expected to be completed by the end of 2002. At September 30, 2002, PG&E NEG had spent approximately $137 million on this project. PG&E NEG owns all of the United States section of this cross-border project. PG&E NEG's share of the costs to develop this project will be approximately $150 million.

The California State Lands Commission is a defendant and, along with North Baja, is a real party in interest in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline in California failed to address environmental justice and other issues as required by the California Environmental Quality Act (CEQA). The claim seeks an injunction restraining construction of the pipeline, but no request for a temporary restraining order was filed. Therefore, construction of the project is underway. PG&E NEG intends to participate vigorously in the lawsuit. A hearing on the merits of the case was held on September 13, 2002. A decision is expected soon.

Financing Activities

PG&E NEG's cash outflows from financing activities were attributable primarily to increases in borrowings under PG&E NEG's credit facilities relating to the continuing completion of PG&E NEG's construction facilities and borrowings under construction financing. For the nine months ended September 30, 2002, and 2001, PG&E NEG provided net cash flows from financing activities of $626 million and $818 million, respectively. This decrease is related primarily to the timing of construction funding needed for the Athens, La Paloma, Covert, and Harquahala projects. New loan agreements prohibit PG&E NEG from spending on these projects.

PG&E Corporation

Operating Activities

Net cash provided by operating activities totaled $1,066 million and $4,774 million for the nine months ended September 30, 2002, and 2001, respectively. The decrease of $3,708 million between 2002 and 2001 was due partially to the $1.1 billion income tax refund received in the nine months ended September 30, 2001, with no such refund received in 2002. In addition, the Utility made payments in retirement of certain obligations classified as liabilities subject to compromise in the nine months ended September 30, 2002.

Investing Activities

Cash used in investing activities was $2,089 million and $2,053 million for the nine months ended September 30, 2002, and 2001, respectively. The increase of $36 million between 2002 and 2001 was mainly due to increased capital expenditures in 2002 for the improvement of the Utility's electric and gas transmission and distribution networks, along with construction on PG&E NEG's generation facilities and pipelines. Offsetting this increase in capital expenditures were proceeds of $340 million received from a sale-leaseback and a decrease in PG&E NEG's development costs and turbine prepayments in 2002.

Financing Activities

Cash generated through financing activities was $87 million and $349 million for the nine months ended September 30, 2002, and 2001, respectively. The decrease of $262 million was a result of the Utility's repayment of long-term debt, offset by PG&E NEG's increased borrowings under new and existing credit facilities. See Note 4 of the Notes to the Consolidated Financial Statements for more information on PG&E NEG's new credit facilities. In addition, a loan to PG&E Corporation in 2001 netted $906 million in proceeds which was used with cash on hand to repay defaulted commercial paper, other loans, and dividends. Furthermore, the Utility and PG&E NEG paid down long-term debt balances in 2001.

Utility

The Utility currently is operating as a debtor-in-possession under Chapter 11 of the Bankruptcy Code. While certain pre-petition debts are stayed, the Utility does not have access to external funding from capital markets. Additionally, the Utility is in default under its credit facilities, commercial paper, floating rate notes, senior notes, pollution control reimbursement agreements, and medium-term notes, as a result of its failure to pay certain of its obligations. The event of default under each security has been stayed in accordance with the bankruptcy proceedings. The Utility has been making capital investments in its infrastructure out of cash on hand under supervision of the Bankruptcy Court. The Utility anticipates that it will be able to continue making such necessary capital investment in the future, subject to approval by the Bankruptcy Court. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the Utility's Chapter 11 bankruptcy filing.

Since January 2002, the Utility has entered into agreements with additional QFs to assume their power purchase agreements. At September 30, 2002, $704 million and $61 million in principal and interest, respectively, had been paid to QFs.

On March 27, 2002, the Bankruptcy Court issued an order authorizing the Utility to pay pre- and post-petition interest to holders of certain undisputed claims (including commercial paper, senior notes, floating rate notes, medium-term notes, Cumulative Quarterly Income Preferred Securities (QUIPS), prior bond claims, and revolving line of credit claims), trade creditors, and certain other general unsecured creditors. Pursuant to the court's order, the Utility paid approximately $599 million in pre- and post-petition interest related to these claims during the nine months ended September 30, 2002, including accrued interest amounts totaling $433 classified as liabilities subject to compromise.

The Utility estimated that interest payments to creditors pursuant to the Bankruptcy Court's authorization could be as much as $1.1 billion through the fourth quarter of 2002, based on the claim amounts estimated in the Utility's disclosure statement; however, the Utility has withheld a portion of this amount because it disputes the underlying claims and will not pay interest on these disputed claims until the disputes are resolved. The actual amount of pre- and post-petition interest eventually paid may be different, depending on the amount of claims ultimately allowed by the Bankruptcy Court.

As the Utility has been accruing interest on its pre- and post-petition debt at the approved rates, the payment of such interest is not expected to have a material adverse impact on its financial condition or results of operation.

The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the nine months ended September 30, 2002, and 2001.

Operating Activities

Net cash provided by operating activities decreased to $1.3 billion for the nine months ended September 30, 2002, from $4.3 billion for the same period in the prior year. The decrease is due primarily to payments made in the nine months ended September 30, 2002, pursuant to Bankruptcy Court orders, which consisted primarily of principal and interest payments to QFs, and the payment of pre-and post-petition interest on financial debt and other general unsecured and secured debt. See the discussion of liabilities subject to compromise in Note 2 of the Notes to the Consolidated Financial Statements. Additionally, net cash provided by operating activities in 2001 included an income tax refund of approximately $1.1 billion.

Investing Activities

The primary use of cash by investing activities was for additions to property, plant and equipment. While the Utility is in Chapter 11, these expenditures will be funded from cash provided by operating activities. Capital expenditures were $1.2 billion and $889 million for the nine months ended September 30, 2002, and 2001, respectively, and were attributable primarily to the improvement of the distribution and transmission networks for electric and gas operations. Planned expenditures for 2002 are $1.6 billion, and mainly include projects designed to upgrade and improve the Utility's gas and electric transmission and distribution system.

Financing Activities

Net cash used by financing activities in the nine months ended September 30, 2002, was $546 million, reflecting mainly the repayment of long-term debt. Repayment of matured long-term debt consisted of $333 million related to mortgage bonds, paid pursuant to a Bankruptcy Court order, and $213 million related to the Rate Reduction Bonds, which are held by PG&E Funding LLC, a wholly owned subsidiary of the Utility.

Net cash used by financing activities in the nine months ended September 30, 2001, was $353 million, reflecting mainly the net repayment under credit facilities and short-term borrowings of $28 million and repayment of long-term debt of $325 million. Repayment of long-term debt consisted of payments of $93 million and $19 million related to maturities of mortgage bonds and medium-term notes, respectively, and payments totaling $213 million related to the Utility's Rate Reduction Bonds.

Except as discussed in Note 2 of the Notes to the Consolidated Financial Statements, the Utility has no plans to seek external financing alternatives as a source of funding. In addition, until its financial condition is restored, the Utility is precluded from paying dividends to its shareholders. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock.

Other Commitments and Contingencies

The Utility has substantial financial commitments and contingencies in connection with its operating, investing, and financing activities. See Note 7 of the Notes to the Consolidated Financial Statements for further discussion of commitments and contingencies.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation and the Utility conduct risk management activities in a manner that supports business objectives, minimizes costs, and discourages unauthorized physical and financial risk through a strong internal control environment. PG&E Corporation and the Utility intend to manage exposures to market, credit, volumetric, regulatory, operational, and reliability risks to manage the volatility of earnings and cash flows. Such risks may be managed using cost-effective risk management programs that may 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.

A forward contract is a commitment to purchase or sell energy commodities at a specified future date at a specified price.

A futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell an energy commodity or financial instrument at a specified future date at a specified price.

A swap agreement requires payments for a quantity of an energy commodity based upon the difference between agreed-upon prices.

An option contract provides the right, but not the obligation, to buy or sell the underlying commodity at a predetermined price in the future.

PG&E Corporation uses derivatives for both trading (for profit) and non-trading purposes. PG&E Corporation and the Utility may enter into energy and financial derivative instruments and other instruments and agreements for purposes of mitigating 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 in accordance with approved risk management policies adopted by a senior officer-level risk oversight committee. Additionally, PG&E Corporation may engage in trading activities for purposes of generating profit, gathering market intelligence, creating liquidity, maintaining a market presence, and taking a market view. Derivative activity is permitted only after the senior officer-level risk oversight committee approves appropriate risk limits for such activity and the organizational unit proposing the activity successfully demonstrates that there is a business ne ed for such activity and that the market risks will be adequately measured, monitored, and controlled.

The activities affecting the estimated fair value of trading activities and the non-trading activities balance, included in net price risk management assets and liabilities, are presented below.

	Three Months Ended		Nine Months Ended
	September 30, 2002		September 30, 2002
	--------------------------		-------------------------
(in millions)

Fair values of trading contracts at beginning of period	$	(1)	$	33
Net gain on contracts settled during the period	84		165
Fair value of new contracts when entered into	2		2
Changes in fair values attributable to changes in valuation techniques and assumptions	(12)		(12)
Other changes in fair values	(63)		(178)
	-------------------		-------------------
Fair values of trading contracts outstanding at end of period		10	10

Fair value of non-trading contracts at the end of the period		(422)	(422)
	-------------------		-------------------
Net Price Risk Management Liabilities at end of period	$	(412)	$	(412)
	===========		===========

The changes in fair values attributable to changes in valuation and assumptions, as reported in the table above, are composed of a $14 million loss related to PG&E NEG's implementation of a new methodology for estimating forward prices in illiquid periods and a $2 million gain related to changes in assumptions used to value transportation contracts. This change in forward prices is described more fully in Note 1 of the Notes to the Consolidated Financial Statements.

PG&E Corporation estimated the fair value of its trading contracts at September 30, 2002, using the midpoint of quoted bid and ask prices, where available, and other valuation techniques when market data was not available (e.g., for illiquid markets or products). When market data is not available, PG&E Corporation uses its forward price curve methodology described in Note 1 to the Consolidated Financial Statements. Most of PG&E Corporation's risk management models are reviewed by or purchased from third-party experts with extensive experience in specific derivative applications. The fair value of trading contracts also includes deductions for time value, credit, model, and other reserves necessary to determine fair value.

The following table shows the fair value of PG&E Corporation's trading contracts by maturity at September 30, 2002.

Fair Value of Trading Contracts ⁽²⁾

---------------------------------------------------------------------------------------------

Source of Prices Used in
   Estimating Fair Value

Maturity
Less than
One Year

Maturity
One-Three
Years

Maturity
Four-Five
Years

Maturity
in Excess of
Five Years

Total
Fair
Value

-----------

-------------

-----------

-------------

-----------

(in millions)

Actively quoted markets

$

(10)

$

8

$

4

$

-

$

2

Provided by other external sources

14



(22)

(13)

(1)

(22)

Based on models and other

   valuation methods ⁽¹⁾

3

(14)

(12)

53

30

----------

----------

----------

----------

----------

Total Mark-to-Market

$

7

$

(28)

$

(21)

$

52

$

10

======

======

======

======

======

^{(1) In many cases, these prices are an input into option models that calculate a gross mark-to-market value from which fair value is derived.
^{(2) Excludes all non-trading contracts, including non-trading contracts that receive mark-to-market accounting treatment.}

The amounts disclosed above are not indicative of likely future cash flows, as these positions may be impacted by changes in underlying valuations, new transactions in the trading portfolio in response to changing market conditions, market liquidity, and PG&E Corporation's risk management portfolio needs and strategies.

Market Risk

Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow. Such risks include commodity price risk, interest rate risk, foreign currency risk, and credit risk and may impact PG&E Corporation's and its subsidiaries' assets and trading portfolios.

Price Risk

Price risk is the risk that changes in market prices will adversely affect earnings and cash flows.

Utility Electric Commodity Price Risk

In compliance with regulatory requirements, the Utility manages commodity price risk independently from the activities in PG&E Corporation's unregulated businesses. The Utility reports its commodity price risk separately for its electricity and natural gas businesses. Since January 2001, the DWR has been responsible for purchasing wholesale power for the Utility's retail electric customers on behalf of the State. The Utility currently is passing through revenues to the DWR, in accordance with the CPUC's May 16, 2002, servicing order, based on the amount of power supplied by the DWR to cover the Utility's net open position and the per kWh rate established by the CPUC's March 21, 2002, revenue requirement decision (see discussion of the DWR's proposed amendment to the CPUC's May 16, 2002, servicing order in Note 2 of the Notes to the Consolidated Financial Statements). Future revisions to the DWR's revenue requirement as a result of, among other things, changes in the market price of electric e
nergy may impact the amount of revenues allocated from the Utility to the DWR. Under the Utility's electric rates currently in effect and subject to the implementation of SB 1976 (see below), the Utility is exposed to commodity price risk, as changes in the amount of revenues allocated to the DWR as pass-through revenues impact the amount of remaining revenues that the Utility has available to recover its generation, transmission, and distribution costs.

Under AB 1X, the DWR is prohibited from entering into new power purchase contracts and from purchasing power on the spot market after January 1, 2003. On September 24, 2002, California SB 1976 was signed into law. SB 1976 requires that the Utility resume electricity procurement responsibility for the portion of its net open position not covered by existing DWR contracts. It also requires the CPUC to allocate the electricity subject to existing DWR contracts among the IOUs, including the Utility. Under SB 1976, each IOU is required to submit, within 60 days of the CPUC's allocation, an electricity procurement plan to meet its residual net open position needs after taking into account the quantities of electricity under the DWR contracts allocated to it by the CPUC. SB 1976 authorizes the CPUC to create power procurement balancing accounts to track and allow recovery of the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC would be required to review
, at least semi-annually, the balancing accounts, and to adjust rates or order refunds, as necessary to properly amortize a balancing account.

On September 19, 2002, the CPUC issued a decision allocating electricity subject to the DWR contracts to the generation portfolios of the three California IOUs for operational and scheduling purposes. The DWR will retain legal title and financial reporting and payment responsibility associated with these contracts. The IOUs will, however, become responsible for scheduling and dispatch of the quantities subject to the allocated contracts and for many administrative functions associated with those contracts. The IOUs would continue to act as billing and collection agents for the DWR.
On October 24, 2002, the CPUC issued another decision regarding SB 1976, ordering the IOUs to resume full procurement responsibilities on January 1, 2003. The decision requires the Utility to submit modifications to its short-term procurement plan to the CPUC by November 12, 2002, and to submit its long-term procurement plan by April 1, 2003. However, the decision does not establish the balancing account structure authorized by SB 1976. The CPUC indicated that it would address any necessary ratemaking structure in a subsequent proceeding.
Additionally, the CPUC has authorized the Utility to enter into contracts between August 22, 2002, and December 31, 2002, for energy deliveries and capacity purchases to meet the residual net open energy requirement beginning January 1, 2003, with the DWR acting as the creditworthy purchaser until such time as the Utility regains its investment grade credit rating and is able to assume all rights and obligations of the buyer in such contracts. In October 2002, the Utility entered into interim procurement contracts that would obligate itself and the DWR upon the occurrence of certain conditions. The Utility is not obligated under the contracts until the following conditions have been met: (1) the Utility has achieved an investment grade credit rating, (2) the CPUC has approved the contracts as just and reasonable for their entire term, (3) the Bankruptcy Court has approved the contracts, and (4) the DWR has agreed to be financially and legally obligated under the contracts until such time as the Utility
is investment grade.
The Utility believes that resumption of full procurement and assumption of operational responsibility for the DWR contracts has the potential for continued exposure to (1) after-the-fact reasonableness reviews and disallowances of costs associated with the Utility's new procurement actions and DWR contracts which the CPUC allocates to the Utility's customers, and (2) delays in the recovery of Utility procurement costs. In addition, the amount of energy provided by the DWR's long-term contracts, in conjunction with that provided by the Utility's retained generation, may not be sufficient to meet all of the Utility's customer's energy needs beginning January 1, 2003, and may result in a residual net open energy requirement. Conversely, the amount of energy provided by the DWR contracts likely will result in significant excess power during various periods, which the Utility will be required to attempt to market. See the discussion of the Generation Procurement OIR in the "Regulatory Matters" section of th
is MD&A.

Utility Natural Gas Commodity Price Risk

Under a ratemaking method called the Core Procurement Incentive Mechanism (CPIM), the Utility recovers in retail rates the cost of procuring natural gas for its customers as long as the costs are within a 99 percent to 102 percent tolerance band of a benchmark price. The CPIM benchmark price reflects a weighting of prescribed daily and monthly gas price indices that are representative of Utility gas purchases. Ratepayers and shareholders share costs or savings outside the tolerance band equally. In addition, the Utility has contracts for capacity on various gas pipelines. Although the Utility recovers most of the cost of the capacity contracts in retail rates, there is price risk related to the unused portions of the pipeline capacity to the extent that it is brokered at floating rates, which are reset monthly to reflect changes in commodity prices.

Under a ratemaking pact called the Gas Accord, shareholders are at risk for any revenues from the sale of capacity on the Utility's pipelines and gas storage fields. According to the terms of the Gas Accord, a portion of the pipeline and storage capacity is sold at competitive market-based rates. The Utility generally is exposed to reduced revenues when the price spreads between two delivery points narrow. In addition, the Utility generally is exposed to reduced revenues when throughput volumes are lower than expected, primarily caused by temperature and precipitation effects or by economy-driven impacts. Although the Gas Accord originally was scheduled to expire on December 31, 2002, the Utility filed an application to extend the Gas Accord for two years, known as the Gas Accord II Application, or Gas Accord II. In August 2002, the CPUC approved a settlement agreement among the Utility and other parties that provided for a one-year extension of the Utility's existing gas transmission and storage rat
es and terms and conditions of service, as well as rules governing contract extensions and an open season for new contracts. The Gas Accord II settlement left open to subsequent litigation the issues raised in the application in so far as they relate to the second year of the two-year application.

In October 2002, the assigned CPUC ALJ issued a ruling that granted, in part, the Utility's motion to postpone the procedural schedule for litigation of the unresolved issues. The ALJ ruling directed the Utility to file prepared testimony and a cost-of-service study by December 9, 2002, the other parties to file prepared testimony by January 27, 2003, and all parties to file rebuttal testimony by February 28, 2003, with evidentiary hearings set for March 10, 2003 through March 14, 2003.

PG&E NEG

PG&E NEG is exposed to commodity price risk for its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, and with respect to various merchant plants currently in development and construction. PG&E NEG manages such risks using a risk management program that includes primarily the buying and selling of fixed-price commodity commitments to lock in future cash flows of its forecasted generation. PG&E NEG also is exposed to commodity price risk for net open positions within its trading portfolio due to the assessment of, and response to, changing market conditions.

Value-at-Risk

PG&E Corporation and the Utility measure price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the probability of future potential losses. Price risk is quantified using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period.

PG&E Corporation uses historical data for calculating the price volatility of its contractual positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity instruments over the entire length of the terms of the transaction in the trading and non-trading portfolios. PG&E Corporation and the Utility express value-at-risk as a dollar amount of the potential loss in the fair value of their portfolios based on a 95 percent confidence level using a one-day holding period. Therefore, there is a 5 percent probability that PG&E Corporation's and its subsidiaries' portfolios will incur a loss in one day greater than their value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95 percent confidence level that if prices moved against current positions, the reduction in the value of the portfolio resulting from such one-day price movements would not exceed $5 million.

The following table illustrates the daily value-at-risk exposure for commodity price risk at September 30, 2002.

(in millions)

Utility

  Non-trading activities ⁽¹⁾

$

6

PG&E NEG

  Trading activities

3

  Non-trading activities:

  Non-trading contracts that receive mark-to-market accounting treatment ⁽²⁾

2

  Non-trading contracts accounted for as hedges ⁽³⁾

19

^{(1) Includes the Utility's gas portfolio only.
^{(2) Includes derivative power and fuels contracts that do not qualify to be accounted for as cash flow hedges, due to certain pricing provisions, or exempted from SFAS No. 133 as normal purchases and sales.
^{(3) Includes only the risk related to the financial instruments that serve as hedges and does not include the related underlying hedged item.}}}

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, 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, legislative, and legal risks currently facing the Utility or the risks relating to the Utility's bankruptcy proceedings.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on working capital facilities, the risk of increasing interest rates on new money notes and exchange notes used for debt refinancings, and the risk of increasing rates on variable rate tax-exempt pollution control bonds.

PG&E Corporation may use the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forward and futures contracts. 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, 2002, if interest rates change by 1 percent for all variable rate debt at PG&E Corporation and the Utility, the change would affect net income by approximately $35 million and $29 million, respectively, based on variable rate debt and derivatives and other interest rate-sensitive instruments outstanding.

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. The Utility and PG&E Corporation are exposed to foreign currency risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. However, for the Utility, 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 costs are within a 99 percent to 102 percent tolerance band of the benchmark price under the CPIM mechanism. The Utility's customers and shareholders would share in the cost savings outside of the tolerance band equally. In addition, PG&E Corporation has translation exposure resulting from the need to translate Canadian-denominated financial statements of its affiliate, PG&E Energ
y Trading, Canada Corporation, into U.S. dollars for PG&E NEG's Consolidated Financial Statements. PG&E Corporation and the Utility use forwards, swaps, and options to hedge foreign currency exposure.

PG&E Corporation and the Utility use sensitivity analysis to measure their foreign currency exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at September 30, 2002, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E Corporation's and the Utility's Consolidated Financial Statements.

Credit Risk

Credit risk is the risk of an accounting loss that PG&E Corporation and the Utility would incur if counterparties fail to perform their contractual obligations (net accounts receivable, notes receivable, and PRM assets reflected on the balance sheet). PG&E Corporation and the Utility conduct business primarily with customers in the energy industry, such as investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies, located in the United States and Canada. This concentration of counterparties may impact PG&E Corporation's and the Utility's overall exposure to credit risk in that their counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E Corporation and the Utility manage credit risk pursuant to their respective Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. The
se procedures include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E Corporation and the Utility rely heavily on master agreements that contain credit support provisions requiring the counterparty to post security 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.

PG&E Corporation and the Utility calculate gross credit exposure by counterparty as the current mark-to-market value (what would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of credit collateral. In the past year, PG&E Corporation's and the Utility's credit risk has increased partially due to credit rating downgrades of some of the counterparties in the energy industry to below investment grade.

At September 30, 2002, PG&E Corporation had no single counterparty that represents greater than 10 percent of PG&E Corporation's net credit exposure. At September 30, 2002, the Utility had one investment grade counterparty that represents 17 percent of the Utility's net credit exposure, and one below investment grade counterparty that represents 15 percent of the Utility's net credit exposure.

The schedule below summarizes the exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), at September 30, 2002:

(in millions)

Gross

Exposure ⁽¹⁾

Credit

Collateral ⁽²⁾

Net

Exposure ⁽²⁾

----------------

----------------

----------------

PG&E Corporation

$

1,266

$

221

$

1,045

Utility ⁽³⁾

236

102

134

^{(1) Gross credit exposure equals mark-to-market value (adjusted for applicable credit valuation adjustments), notes receivable, and net receivables (payables) where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity model or credit reserves.
^{(2) Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit).
^{(3) The Utility's gross exposure includes wholesale activity only. Retail activity and payables prior to the Utility's bankruptcy filing are not included. Retail activity at the Utility consists of the accounts receivable from the sale of gas and electricity to residential and small commercial customers.}}}

At September 30, 2002, approximately $228 million or 22 percent of PG&E Corporation's net credit exposure is to entities that have credit ratings below investment grade. Approximately $54 million or 40 percent of the Utility's net credit exposure is to below investment grade entities. Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. Approximately $86 million or 9 percent of PG&E Corporation's net credit exposure at PG&E NEG is not rated. PG&E Corporation has regional concentrations of credit exposure to counterparties that conduct business primarily in the western United States and also to counterparties that conduct business primarily throughout North America. In addition to the Utility's concentration of credit risk due to receivables from residential and small commercial customers in northern California, the Utility has a net regional concentration of credit exposure totaling $134 million to counterpartie
s that conduct business primarily throughout North America.

RESULTS OF OPERATIONS

The following table shows for the three months and nine months ended September 30, 2002, and 2001, certain items from the accompanying Consolidated Statements of Income detailed by Utility and PG&E NEG operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for those items.) The information for PG&E Corporation (the "Total" column) includes the appropriate intercompany eliminations. Results of operations are discussed following this table.

PG&E National Energy Group

------------------------------------------------------------------

(in millions)

Utility

Total

PG&E

NEG

Integrated

Energy &

Marketing

Interstate

Pipeline

Operations

PG&E

NEG

Elimi-

nations

PG&E

Corpora-

tion &

Other

Elimi-

nations⁽³⁾

Total

-------------

------------

----------------

--------------

------------

--------------

------------

Three months ended September 30, 2002

Operating revenues ⁽¹⁾

$

2,949

$

1,087

$

1,030

$

62

$

(5)

$

(18)

$

4,018

Operating expenses

1,890

1,137

1,114

26

(3)

(14)

3,013

-------------

------------

----------------

--------------

------------

--------------

------------

Operating income (loss)

1,059

(50)

(84)

36

(2)

(4)

1,005

========

=======

==========

========

=======

========

Interest income

45

Interest expense

(434)

Other income (expenses), net

64

Income before income taxes

680

Income taxes

214

Income from continuing operations

466

Net income

466

Net cash provided by operating activities

672

Net cash used by investing activities

(834)

Net cash used by financing activities

(453)

EBITDA ⁽²⁾

1,368

5

(49)

53

1

61

1,434

Three months ended September 30, 2001

Operating revenues ⁽¹⁾

2,937

782

733

57

(8)

-

3,719

Operating expenses

1,509

646

626

28

(8)

12

2,167

-------------

------------

----------------

--------------

------------

--------------

------------

Operating income (loss)

1,428

136

107

29

-

(12)

1,552

========

=========

==========

========

=======

========

Interest income

61

Interest expense

(317)

Other income (expenses), net

(38)

Income before income taxes

1,258

Income taxes

487

Income from continuing operations

771

Net income

771

Net cash provided by operating activities

1,922

Net cash used by investing activities

(836)

Net cash provided by financing activities

60

EBITDA ⁽²⁾

1,639

177

132

42

3

(32)

1,784

Nine months ended September 30, 2002

Operating revenues ⁽¹⁾

8,116

2,438

2,277

175

(14)

(74)

10,480

Operating expenses

4,750

2,707

2,633

77

(3)

(62)

7,395

-------------

------------

----------------

--------------

------------

--------------

------------

Operating income (loss)

3,366

(269)

(356)

98

(11)

(12)

3,085

========

=========

==========

========

=======

========

Interest income

130

Interest expense

(1,129)

Other income (expenses), net

61

Income before income taxes

2,147

Income taxes

771

Income from continuing operations

1,376

Net income

1,315

Net cash provided by operating activities

1,066

Net cash used by investing activities

(2,089)

Net cash provided by financing activities

87

EBITDA ⁽²⁾

4,222

(128)

(263)

143

(8)

73

4,167

Nine months ended September 30, 2001

Operating revenues ⁽¹⁾

7,808

2,224

2,042

186

(4)

(147)

9,885

Operating expenses

6,464

1,878

1,801

80

(3)

(116)

8,226

-------------

------------

----------------

--------------

------------

--------------

------------

Operating income (loss)

1,344

346

241

106

(1)

(31)

1,659

========

=========

==========

========

=======

========

Interest income

170

Interest expense

(876)

Other income (expenses), net

(43)

Income before income taxes

910

Income taxes

340

Income from continuing operations

570

Net income

570

Net cash provided by operating activities

4,774

Net cash used by investing activities

(2,053)

Net cash provided by financing activities

349

EBITDA ⁽²⁾

$

1,976

$

468

$

324

$

141

$

3

$

(44)

$

2,400

⁽¹⁾

Operating revenues and operating expenses for the three months ended September 30, 2002, reflect the adoption of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. Amounts for trading activities for the comparative periods in 2001 have been reclassified to conform with the new net presentation.

⁽²⁾

EBITDA is defined as income before provision for income taxes, interest expense, interest income, depreciation, and amortization. EBITDA is not intended to represent cash flows from operations and should not be considered as an alternative to net income or as an indicator of PG&E Corporation's operating performance, or to represent cash flows as a measure of liquidity. Refer to the Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E Corporation believes that EBITDA is a standard measure commonly reported and widely used by analysts, investors, and other interested parties. However, EBITDA as presented herein may not be comparable to similarly titled measures reported by other companies.

⁽³⁾

All inter-segment transactions are eliminated.

PG&E Corporation - Consolidated

Overall Results

PG&E Corporation's consolidated results of operations continue to be impacted by California's electric industry and the Utility's Chapter 11 filing. See the "Liquidity and Financial Resources" section of this MD&A and Note 2 of the Notes to the Consolidated Financial Statements for more information. In addition, results of operations for the Utility and PG&E NEG are discussed below.

PG&E Corporation's net income for the three months ended September 30, 2002, was $466 million, compared to net income of $771 million for the same period in 2001, representing a decrease of $305 million. The Utility accounted for $217 million of this decrease. PG&E Corporation's net income for the nine months ended September 30, 2002, was $1,315 million, compared to net income of $570 million for the same period in 2001, representing an increase of $745 million. Substantially all of this change was attributable to the Utility. PG&E Corporation and the Utility expect future earnings to continue to reflect increased volatility as a result of no longer being able to reflect the impact of generation-related regulatory balancing accounts in their financial statements, since these amounts cannot be deemed probable of recovery. As such, these amounts are accounted for as expenses and now directly impact net income.

The changes in performance for the three and nine months ended September 30, 2002, and 2001, are generally attributable to the following factors:

In the third quarter of 2002, PG&E Corporation recorded write-offs of unamortized loan fees and discount of $83 million and $70 million relating to the Tranche A note prepayment and Tranche B new waiver extension, respectively. Additionally, PG&E Corporation reversed $38 million of unamortized loan discounts representing the value of unvested PG&E NEG options associated with the prepayment of the Tranche A note.

In the third quarter of 2002, PG&E Corporation recorded other income of $71 million as a result of the change in the market value of the 3 percent vested portion of the PG&E NEG warrants previously issued in connection with the PG&E Corporation March 1, 2001, Credit Agreement (Old Credit Agreement).

The Utility's electric operating revenues decreased $26 million for the three months ended September 30, 2002, compared to the same period in 2001, primarily due to increases of $81 million and $78 million in the amount of direct access credits (see discussion of direct access credits under Utility Electric Operations below) and revenues passed through to the DWR, respectively. For the nine months ended September 30, 2002, the Utility's electric operating revenues increased $1.2 billion compared to the same period in 2001, due to both an increase in the amount of electricity generated and procured by the Utility and an increase in CPUC-authorized generating related surcharge revenues.

The Utility's cost of electric energy increased $121 million for the three months ended September 30, 2002, compared to the same period in 2001, primarily due to an increase in the quantity of electricity purchased from QFs.

The Utility's cost of electric energy decreased by $1.5 billion for the nine months ended September 30, 2002, compared to the same period in the prior year, primarily due to a lower average cost of electric energy purchased and a net reduction to cost of electric energy of $595 million resulting from a CPUC decision adopting a revenue requirement for the DWR's electricity costs for the two-year period ended December 31, 2002, and a FERC decision requiring the DWR to pay for ISO electricity costs previously invoiced by the ISO to the Utility. See Note 2 of the Notes to the Consolidated Financial Statements for more information. Offsetting these impacts were 2001 amounts recorded that reduced the Utility's previously accrued ISO related purchased power cost, and reversed previously expensed purchased power costs for terminated bilateral contracts, with no similar transactions in 2002.

The Utility's gas operating revenues for the three months ended September 30, 2002, increased $38 million, compared to the same period in 2001, primarily due to a net increase in overall gas consumption by customers. The Utility's gas operating revenues for the nine months ended September 30, 2002, decreased $881 million, as compared to the same period in 2001, primarily due to a lower average cost of gas in 2002, which was passed on to customers through gas revenues.

The Utility's cost of gas for the three months ended September 30, 2002, decreased $144 million, as compared to the same period in 2001, mainly due to losses resulting from the involuntary termination of gas transportation hedges. The Utility's cost of gas for the nine months ended September 30, 2002, decreased $976 million, as compared to the same period in 2001, mainly due to a lower average cost of gas in 2002.

The Utility's operating and maintenance expense for the three and nine months ended September 30, 2002, increased $297 million and $498 million, respectively, compared to the same periods in 2001, primarily resulting from regulatory balancing account activity related to the deferral of both the half-cent surcharge revenues beginning June 1, 2002, and the electric revenues associated with rate reduction bond financing cost savings returned to ratepayers. Offsetting these deferrals was electric transmission related costs deferred through a reduction of operating and maintenance expense for the shortfall of revenues needed to recover these costs. See the Utility's Operating and Maintenance expense section of this MD&A for further discussion.

The Utility's 2002 results include an accrual of $303 million for electricity that has been provided by the DWR to the Utility's customers as a result of the DWR's proposed amendment to the CPUC's May 16, 2002, servicing order, requesting changes to the calculation of the amount that the Utility is required to pass through to the DWR for electricity provided to the Utility's customers. See Note 2 of the Notes to the Consolidated Financial Statements for more information.

The Utility's depreciation, amortization, and decommissioning increased $91 million and $217 million respectively, for the three and nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to the amortization of the rate reduction bond regulatory asset.

PG&E NEG's net loss for the three months ended September 30, 2002, was $18 million, compared to net income of $77 million for same period in 2001, a decrease of $95 million. The 2002 results include the following on a pre-tax basis: a write-off of goodwill of $95 million, an impairment charge of $30 million for dispersed generation equipment and a restructuring accrual of $19 million. Offsetting these decreases were the effect of a change in the mark-to-market methodology of $11 million and an increase in tax benefits related to synthetic fuel investment tax credits of $43 million.

PG&E NEG's net loss for the nine months ended September 30, 2002, was $222 million, compared to net income of $202 million for the same period in 2001, a decrease of $424 million. The 2002 results include a net loss for the following on a pre-tax basis: the cumulative effect of a change in accounting principle of $103 million, impairments and write-offs of long-term prepayments and related capitalized development costs of $265 million, an impairment charge for dispersed generation equipment of $30 million, a restructuring accrual of $19 million, and a goodwill write-off of $95 million. Offsetting these decreases were the effect of a change in the mark-to-market methodology of $11 million and an increase in tax benefits related to synthetic fuel investment tax credits of $43 million. The decrease in PG&E NEG net income was also the result of lower gross margins and higher operating and maintenance costs due to the timing of major overhauls on generating facilities. In addition, higher deprecia
tion expenses were incurred due to plants that either were acquired or began operations in 2001.

PG&E NEG's operating revenues increased $305 million and $214 million for the three and nine months ended September 30, 2002, respectively, due to settled volume increases and new generating plants coming on line.

PG&E NEG's operating expenses increased $301 million and $372 million for the three and nine months ended September 30, 2002, due to the increased costs of commodity sales and fuel resulting from the operation of new generation plants noted above.

Dividends

No dividends were declared in 2002 or 2001. The New Credit Agreement described under "Liquidity and Financial Resources" above prohibits PG&E Corporation from declaring or paying dividends until the term loans have been repaid.

Utility

Overall Results

The Utility's income available for common stock was $520 million for the three months ended September 30, 2002, compared to $737 million for the three months ended September 30, 2001. The decrease in net income was primarily due to increases in operating and maintenance and depreciation, amortization, and decommissioning expenses, offset by a decrease in the cost of gas.

The Utility's income available for common stock was $1.6 billion for the nine months ended September 30, 2002, compared to $433 million for the nine months ended September 30, 2001. The increase in net income was primarily due to an increase in electric revenues and a decrease in the cost of electric energy, offset by increases in operating and maintenance, depreciation, amortization, and decommissioning, and interest expenses.

Electric Operations

Electric Revenues

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

Three months ended

Nine months ended

September 30,

September 30,

---------------------------

--------------------------

(in millions)

2002

2001

2002

2001

-----------

-----------

-----------

-----------

Residential

$

1,046

$

987

$

2,805

$

2,529

Commercial

1,468

1,426

3,464

2,993

Industrial

448

509

1,075

1,140

Agricultural

222

235

443

416

------------

------------

------------

------------

  Total electric revenue

3,184

3,157

7,787

7,078

Direct access credits

(95)

(14)

(207)

(368)

DWR pass-through revenue

(718)

(640)

(1,461)

(1,793)

Miscellaneous

112

6

335

348

------------

------------

------------

------------

  Total electric operating revenues

$

2,483

$

2,509

$

6,454

$

5,265

=======

=======

=======

=======

Electric revenues for the three months ended September 30, 2002, decreased by $26 million from the three months ended September 30, 2001. This variance was primarily due to increases of $81 million and $78 million in the amount of the direct access credits and revenues passed through to the DWR, respectively.

In accordance with CPUC regulations, the Utility provides an energy credit to those customers (known as direct access customers) who have chosen to buy their electric generation energy from an Energy Service Provider (ESP) other than the Utility (See discussion of Direct Access Credits in the "Regulatory Matters" section of this MD&A). The Utility bills direct access customers based upon fully bundled rates (generation, distribution, transmission, public purpose programs, and a competition transition charge). However, direct access customers receive an energy credit equal to the per kWh average generation price multiplied by customer energy usage for the period.

The variance in direct access credits is due to both an increase in the total gigawatt-hours (GWh) provided to direct access customers by ESPs and an increase in the average generation price. During the three months ended September 30, 2002, ESPs provided approximately 2,128 GWh to the Utility's direct access customers at an average per kWh price of $0.045, compared to 465 GWh provided during the three months ended September 30, 2001, at an average per kWh price of $0.030.

The amount recorded as DWR pass-through revenues in the three months ended September 30, 2002, increased in comparison to the same period in the prior year due to an adjustment recorded in the third quarter of 2002 to reflect the changes proposed by the DWR to the CPUC's May 16, 2002, servicing order (see Note 2 of the Notes to the Consolidated Financial Statements), offset by an increase in the amount of electricity generated and procured by the Utility and a resulting decrease in the Utility's net open position (the amount of power needed by retail electric customers that cannot be met by Utility-owned generation or power under contract to the Utility). Since January 2001, the DWR has been responsible for procuring electricity required to cover the Utility's net open position. The Utility acts as a collection agent for electricity provided by the DWR to the Utility's customers and pays the DWR based on a CPUC-approved per kWh power charge. Therefore, the Utility does not reflect revenues collected on
behalf of the DWR or the related costs in its Consolidated Statements of Income. See "Electricity Purchases" under Note 2 of the Notes to the Consolidated Financial Statements.

Electric revenues for the nine months ended September 30, 2002, increased by $1.2 billion from the nine months ended September 30, 2001. The variance between the two periods was affected significantly by three factors.

First, the amount of CPUC-authorized generation-related surcharges increased by $812 million for the nine months ended September 30, 2002, compared to the same period in the prior year. This increase is attributable primarily to the fact that a $0.03 surcharge, effective June 2001, was collected over the entire nine-month period ended September 30, 2002, whereas it was in effect for only four months during the nine-month period ended September 30, 2001.

Second, the amount of pass-through revenues for electricity procured by the DWR to cover the Utility's net open position decreased by $332 million for the nine months ended September 30, 2002, compared to the same period in the prior year. See the discussion of DWR pass-through revenues above. The variance is primarily due to a decrease in the Utility's net open position created by an increase in power supplied by ESPs to direct access customers and an increase in the power purchased from QFs due to renegotiated payment terms through the Utility's bankruptcy proceeding. DWR pass-through revenues for the nine months ended September 30, 2002, also were impacted by an additional amount accrued in the third quarter of 2002 to reflect changes proposed by the DWR to the CPUC's May 16, 2002, servicing order, as discussed above.

Finally, there was $161 million less in direct access credits for the nine months ended September 30, 2002, in comparison to the same period in 2001. The decrease was due to a decrease in the average per kWh generation price offset by an increase in the total GWh provided to direct access customers by ESPs. Because of lower market prices for electric energy, the average direct access credit in the nine months ended September 30, 2002, was $0.035 per kWh compared to an average credit of $0.175 per kWh in the nine months ended September 30, 2001. During the nine months ended September 30, 2002, ESPs provided approximately 5,933 GWh to the Utility's direct access customers, compared to 2,108 GWh provided in the nine months ended September 30, 2001.

Cost of Electric Energy

The following table shows the components of the Utility's cost of electric energy:

Three months ended

September 30,

Nine months ended

September 30,

--------------------------------

-------------------------------

(in millions)

2002

2001

2002

2001

-------------

-------------

-------------

-------------

Cost of electric energy purchased

$

529

$

405

$

1,415

$

3,132

Fuel used in own generation

26

29

74

70

Adjustment to purchased power accruals

-

-

(595)

(261)

Market value of terminated bilateral contracts

-

-

-

(552)

-------------

--------------

--------------

-------------

Total cost of electric energy

$

555

$

434

$

894

$

2,389

========

========

========

========

Average cost of electric energy purchased per kWh

$

0.082

$

0.080

$

0.076

$

0.185

Total electric energy purchased (GWh)

6,486

5,061

18,624

16,942

The cost of electric energy for the three months ended September 30, 2002, increased by $121 million, as compared to the three months ended September 30, 2001. This increase was due primarily to an increase in the quantity of electricity purchased from QFs in the third quarter of 2002 compared to the same period in 2001.

The cost of electric energy for the nine months ended September 30, 2002, decreased by $1.5 billion, compared to the nine months ended September 30, 2001. The significant variance between the two periods is attributable to several factors.

First, the Utility's average cost per kWh of electric energy purchased decreased to $0.076 per kWh over the nine months ended September 30, 2002, from $0.185 per kWh for the same period in 2001. The more favorable price was due primarily to significantly higher prices for electricity prior to the stabilization of the energy market in the second half of 2001. Also reducing the average cost of electric energy in 2002 was the fact that the Utility purchased more electricity from QFs, other generators, and irrigation districts, which were lower-cost sources of power than market alternatives. In addition, the DWR purchased all amounts related to imbalance energy (energy purchased on the market at spot rates) needed to service the Utility's customers in 2002, whereas in 2001 the Utility was purchasing imbalance energy through the PX through the first half of January. As previously discussed, the Utility serves as a collection agent for the DWR and does not reflect the DWR's cost of electricity on its Consol
idated Statements of Income.

Second, in March 2002, the CPUC approved a decision adopting a revenue requirement for the DWR's electricity costs for the two-year period ended December 31, 2002, and the FERC upheld its previous decisions requiring the DWR to pay for ISO electricity costs previously invoiced by the ISO to the Utility. As a result of the FERC and CPUC decisions, the Utility recorded a net reduction to cost of electric energy of $595 million (pre-tax). See Note 2 of the Notes to the Consolidated Financial Statements for further discussion of the FERC and CPUC decisions and the resulting adjustment to amounts accrued as payable to the ISO and the DWR.

Finally, offsetting these impacts were amounts recorded during 2001 that (1) reduced the Utility's previously accrued ISO-related purchased power costs, and (2) offset previously expensed purchased power costs related to the market value of terminated bilateral contracts. There were no similar events in 2002.

Gas Operations

Gas Revenues

For the three months ended September 30, 2002, gas revenues increased by $38 million due primarily to an increase in overall gas consumption by the Utility's customers, offset by a slightly lower average sales price. The average bundled sales price for gas sold during the three months ended September 30, 2002, was $10.54 per thousand cubic feet (Mcf), compared to $10.63 per Mcf for the same period in 2001. The cost of gas is passed through directly to gas customers.

For the nine months ended September 30, 2002, gas revenues decreased by $881 million primarily due to a lower average cost of gas, which was passed on to customers and refunded in gas revenues. The average bundled sales price for gas sold during the nine months ended September 30, 2002, was $7.80 per Mcf, compared to $12.45 per Mcf for the same period in 2001.

Cost of Gas

For the three months ended September 30, 2002, the Utility's cost of gas decreased by $144 million compared to the same period in 2001 due mainly to losses recognized during the three months ended September 30, 2001, associated with the involuntary termination of gas transportation hedges caused by a decline in the Utility's credit rating.

For the nine months ended September 30, 2002, the Utility's cost of gas decreased by $976 million compared to the same period in the prior year due principally to a decrease in the average unit cost of gas to $2.97 per Mcf from $7.15 per Mcf for the same period in 2002.

Other Operating Expenses

Operating and Maintenance

For the three-month period ended September 30, 2002, the Utility's operating and maintenance expenses increased by $297 million compared to the same period in the prior year. The increase is due primarily to regulatory balancing account activity related to (1) the deferral of half-cent surcharge revenues beginning June 1, 2002 (see the discussion of the One-Cent and Three-Cent Surcharge revenues in the "Regulatory Matters" section of the MD&A), (2) the deferral of electric revenues associated with rate reduction bond financing cost savings returned to ratepayers, and (3) a net reduction of deferred electric transmission-related costs compared to 2001. 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. (Electric transmission-related costs are included in the cost of electric energy and consist primarily of scheduling coordinator costs and reliability must r
un charges from the ISO.)

For the nine-month period ended September 30, 2002, the Utility's operating and maintenance expenses increased by $498 million compared to the same period in the prior year. The increase is primarily due to regulatory balancing account activity related to (1) the deferral of half-cent surcharge revenues beginning June 1, 2002 (see the discussion of the One-Cent and Three-Cent Surcharge Revenues in the "Regulatory Matters" section of the MD&A), (2) the deferral of electric revenues associated with the rate reduction bond financing cost savings returned to ratepayers, and (3) a net reduction of deferred electric transmission related costs compared to 2001 (see the discussion of electric transmission-related costs above). Operating and maintenance costs were also higher in 2002 due to an increase in employee benefit plan-related expenses and increased spending on public purpose programs, customer-related costs, and other administrative and general costs.

Depreciation, Amortization, and Decommissioning

Depreciation, amortization, and decommissioning increased by $91 million and $217 million for the three and nine months ended September 30, 2002, respectively, from the same periods in 2001. The increase was due mainly to amortization of the rate reduction bond regulatory asset, which began in January 2002, and totaled $93 million and $206 million in the three and nine months ended September 30, 2002. The rate reduction bond regulatory asset is discussed further in the "Regulatory Matters" section of this MD&A.

Interest Income

In accordance with the American Institute of Certified Public Accountants' SOP 90-7, the Utility has reported reorganization interest income separately on the Consolidated Statements of Income. Interest income decreased by $21 million and $36 million, respectively, for the three and nine months ended September 30, 2002, compared to the same periods in 2001. The decrease in interest income in 2002 was due to lower average interest rates and the liquidation of short-term investments in order to make payments pursuant to a Bankruptcy Court order in settlement of certain obligations classified as Liabilities Subject to Compromise. See the discussion of Liabilities Subject to Compromise in Note 2 of the Notes to the Consolidated Financial Statements.

Interest Expense

For the three months ended September 30, 2002, the Utility's interest expense decreased by $24 million compared to the same period in 2001 primarily due to lower interest rates on debt and the maturity of mortgage bonds. Also, the Utility made payments during the second and third quarters of 2002 pursuant to a Bankruptcy Court order in settlement of certain obligations classified as Liabilities Subject to Compromise. These payments reduced the average level of unpaid debts accruing interest over the three months ended September 30, 2002.

For the nine months ended September 30, 2002, the Utility's interest expense increased by $64 million compared to the same period in the prior year due to the Utility's bankruptcy proceeding beginning in the second quarter of 2001, which resulted in an increased average level of unpaid debts accruing interest. See the discussion of interest rates in Note 2 of the Notes to the Consolidated Financial Statements.

Reorganization Fees and Expenses

In accordance with SOP 90-7, the Utility has reported reorganization fees and expenses separately on the Consolidated Statements of Income. Such costs include primarily professional fees for services in connection with Chapter 11 proceedings.

PG&E NEG

Overall Results

PG&E NEG's net loss was $18 million for the three months ended September 30, 2002, a decrease of $95 million from the three months ended September 30, 2001. PG&E NEG's pre-tax operating income decreased $186 million for the three months ended September 30, 2002, compared to the same period in 2001. Gross margins improved slightly during the third quarter of 2002 compared to 2001, but PG&E NEG took various one-time charges to pre-tax operating income that more than offset gross margin improvements. As of September 30, 2002, PG&E NEG had recorded, within the PG&E NEG Integrated Energy and Marketing segment, approximately $95 million of net goodwill on its balance sheet. Based upon significant adverse changes within the national energy markets, PG&E NEG tested, within the third quarter of 2002, for possible impairment of goodwill balances, and determined that the book value of PG&E NEG's Integrated Energy and Marketing segment was greater than the fair value. As such,
PG&E NEG determined that the $95 million net goodwill balance was not supportable and should be charged to earnings in the current period. Also, during the third quarter, based on the changes in national energy markets and specifically the markets in which PG&E NEG Dispersed Generation assets operate, PG&E NEG assessed the probability of utilizing various Dispersed Generation assets (including turbines, generators, transformers, metering equipment, etc.) for expansion. PG&E NEG measured the estimated capital investment necessary for expansion against the future estimated cash flows to be generated. It was determined that such investments would be uneconomical and that PG&E NEG cannot characterize these expansion projects as probable. The book value of this equipment was approximately $46 million at September 30, 2002. Based on recent market quotes and expected net salvage values, PG&E NEG has recorded an impairment charge of approximately $30 million in the third quarter of 200
2. Both the impairment of goodwill and impairment of Dispersed Generation assets are included in the impairments and write-offs line item on PG&E NEG's Consolidated Statements of Operations in the three months and nine months ended September 30, 2002. In addition, in the third quarter of 2002, PG&E NEG initiated a program to reduce future administrative, general, and operating costs. This cost reduction program created one-time charges to operating income of approximately $18 million of employee termination cost as well as costs associated with various office closures. Interest income was less for the three months ended September 30, 2002, compared to the prior year primarily due to decreased cash balances on hand. PG&E NEG's tax benefits for the three months ended September 30, 2002, were based on reduced income levels as compared to the same period last year and on certain energy tax credits. In addition, in the quarter ended September 30, 2002, PG&E Corporation re-evaluated its positi
on with respect to the expected realization of certain synthetic fuel tax credits and, as a result, PG&E NEG recorded additional tax benefits totaling $43 million.

PG&E NEG's net loss (after the cumulative effect of a change in accounting principle) was $222 million for the nine months ended September 30, 2002, a decrease of $424 million from the nine months ended September 30, 2001. The nine months ended September 30, 2002, included a net loss for the cumulative effect of a change in accounting principle of $61 million. The cumulative effect was based on PG&E NEG's adoption, as of April 1, 2002, of interpretations issued by the Derivatives Implementation Group (DIG), DIG C15 and DIG C16, reflecting a mark-to-market value of certain contracts that previously had been accounted for under the accrual basis as normal purchases and sales. PG&E NEG's pre-tax operating income decreased $615 million mainly due to impairments and write-offs of long-term turbine prepayments and related capitalized development costs of $265 million, goodwill write-offs of $95 million, and impairment of PG&E NEG's Dispersed Generation assets of $30 million. Also contributin
g to the decline in pre-tax operating income were higher operations and maintenance costs and higher depreciation due to the start-up of new plants. Interest expense was higher due primarily to PG&E NEG $1 billion Senior Notes which were issued late in the second quarter of 2001. Interest income was less for the nine months ended September 30, 2002, compared to the prior year due primarily to decreased cash balances on hand. PG&E NEG's tax benefits for the nine months ended September 30, 2002, were based on reduced income levels as compared to the same period last year and on certain energy tax credits. In addition, in the quarter ended September 30, 2002, PG&E Corporation re-evaluated its position with respect to the expected realization of certain synthetic fuel tax credits and as a result, PG&E NEG recorded additional tax benefits totaling $43 million.
Operating Revenues

PG&E NEG's operating revenues were $1.1 billion in the three months ended September 30, 2002, an increase of $305 million from the three months ended September 30, 2001. This increase occurred principally in the Integrated Energy and Marketing Activities segment, with a slight increase in revenue from Interstate Pipeline Operations. The principal drivers in this increase were in PG&E NEG's asset generation business providing wholesale energy revenues as a result of settled volume increases compared to the prior year and new generation plants coming on line, as well as increased tolling revenues in PG&E NEG's energy trading operations. Settled volume increases were somewhat offset by declines in commodity prices and continued compressed spark spreads through the third quarter of 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues increased $5 million due to additional revenue collected as a result of a negotiated contract t
ermination settlements.
PG&E NEG's operating revenues were $2.4 billion in the nine months ended September 30, 2002, an increase of $214 million from the nine months ended September 30, 2001. These occurred primarily in the Integrated Energy and Marketing Activities segment. The principal drivers in this increase were in PG&E NEG's asset generation business providing wholesale energy revenues as a result of settled volumes increases compared to the prior year and new generation plants coming on line, as well as increased tolling revenues in PG&E NEG's energy trading operations. Settled volume increases were somewhat offset by declines in commodity prices and continued compressed spark spreads through the third quarter of 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues declined $11 million due to weak pricing fundamentals on gas transportation to the California and Pacific Northwest gas markets compared to the same period last year, partially offset b
y contract termination settlements in the third quarter of 2002.
Operating Expenses

PG&E NEG's operating expenses were $1.1 billion in the three-month period ended September 30, 2002, an increase of $491 million from the same period in the prior year. These increases occurred primarily in the Integrated Energy and Marketing segment. The cost of commodity sales and fuel increased $301 million in line with the increases in operating revenues, compressed spark spreads, and new generation plants coming on line within the wholesale energy business. Administrative and general costs increased in the third quarter of 2002 as compared to the same period last year due principally to PG&E NEG's one-time charges associated with employee termination costs and office closures. Impairments and write-offs were $125 million in the third quarter of 2002, with no comparable charges in 2001, for goodwill write-offs of $95 million and impairment of PG&E NEG's Dispersed Generation assets of $30 million. Operations, maintenance, and management costs increased $25 million and deprecia
tion and amortization costs increased $6 million in the third quarter of 2002 as compared to the same period last year due principally to the operations of new plants coming on line.

PG&E NEG's operating expenses were $2.7 billion in the nine-month period ended September 30, 2002, an increase of $829 million from the same period in the prior year. These increases occurred primarily in the Integrated Energy and Marketing segment. The cost of commodity sales and fuel increased $372 million in line with the increases in operating revenues, compressed spark spreads, and new generation plants coming on line within the wholesale energy business. Included in operating expenses is approximately $390 million of impairment charge relative to previously capitalized turbine pre-payments and related capitalized development cost of $265 million in the second quarter of 2002, goodwill write-offs of $95 million in the third quarter of 2002, and impairment of PG&E NEG's Dispersed generation assets of $30 million in the third quarter of 2002. Operations, maintenance, and management costs increased $60 million in 2002 as compared to the same period last year due principal
ly to new plants coming on line. In addition, depreciation and amortization costs increased $20 million in the period also due mainly to new plants coming on line. Administrative and general costs increased in the third quarter of 2002 as compared to the same period last year due to one-time charges associated with the PG&E NEG cost reduction program which were offset on a year-to-date basis by lower costs in the first half of 2002 associated with lower employee-related expense.

REGULATORY MATTERS

A significant portion of PG&E Corporation's operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, PG&E Corporation's revenues and pricing for its regulated services.

The Utility is the only subsidiary with significant regulatory proceedings or issues at this time. The Utility's significant regulatory proceedings and issues are discussed below. Regulatory proceedings associated with electric industry restructuring are discussed further in Note 2 of the Notes to the Consolidated Financial Statements.

DWR Rate Agreement and Revenue Requirement

In January 2001, the California Legislature and the Governor of California authorized the DWR to begin purchasing wholesale electric energy on behalf of the Utility's retail customers. On February 1, 2001, the Governor signed into law AB 1X authorizing the DWR to purchase power to meet the Utility's net open position (the amount of power needed by retail electric customers that cannot be met by Utility-owned generation or power under contract to the Utility) and to issue revenue bonds to finance electricity purchases. The DWR purchased energy on the spot market until it was able to enter into contracts for the supply of electricity. In addition to certain contracts that it has subsequently entered into, the DWR continues to purchase power on the spot market at prevailing market prices.

On February 21, 2002, the CPUC approved a decision adopting rates for the DWR and allowing the DWR to collect power charges and financing charges from ratepayers to recover the $19 billion needed by the DWR to procure electricity for the customers of the California IOUs for the two-year period ended December 31, 2002. These funds needed by the DWR will be financed partially through a DWR bond issuance (see "DWR Bond Charges Allocation Proceeding" below) and partially through the DWR's total statewide revenue requirement that is allocated among the Utility and the other California IOUs. Accordingly, the CPUC established a total statewide revenue requirement of $9.0 billion for the DWR's power charges for the two-year period ended December 31, 2002, and allocated $4.5 billion to the Utility's customers. The February 21, 2002, CPUC decision noted that the DWR had been found by the FERC to be responsible for ISO imbalance energy purchases (energy obtained from the market) for 2001, and authorized
the DWR to collect revenues from the Utility's customers sufficient to reimburse the DWR for these costs. On March 21, 2002, the CPUC modified its February 21, 2002, revenue requirement decision, effectively lowering the amount allocated to the Utility's retail customers to $4.4 billion for the two-year period ended December 31, 2002.

On October 8, 2002, the DWR filed a proposed amendment to the CPUC's May 16, 2002, servicing order requesting changes to the calculation that determines the amount that the Utility is required to pass-through to the DWR for electricity provided by the DWR for the Utility's customers. This proposed amendment more specifically defines the methodology used to calculate payments by the Utility to the DWR. It also specifies that the Utility should use the more specific methodology to true up previous payments of revenues passed through the DWR as well as future payments. Under its statutory authority, the DWR may request the CPUC to order the California IOUs to implement amendments to the servicing orders and arrangements that the DWR has with the IOUs, and the CPUC has approved such amendments in the past without significant change. Based on the DWR's proposed amendment, during the third quarter of 2002, the Utility accrued an additional $303 million (pre-tax) liability for pass-through revenues for elect
ricity provided by the DWR to the Utility's customers through September 30, 2002.

On May 10, 2002, the Sacramento Superior Court ruled that the DWR must hold a public hearing before determining that its power purchases are "just and reasonable" under the law that gave it authority to buy electricity. The court also ruled that the result is subject to judicial review, and that the hearings must occur before the CPUC agrees to add the DWR's power expenses to rates. However, the court stated that the revenue requirements covering the DWR's power costs for 2001-2002 approved by the CPUC would not be revoked pending completion of required public proceedings.

The CPUC's February 21, 2002, DWR revenue requirement decision, as modified by the March 21, 2002, decision, requires the DWR to submit true-ups of differences between forecast and actual data contained in its 2001-2002 revenue requirement when it submits its 2003 revenue requirement.

In August 2002, the DWR determined that its 2001, 2002, and 2003 statewide revenue requirements were "just and reasonable" as required by AB 1X, and filed with the CPUC its 2003 statewide revenue requirement that totaled $5.8 billion ($4.7 billion in power charge-related costs and $1.1 billion in bond-related costs.) This represents a decrease of 14.2 percent for power charges only from its 2002 revenue requirement. The DWR's 2003 revenue requirement filing includes adjustments for shortfalls between the amounts collected from the IOUs and the 2001-2002 revenue requirement to be considered separately from its 2003 revenue requirement. The DWR revised its previously approved forecast of $9.045 billion for its 2001-2002 revenue requirement upward by $47 million. This increase reflects actual costs through March 2002 and projected costs for the remainder of 2002.

Before the DWR filed its 2003 statewide revenue requirement and its updated 2001-2002 revenue requirement with the CPUC in August, 2002, the Utility had filed comments with the DWR alleging that major portions of the DWR's revenue requirements were not "just and reasonable" as required by AB 1X. The comments also alleged that the DWR was not complying with the procedural requirements of AB 1X in making its determination. On August 26, 2002, the Utility filed with the DWR a motion for reconsideration of the DWR's determination that its revenue requirements were "just and reasonable." The DWR denied the Utility's motion on October 8, 2002. On October 17, 2002, the Utility filed a lawsuit in a California court asking the court to find that the DWR's revenue requirements had not been demonstrated to be "just and reasonable" and lawful, and that the DWR had violated the procedural requirements of AB 1X in making its determination. The Utility asked that the court order the DWR's revenue requirement determ
ination be withdrawn as invalid, and that the DWR be precluded from imposing its revenue requirements on the Utility and the Utility's customers until it has complied with the law. No schedule has yet been set for consideration of the lawsuit.

On September 9, 2002, the CPUC issued a ruling scheduling a proceeding to determine how the DWR's 2003 power charge-related revenue requirement of $4.7 billion for the DWR's power contracts should be allocated to the California IOUs for payment to the DWR in 2003. The proceeding is also to consider a revision or true up for the revenue requirements remitted to the DWR for the period January 17, 2001, through December 31, 2002. In a related decision on September 19, 2002, the CPUC ordered that the DWR contract power variable costs are to be remitted to the DWR based on the allocation of the DWR contracts assigned to the IOUs by that decision. In the proceeding, the parties' proposed allocation methodologies result in a power charge revenue requirement allocation for the Utility of between $1.8 billion and $2.2 billion. Hearings in the 2003 DWR power charge revenue requirement proceeding were held in early October 2002, and a final decision is expected to be issued by the end of 2002.

The DWR's 2003 expenditures are based on a number of projections regarding power supplies, natural gas prices, off-system power sales, the cost of ancillary services, demand-side management and conservation, and administrative and general expenses. A key assumption in the determination of its 2003 revenue requirement is that the DWR no longer will be responsible for purchasing the IOU's residual net short energy requirements. The residual net short energy requirement is the difference between (1) the IOU's customer's energy demands, and (2) the energy provided by the IOU's retained generation assets and contracted power, and the energy supplied through the DWR's long-term power contracts. The DWR's 2003 revenue requirement is based solely on its long-term power contracts and their administration. Prior to 2003, the DWR has been responsible for procuring the IOUs' entire net short requirements (the difference between the total IOU energy requirements and the supply of energy from resources owned, operat
ed, or contracted by the IOUs) using a combination of long-term energy contracts and short-term energy purchases.

The DWR identified a number of uncertainties that may require material changes to its 2003 revenue requirement. These uncertainties include assumptions regarding direct access participation, the DWR's role in the procurement of the California IOUs net short requirements (including residual net short requirements), developments with its bond financing, and potential changes in California's electricity market design proposed by the ISO.

DWR/ISO Balancing Account

The CPUC's March 21, 2002, DWR revenue requirement decision determines, in part, cost recovery for non-energy charges paid by the DWR to the ISO on behalf of the IOUs' customers. These non-energy charges include grid management and scheduling coordinator charges associated with the transmission of retail electricity. The decision orders that these costs be included in the retained generation revenue requirements. In this decision, the CPUC authorized the Utility to establish the DWR/ISO balancing account to record those post-2001 costs that are paid to the ISO or to the DWR for these non-energy ISO-related costs. The March 21, 2002, decision did not provide any recovery for 2001 costs. Recovery of amounts recorded in the balancing account would be determined in a future proceeding.

Payments totaling $40 million were made by the Utility through September 2002 for 2002 costs previously accrued during the year. Given that specific recovery of these costs has not been provided, the Utility could not conclude that the balancing account is probable of recovery and has fully reserved the amount. Amounts recorded in the balancing account should have no earnings impact, since the balancing account is fully reserved.

DWR Bond Charges Allocation Proceeding

As previously mentioned, funds needed by the DWR to procure electricity for the California IOUs will be financed partially through a DWR bond issuance. The February 21, 2002, CPUC decision allowing the Utility to collect financing charges from ratepayers provided for future recovery by the DWR of just and reasonable bond-related costs. The decision deferred the allocation among service territories or customer classes to future CPUC decisions. On June 6, 2002, a CPUC Commissioner issued a ruling scheduling a proceeding to determine how the DWR will recover bond-related costs through bond charges imposed on the California IOUs' customers. The proceeding will consider the amount of bond charges, how the bond charges will be allocated among the service territories and/or customer classes of the IOUs, rate design, and other issues necessary to levy bond charges in an amount sufficient to provide for the timely repayment of the DWR's bond-related costs. The ruling stated that the bond charge would be impos
ed based on the aggregate amount of electric power sold to customers in the IOUs' service territories, regardless of whether the power is sold by the DWR, the IOUs, or ESPs.

On October 24, 2002, the CPUC issued a decision adopting a bond charge for 2003 ranging from $0.0079 to $0.0107 per kWh. The final bond charge will be set after the bonds have been placed, and the DWR has communicated its 2003 bond-related revenue requirement to the CPUC. Additionally, the decision establishes a Bond-Charge Balancing Account to track over- and under-payments of bond charges, with subaccounts to track the payments and obligations by specific customer groups. The Utility expects to implement the bond charge on November 15, 2002.

The bonds will be used to repay the funds borrowed last year from the State's general fund to buy electricity during the California energy crisis. Bond-related charges include debt service, credit enhancement and liquidity facilities charges, and costs relating to other financial instruments and servicing arrangements entered into in connection with the bonds. Until the CPUC implements bottoms-up billing (billing for specific rate components) for the California IOUs, any bond charges will reduce the amount of revenue available to recover previously written-off under-collected purchase power costs and transition costs.

CPUC's Generation Procurement OIR

Under AB 1X, the DWR is not authorized to enter into new power purchase contracts or to purchase power on the spot market after January 1, 2003. In 2001, the CPUC opened a rulemaking proceeding to consider the ratemaking mechanisms that will apply to the California IOUs' power procurement costs incurred to meet the net open position to cover their customers' needs after January 1, 2003. Under current FERC tariffs, in order to purchase power through the ISO, the IOUs must meet the ISO's creditworthiness standards for third-party transactions, which require that the IOUs have an investment grade credit rating or meet certain collateral or prepayment requirements.

Interim Procurement Contracts

On August 22, 2002, the CPUC authorized the Utility to enter into transitional electricity procurement contracts before January 1, 2003, with the DWR as a co-party to cover the Utility's forecasted residual net open position, or a portion thereof, beginning January 1, 2003. All contracts must be pre-approved by the CPUC and the CPUC's decision puts in place a review framework designed to enable pre-approvals before the end of the year. So long as the DWR is the creditworthy purchaser, the DWR will retain legal and financial title to the electricity and recover costs associated with these interim procurement contracts directly from the Utility's customers under the AB1X framework with the Utility acting as billing and collection agent. However, the contracts provide that if the Utility regains investment grade status, all legal title and responsibility for these interim contracts from that point forward will pass from the DWR to the Utility.

This interim procurement authorization extends only to contracts entered into before January 1, 2003, although it allows multi-year procurement arrangements of up to five years in length. Under the authorization, the California IOUs are required to:

Obtain pre-approval of proposed contracts and hedging products from the CPUC;
Demonstrate, in the context of applying for that pre-approval, that the contracts are needed to meet the conservatively estimated peak period net open position; and
Demonstrate, in the context of applying for that pre-approval, that the conservative methodology for forecasting the peak-period net open position in the decision has been adhered to.

Although CPUC pre-approval of the contracts would constitute a determination that the costs incurred under the contracts are reasonable, the IOUs' administration of the contracts would remain subject to a reasonableness review by the CPUC. The Utility would be subject to a risk of disallowance for costs arising from its actions that are found to be unreasonable.

The Utility entered into several interim procurement contracts in October 2002 that would obligate the Utility and the DWR upon the occurrence of certain conditions. The Utility is not obligated under the contracts until the following conditions have been met:

The Utility has achieved an investment grade credit rating;
The CPUC has approved the contracts as just and reasonable for their entire term;
The Bankruptcy Court has approved the contracts; and
The DWR has agreed to be financially and legally obligated under the contracts until such time as the Utility is investment grade.

The terms of the interim procurement contracts range from one to three years commencing on or after January 1, 2003. The Utility estimates that the total costs to be incurred under the contracts will not exceed $42 million in 2003, $37 million in 2004, and $33 million in 2005. These amounts would be paid by the DWR until the Utility attains an investment grade credit rating and would be recovered as an addition to the DWR's revenue requirement. The DWR is not obligated to enter into the contracts, and therefore the Utility is unable to predict whether the Utility will be obligated under the contracts and whether the contracts will become effective prior to January 1, 2003, when the DWR's authority to enter such contracts expires. If the contracts do not go into effect, the residual net open requirements for the Utility to cover retail electric customers' load after January 1, 2003, would be higher.

Allocation of DWR Contracts

Consistent with applicable law, the Utility currently acts as a billing and collection agent pursuant to a servicing order adopted by the CPUC for the DWR's sales to the Utility's retail customers. The Utility does not take title to the DWR electricity or have any financial responsibility for the sale of DWR electricity.

As discussed above (see discussion in the Market Conditions and Business Environment section in this MD&A), SB 1976 requires the CPUC to allocate the existing DWR contracts among the three California IOUs. On September 19, 2002, the CPUC issued a decision that allocates the electricity subject to the DWR contracts among the three California IOUs. The power available under the contracts is to be dispatched in conjunction with the IOUs' existing resources on a least-cost basis.

The CPUC's allocation generally assigns to the Utility, for operating purposes, the quantities under contracts with specified delivery points north of the Path 15 transmission facilities. The CPUC has indicated this allocation will not be changed in the future.

The IOUs are required to assume all of the day-to-day scheduling, dispatch, and administrative functions for DWR contracts allocated to their customers by January 1, 2003. The variable costs of the contracts will be allocated to the IOU receiving physical allocation of the contract for operating purposes. Both variable and fixed costs of the contracts will be allocated among the IOUs for 2003 in a separate proceeding, the 2003 DWR revenue requirement case. The decision adopts least-cost dispatch as the general principle for dispatch of IOU power resources and the DWR allocated contracts in the IOU's combined portfolio, with surplus energy sales allocated pro rata between the DWR and the IOU resources based on their relative amounts of generation. The decision also orders the IOUs to negotiate operating agreements with the DWR for the allocated contracts and submit the operating agreements to the CPUC. The DWR will retain legal title and financial reporting and payment responsibility associated with th
ese contracts. The IOUs will, however, become responsible for scheduling and dispatch of the quantities subject to the allocated contracts and for many administrative functions associated with those contracts. The IOUs would continue to act as billing and collection agents for the DWR. Under AB 1X, the CPUC has no reasonableness review authority over the procurement prices in the DWR's contracts. However, under the CPUC decision, the CPUC would review annually the reasonableness of the IOUs' administration of the allocated DWR contracts, potentially including, how the IOUs elected to dispatch the DWR contracted-for power in their portfolios relative to other resources in their portfolios. While the IOUs would not bear the risk of being unable to fully pass-through the procurement costs associated with these contracts because they would be recoverable through the DWR's revenue requirement, the IOUs will be held to a reasonableness standard in their scheduling and dispatch decision-making and their admin
istration of the contracts. If the Utility's scheduling or dispatch decisions or its administration of these allocated contracts were found by the CPUC to be unreasonable in conjunction with the scheduling and dispatch of the Utility's retained generation, the Utility could bear the risk of not being able to fully recover its costs in the Utility's rates or otherwise be held responsible for its conduct. Because the Utility believes that it cannot be compelled to administer and bear the risks associated with the DWR's contracting, including the obligation to dispose of significant excess purchase obligations under those contracts, the Utility filed an application for rehearing of the decision with the CPUC on October 23, 2002, challenging the decision as violating SB 1976 and other federal and state laws. The Utility cannot predict whether the CPUC will alter this aspect of the decision or whether the CPUC's position ultimately will be determined to be unlawful.

The SB 1976 Regulatory Structure and the Utility's Bankruptcy Plan

On October 24, 2002, the CPUC issued a decision ordering the Utility to resume full procurement on January 1, 2003. The decision requires the Utility to submit modifications to its short-term procurement plan to the CPUC by November 12, 2002, and submit its long-term procurement plan by April 1, 2003. After the CPUC adopts the Utility's proposed procurement plan, SB 1976 mandates that the Utility resume procurement within 60 days. The Utility's bankruptcy plan of reorganization provides that the Utility will not be obligated to accept any assignment of electricity procurement contracts executed by the DWR. It also provides that the Utility will not be obligated to assume responsibility for its net open position, including any portion that might not be satisfied under the DWR contracts, unless certain conditions are satisfied, including (1) the Utility's receipt of an investment grade credit rating, (2) the existence of an objective retail rate recovery mechanism pursuant to which the Utility will
be able to fully recover in a timely manner its wholesale power procurement costs, and (3) the existence of objective standards regarding pre-approval of procurement transactions. The creation of an objective retail rate recovery mechanism and the adoption of objective standards regarding pre-approval of procurement transactions are each within the control of the CPUC. The Utility is evaluating the CPUC decision in light of the conditions of the Utility Plan. The Utility cannot predict at this time what steps it may or may not need to take regarding implementation of its modified short-term procurement plan and resumption of full procurement under the CPUC decision.

The DWR has publicly stated that it intends to seek to transfer full legal title and responsibility for the DWR electricity contracts to the California IOUs as soon as possible. While the Utility believes nothing in SB 1976 or in current CPUC decisions or state law supports the DWR's authority to cause such a transfer of legal title, without the consent of the Utility, the Utility cannot predict whether either the DWR or the CPUC will seek to compel transfer of the DWR contracts to the Utility without its consent in the future. The Utility has informed the CPUC, the DWR, and the State that it would vigorously oppose any attempt to transfer the DWR contracts without its consent.

The CPUC decision implementing SB 1976 contemplates that the Utility will reassume procurement responsibility for the net open position by January 1, 2003, regardless of whether the Utility Plan is effective, the Utility has regained investment grade status, or the other conditions to the Utility's resumption of the net open position set forth in the Plan have been satisfied. The CPUC decision recognizes that Bankruptcy Court approval may be required in order for the Utility to resume procurement of the net open position and directs the Utility to seek such authority immediately. The power available under the existing DWR contracts allocated to the Utility's customers and the power available under any interim contracts that the Utility may enter into using the DWR's credit would reduce the Utility's residual net open position. The Utility currently expects its residual net open position for 2003 to be immaterial. However, resumption of procurement responsibility for the residual net open position on J
anuary 1, 2003, or at any time when the Utility Plan conditions have not been satisfied could expose the Utility to the following burdens and risks:

If the Utility is not permitted to recover procurement costs in a timely manner, the Utility's cash flow would be adversely affected.

The CPUC has authorized a conservative estimate of the Utility's post-January 1, 2003, residual peak-period net open position for purposes of determining its interim procurement authority using DWR credit. If this estimate is too low, the power that the Utility contracts for under that arrangement will be insufficient to meet its actual residual peak demand after January 1, 2003.

If spot or forward prices for electricity materially increase, the magnitude of the costs exposed to regulatory-determined recovery will increase.

Finally, if the Utility must resume procurement responsibility for the residual net open position before regaining an investment grade credit rating, the ISO would, and energy trading counterparties may, require the Utility to post collateral or make cash prepayments, which would affect the Utility's cash flow.

Retained Generation Revenue Requirement

On April 4, 2002, the CPUC issued a decision establishing the Utility's utility retained generation (URG) revenue requirement for 2002. The decision adopted a cost-based 2002 generation revenue requirement for the Utility of $2.9 billion, subject to adjustment to reflect actual recorded regulatory costs (based on recorded December 31, 2000, net regulatory value). In accordance with the decision, on April 24, 2002, the Utility filed an advice letter with the CPUC updating the adopted revenue requirement to reflect the net regulatory value of generation assets as of December 31, 2000. The CPUC approved the advice letter, effective June 3, 2002. As a result of this update, the Utility's 2002 generation revenue requirement increased by $106 million, to a total of $3 billion.

The April 4, 2002, decision allows the Utility to recover reasonable costs for retained generation incurred in 2002, subject to reasonableness review in the Utility's 2003 General Rate Case (GRC) proceeding. The decision does not change retail electric rates and the Utility does not expect it to have a current earnings impact. Instead, the decision defers consideration of future rate changes until such time as the CPUC addresses the status of the retail rate freeze. The CPUC also noted in its decision that recovery of the Utility's past unrecovered generation-related costs remains an open issue but that it will not be addressed in this phase of the rate stabilization proceeding. In addition, the April 4, 2002, decision stated that the Utility's 2003 URG revenue requirement will be considered in the Utility's 2003 GRC proceeding. (See "2003 GRC" below.)

Divestiture of Retained Generation Facilities

In January 2001, the California Legislature passed AB 6X, which amended Public Utilities Code (PUC) Section 377 to prohibit utilities from divesting their retained generating plants before January 1, 2006. AB 6X did not amend PUC Section 367, which requires the CPUC to market value the generating assets of each utility by no later than December 31, 2001, based on appraisal, sale, or other divestiture. However, on December 21, 2001, a CPUC Commissioner issued a ruling requesting comments on the impact of AB 6X on the valuation obligation and indicating that, in her opinion, AB 6X supersedes PUC Section 367 to delete any requirement of market valuation for utility generation assets. On January 15, 2002, the Utility filed comments reiterating the reasons contained in previous pleadings as to why the enactment of AB 6X did not supersede or repeal the CPUC's statutory obligation to market value the Utility's generation assets by December 31, 2001. The CPUC has not yet issued a decision on this matter.<
/P>

On January 17, 2002, the Utility filed an administrative claim with the State of California Victim Compensation and Government Claims Board (Board) alleging that the January 2001 enactment of AB 6X violates the Utility's contractual rights under AB 1890. The Utility's claim seeks compensation for the denial of the Utility's right to at least $4.1 billion market value of its retained generating facilities in FERC-regulated interstate power markets. On March 7, 2002, the Board formally denied the Utility's claim. Having exhausted administrative remedies before the Board, the Utility filed on September 6, 2002, a complaint against the State in Sacramento Superior Court alleging a claim for breach of contract arising out of the enactment of AB 6X.

The Utility cannot predict what the outcome of any of these proceedings will be or whether they will have a material adverse effect on its results of operations or financial condition.

Direct Access Suspension OIR

Until September 20, 2001, California's restructured electricity market gave customers the option of subscribing either to ''bundled service'' from the Utility or to "direct access" service from an ESP. Customers receiving bundled services receive distribution, transmission, and generation services from the Utility. Direct access customers receive distribution and transmission service from the Utility, but purchase electricity (generation) from their ESP. On September 20, 2001, the CPUC, pursuant to AB 1X, suspended the right of retail end-use customers to acquire direct access service, thereby preventing additional customers from entering into contracts to purchase electricity from ESPs. The decision did not address agreements entered into before September 20, 2001, including renewals of such contracts or agreements, and stated that such issues would be addressed in a subsequent decision.

In the subsequent decision issued on March 21, 2002, the CPUC decided to allow all customers with direct access contracts entered into on or before September 20, 2001, to remain on direct access. However, the CPUC proposed to assess an exit fee, or non-bypassable charge, on those direct access customers to avoid a shift of costs from direct access customers to bundled service customers. On March 29, 2002, an Administrative Law Judge (ALJ) issued a ruling finding that, in addition to the DWR's costs, the Utility's energy procurement and generation costs would be considered in determining the exit fees.

On November 7, 2002, the CPUC issued a final decision establishing a Direct Access Cost Responsibility Surcharge (CRS) mechanism to implement utility-specified non-bypassable surcharges on direct access customers for their share of the bond costs and power costs incurred by the DWR and above-market cost related to the Utility's own generation resources and power contracts. The decision establishes four components comprising the CRS:

DWR Bond Charge - This charge is applicable to all direct access customers except customers who were on direct access before the DWR began purchasing power and have continued to remain on direct access since the DWR began purchasing power (continuous direct access customers). The actual amount of this charge on direct access customers is being determined in the Bond Charge Allocation Proceeding.
DWR Power Charge for September 21, 2001, through December 31, 2002 Period. This charge is applicable to direct access customers who previously took bundled service at any time on or after February 1, 2001. Determination of whether a direct access customer took bundled service on or after February 1, 2001, will be made by reference to the Utility's customer billing records and not the date a direct access customer executed a procurement contract with a third party. The charge is designed to recover direct access customers' share of DWR's procurement costs between September 21, 2001, and December 31, 2002. Since bundled customers have already paid this amount to DWR, these charges collected from direct access customers would be credited to bundled customers as a reductions to their future bills. The actual charge will be determined according to an analysis of direct access migration during the July 1, 2001, to September 20, 2001, period and will be consistent with CPUC approved inter-utility allocatio
ns.
DWR Power Charge for Future DWR Costs - This charge is applicable to direct access customers who previously took bundled service at any time on or after February 1, 2001. This charge is designed to recover direct access customers' share of the uneconomic portion of the DWR's procurement costs for 2003 and thereafter. The actual charge will be determined according to an analysis of direct access migration during the July 1, 2001, to September 20, 2001, period and will be consistent with CPUC approved inter-utility allocations. This charge will be adjusted on an annual basis or more frequently if the DWR's revenue requirement is adjusted more frequently.
Utility Procurement and Generation Charge - This charge is applicable to all direct access customers regardless of the date on which a customer switched to direct access. This charge is designed to recover direct access customers' share of the ongoing uneconomic portion of utility-related generation and procurement costs. This charge will be based on an estimate of above-market costs for our procurement contracts and qualified facility arrangements, that is in turn based on a 4.3 cents per kWh benchmark for 2003. This benchmark for determining above-market costs will be updated annually.

The decision imposes a cap on the CRS mechanism of 2.7 cents per kWh. The CPUC has indicated that it will establish an expedited review schedule to determine whether the cap should be adjusted and has set a goal of reaching a decision on whether this cap should be adjusted, and whether trigger mechanisms for adjusting the cap would be established, by July 1, 2003.
Funds remitted under the CRS mechanism cap will be applied first to the DWR bond charges, second to the DWR power charges, and third to the Utility's ongoing procurement and generation costs. Direct access customers who have returned to bundled service will be responsible for their share of the unrecovered costs resulting from the CRS cap. To the extent the cap results in an under-collection of DWR charges, the shortfall would have to be remitted to DWR from bundled customers' funds. Interest on under-collections will be assessed at the DWR's bond interest rate on an interim basis while the CPUC examines a long-term plan for financing the CRS cap.

The Utility cannot predict whether the CPUC's implementation of this decision or the level of the CRS cap will have a material adverse effect on its results of operations or financial condition.

Direct Access Credits

When the direct access credit was established, direct access customers paid the full bundled rate less a credit based on the market price of electricity. Under this methodology, when the market price exceeded the bundled rates, the direct access customer received a bill credit. As a result, during the energy crisis, direct access customers did not contribute to the Utility's transition cost recovery nor did they pay for transmission and distribution services. Under the interim direct access credit methodology in place since the market ceased operations in January 2001, the Utility has calculated the market price using an estimate of its cost of service for its retained generation and the Utility's generation component of the frozen rate for energy provided by the DWR.

Currently, direct access customers pay the one-cent surcharge but are exempt from the three-cent surcharge. In May 2001, the Utility also requested authorization to charge direct access customers for the three-cent surcharge. One party filed a protest indicating that direct access customers should not pay the three-cent surcharge, nor pay the one-cent surcharge beginning June 1, 2001. The one-cent surcharge generates approximately $80 million in revenues per year from direct access customers. The CPUC has not yet ruled on this issue. It is unclear how or whether direct access customers would be reimbursed if the CPUC rules that direct access customers should not pay this charge.

On May 31, 2002, the Utility filed its proposal for calculating the post-market direct access credit that would continue allowing direct access customers to receive a credit for generation-related costs avoided as a result of their self-procurement. Specifically, the Utility proposes that the credit be based on avoided procurement costs. The Utility proposed to use the Dow Jones Daily Index as a proxy for the short-term market price paid by the DWR. On a going-forward basis, the credit would be limited to the generation charge component of the Utility's total bundled rate, including surcharges, less any non-bypassable direct access charges. On September 13, 2002, the Utility revised its testimony to eliminate the use of the Dow Jones Daily Index as a proxy for the market price. The Utility also proposed to move to bottoms-up billing (billing for specific rate components) for direct access customers as quickly as possible. Consequently, direct access customers would pay at least the same non-procurem
ent charges that are applicable to bundled customers.

The Utility proposes to adjust the direct access credit retroactively from December 28, 2000, to January 18, 2001, using the market price actually billed, adjusted for any price mitigation that may be approved by the FERC. In a preliminary indication with regard to drafting the proposed decision, the ALJ said that he expected to grant the move to bottoms-up billing but deny the Utility's proposal for past billing adjustments.

One-Cent and Three-Cent Surcharge Revenues

On January 4, 2001, the CPUC allowed the Utility to establish an interim energy procurement surcharge of $0.010 per kWh, to remain in effect for 90 days from the effective date of the decision. On March 27, 2001, the CPUC authorized the Utility to add an average of $0.030 per kWh surcharge to its current rates and made the January $0.010 per kWh surcharge permanent. The March 27, 2001, order directed the Utility to apply these new rates solely to power costs incurred after the decision date and to reflect the new three-cent surcharges in customers' bills beginning in June 2001. For each month that the combined revenues from both surcharges exceed procurement costs, the Utility records a regulatory liability for such excess. At September 30, 2002, the total amount of the regulatory liability was approximately $75 million.

In May 2001, the CPUC authorized an "incremental system average surcharge of $0.0052 per kWh" (or 0.52 cents) for a 12-month period beginning June 1, 2001, to recover revenues not collected between March 27, 2001, when the three-cent surcharge was approved, and June 1, 2001, when the Utility began collecting the three-cent surcharge. This "half-cent surcharge" had been projected to end May 31, 2002.

In an advice letter dated April 15, 2002, the Utility proposed to eliminate the half-cent surcharge in accordance with the May 2001 decision, and to calculate new surcharges for each rate schedule by reducing each surcharge on an equal percentage basis. On June 6, 2002, the CPUC instead issued a resolution ordering the Utility to continue collecting the half-cent surcharge and to record the surcharge in balancing account beginning June 1, 2002 until further consideration by the CPUC. The Utility has excluded this surcharge from earnings and has recorded a regulatory liability for the surcharge of approximately $147 million at September 30, 2002. The Utility will continue to record a regulatory liability for these surcharges until further CPUC action.

On November 7, 2002, the CPUC voted to approve a decision lifting restrictions on the use of revenues generated by the one- cent and three-cent surcharges on retail electric rates authorized in January and March 2001, respectively. Although a final written decision is not yet available, the draft decision that the CPUC voted out amends the previous decisions in order to authorize the Utility to use the surcharge revenues not only for ongoing procurement costs, but also for the purpose of securing or restoring its reasonable financial health, as the CPUC determines to be necessary in other proceedings, such as proceedings relating to ratemaking for the CPUC proposed plan of reorganization in the Utility's bankruptcy proceeding, or relating to the determination by the CPUC of the end of the AB 1890 rate freeze and the disposition of under-collected costs remaining at the end of the rate freeze. The draft decision specifically cites recovery of the Utility's remaining transition costs as a potential use of
the surcharge revenues, and states that AB 1890 does not preclude recovery of such costs after the rate freeze, since the Utility's retained generation-related costs are no longer uneconomic within the meaning of the restrictions in AB 1890 on the recovery of such costs. The draft decision also clarifies that the use of the surcharge revenues for ongoing procurement costs is intended to be only for those ongoing procurement costs that exceed the revenues available for the recovery of such costs and other operating costs during the term of the AB 1890 rate freeze, which the draft decision states ended no later than March 31, 2002. Based on this draft decision, it is possible that subsequent decisions by the CPUC may affect the amount and timing of the "headroom" revenues recovered by the Utility through the CPUC surcharge decisions, and it is possible that a portion of "headroom" revenues recovered by the Utility during the period between June 2001 and March 31, 2002, the latest possible end date for the A
B 1890 rate freeze, may be subject to refund to the extent not offset by costs authorized by the CPUC for recovery during the rate freeze or otherwise recoverable under other law, such as pursuant to the Utility's Rate Recovery Litigation. If such refunds are ordered, they could have a material adverse impact on the Utility's earnings.

The use of surcharge revenues also could be affected by the outcome of a court proceeding involving a settlement between SCE and the CPUC. On January 11, 2002, in the court proceeding, the CPUC represented to the court that it has the authority to allow the Utility and SCE to recover their under-collected purchased power and transition costs beyond the end of the AB 1890 rate freeze. The settlement reached by the CPUC and SCE stipulated that SCE would maintain rates at their current levels (beyond the end of the AB 1890 rate freeze) until the earlier of the date that SCE recovered its previously incurred transition costs or December 31, 2003. To the extent SCE's costs are not recovered by December 31, 2003, they are to be amortized and recovered over a period ending December 31, 2005. Several parties have challenged the SCE/CPUC settlement, arguing that the settlement violates the rate freeze provisions of AB 1890 prohibiting post-freeze recovery of transition costs. On September 23, 2002, the U.S. C
ourt of Appeals for the Ninth Circuit (Ninth Circuit) issued an opinion questioning whether the settlement violated AB 1890 and whether the CPUC had the ability to consent to the settlement. The Ninth Circuit has certified the state law issues for review by the California Supreme Court. The Utility cannot predict the outcome of this matter.

1999 GRC

The CPUC authorizes an amount known as "base revenues" to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, currently are authorized by the CPUC in GRC proceedings.

The 1999 GRC Decision, issued on February 17, 2000, ordered the CPUC's Energy Division to contract with a consultant to assess the contribution of the Utility's 1999 electric and gas distribution capital additions to system reliability, capacity, and adequacy of service. The CPUC's consultants began the assessment in February 2002 and issued a final report on November 8, 2002. The final report concludes that "in general the [Utility's] 1999 overall capital expenditure program appears quite acceptable." The final report offers recommendations to improve the Utility's distribution capital investment process, but recommends no adjustments to the Utility's distribution rate base.

The CPUC issued a rehearing decision in October 2001 that, among other matters, orders the record in the 1999 GRC to be reopened to receive evidence of the actual level of 1998 electric distribution capital spending in relation to the forecast used to determine 1999 rates. This possibly could result in an adjustment of the adopted 1998 capital spending forecast level to conform to the 1998 recorded level.

Following the 1998 capital spending rehearing and resolution of all other outstanding matters, a final result of operations analysis will be performed, and a final revenue requirement will be determined. The rehearing decision apparently intends for the revised revenue requirement to be made retroactive to January 1, 1999. The Utility does not expect a material impact on its financial position or results of operations from the remaining proceedings.

On October 1, 2002, the CPUC issued a draft decision further modifying the 1999 GRC decision that would adopt a $10.6 million downward annual adjustment to supervision costs in customer records and collection expenses. In comments filed on October 21, 2002, the Utility maintained that the reduction should be effective only prospectively, not retroactively to January 1999. The CPUC is expected to issue the final decision in the fourth quarter of 2002.

2003 GRC

In the 2003 GRC, the CPUC will determine the amount of authorized base revenues to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations for the period 2003 through 2005. These base revenue requirements are determined based on a forecast of costs for 2003 (the test year).

On November 8, 2002, the Utility filed its 2003 GRC application. The Utility's application requests an increase in electric and gas distribution revenue requirements of $447 million and $105 million, respectively, over the current authorized amounts to maintain current service levels to existing customers, and to adjust for wages and inflation. The Utility also has indicated that it will seek an attrition rate adjustment (ARA) increase for 2004 and 2005. The ARA mechanism is designed to avoid a reduction in earnings in years between GRCs to reflect increases in rate base and expenses.

The Utility's requested 2003 electric distribution revenue requirement increase would not increase overall bundled electric rates over their current authorized level. The Utility is seeking an increase in a typical residential customer's total gas bill of approximately 2.6 percent or $0.99 per month.

Additionally, as directed by the CPUC in its 2002 URG proceeding, the Utility submitted testimony supporting the costs of operating the Utility's generation facilities and fuel and purchased power costs. The Utility's GRC application requests an increase of approximately $61 million or over the interim 2002 URG revenue requirement authorized by the CPUC. On October 25, 2002, the CPUC issued a decision ordering the Utility to resume the procurement function on January 1, 2003. That decision also directed the Utility to amend its GRC application to remove certain generated-related fuel and purchased power costs from its GRC and instead to include them in another CPUC proceeding. In its GRC, the Utility forecast a decrease in these costs in 2003. This decrease offset the forecast increase in costs to operate the Utility's generation facilities. Removing the fuel and purchase power from the generation-related revenue requirement set forth in the GRC would result in an increase in the forecast generation
- -related revenue requirement of approximately $80 million to $90 million.

On June 6, 2002, the CPUC issued a decision adopting a goal of having the Utility's 2003 GRC processed by June 1, 2003, but not precluding the Utility from requesting an interim relief mechanism for its 2003 GRC.

On August 27, 2002, the Utility filed a motion with the CPUC requesting that the revenue requirement that the CPUC determines in the Utility's 2003 GRC be effective January 1, 2003, even though the CPUC will not issue a final decision on the 2003 GRC until sometime after that date. The CPUC has not acted on that request.

The Utility cannot predict what amount of revenue requirements, if any, the CPUC will authorize for the 2003 through 2005 period, nor when such decision will be made.

2002 ARA Request

In light of the postponement of a 2002 GRC, on November 9, 2001, the Utility informed the CPUC of its need for a 2002 ARA to allow for recovery of newer capital investments and escalating costs of providing electric and gas distribution services. On January 17, 2002, the Utility requested an interim decision to ensure that whatever ARA adjustment was ultimately approved would be effective as early in 2002 as possible.

On April 22, 2002, the CPUC issued a decision authorizing the Utility's request for interim relief. The decision sets the effective date of interim relief at either the effective date of the interim decision, or such later date as may be determined by the CPUC. The decision provides the Utility with the opportunity to present arguments regarding which interim relief date should be adopted when it submits substantive arguments for adoption to its 2002 ARA request. On June 11, 2002, the Utility filed its 2002 ARA application. In its application, the Utility requests an annual increase of $76.7 million to its electric distribution revenue requirement, and an annual increase of $19.5 million to its gas distribution revenue requirement. A prehearing conference was held on August 26, 2002, at which the parties agreed that no further testimony, hearings, or briefings were needed and that the matter could be submitted for decision. A final decision is expected during the fourth quarter of 2002 or the first
quarter of 2003.

Cost of Capital Proceedings

Each year, the Utility files an application with the CPUC to determine the authorized rate of return (ROR) that the Utility may earn on its electric and gas rate bases and include in rates. A previously authorized ROR remains in effect until a new ROR is approved. Since February 17, 2000, the Utility's adopted return on common equity (ROE) has been 11.22 percent on electric and gas distribution operations, resulting in an authorized 9.12 percent overall ROR. The Utility's earlier adopted ROE was 10.6 percent. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requested a ROE of 12.4 percent and an overall ROR of 9.75 percent. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22 percent ROE. A final CPUC decision is pending.

On May 8, 2002, the Utility filed an application with the CPUC to establish its authorized ROR for electric generation and distribution, operations and for gas distribution operations for 2003. The application requests a ROE of 12.5 percent and 12.25 percent for electric and gas operations, respectively. The application also requests an authorized ROR of 9.88 percent and 9.76 percent for electric and gas operations, respectively, based on then authorized rate bases.

On June 28, 2002, the CPUC issued a ruling requiring the Utility to file updated testimony on how its capital structure and rate of return would be impacted if the Alternative Plan for the Utility is approved by the Bankruptcy Court and implemented. On July 29, 2002, the Utility filed comments with the CPUC stating that under the expectations and assumptions described, the Utility's required rate of ROR base would be, at a minimum, nearly 20 percent. The expectations and assumptions assumed by the Utility if the Alternative Plan is implemented include not achieving an investment grade credit rating, unlawfully confiscating the Utility's equity return, not adequately addressing the risks associated with its net open exposure, and not addressing the issue of utility assumption of DWR contracts, among other issues. On September 11, 2002, the ALJ issued a ruling requiring the Utility to file comments on its ROR and capital structure under the CPUC's amended Plan of Reorganization. On September 18, 2002, t
he Utility filed comments stating that the CPUC's amended Plan of Reorganization did not provide sufficient financial information to change materially the Utility's analysis in its July 29, 2002, comments.

On November 7, 2002, the CPUC issued a final decision that retained the Utility's ROE at the current authorized level of 11.22 percent. This final decision also increased the Utility's authorized cost of debt to 7.57 percent from 7.26 percent, and held in place the current authorized capital structure of 48 percent common equity, 46.2 percent long-term debt, and 5.8 percent equity. The final decision also holds open the case to address the impact on the Utility's ROE, costs of debt and preferred stock, and ratemaking capital structure of the implementation and financing of a bankruptcy plan of reorganization. The Utility is required to file an advice letter within 30 days of completing any such financing to request authority to true up its test year 2003 ratemaking capital structure, long-term debt, and preferred stock cost, risks, and ROE.

Gas Accord II Application

Under a ratemaking pact called the Gas Accord, implemented in March 1998, the Utility's gas transmission and storage services were separated or unbundled from its distribution services, and the terms of service and rate structure for gas transportation were changed. The Gas Accord also allows core customers to purchase gas from competing suppliers, establishes an incentive mechanism whereby the Utility recovers its core procurement costs, and establishes gas transmission rates through 2002 and gas storage rates through March 2003. On October 9, 2001, the Utility filed an application with the CPUC, known as Gas Accord II, requesting a two-year extension, without modification to the terms and conditions of the existing Gas Accord. As part of this application requesting the two-year extension, the Utility proposed to maintain gas transmission and storage rates at current levels during the two-year extension period.

In August 2002, the CPUC approved a settlement agreement among the Utility and other parties that provided for a one-year extension of the Utility's existing gas transmission and storage rates and terms and conditions of service, as well as rules governing contract extensions and an open season for new contracts. The Gas Accord II settlement left open to subsequent litigation the issues raised in the application in so far as they relate to the second year of the two-year application.

In October 2002, the assigned CPUC ALJ issued a ruling that granted, in part, the Utility's motion to postpone the procedural schedule for litigation of the unresolved issues. The ALJ Ruling directed the Utility to file prepared testimony and a cost of service study by December 9, 2002, the other parties to file prepared testimony by January 27, 2003, and all parties to file rebuttal testimony by February 28, 2002, with evidentiary hearings set for March 10, 2003 through March 14, 2003.

The Utility cannot predict what the outcome of this litigation will be, or whether the outcome will have a material adverse effect on its results of operations or financial condition.

El Paso Capacity Decision

In May 2002, a FERC order directed El Paso Natural Gas Company (El Paso) to change the way it allocates space on its pipeline. El Paso's customers that are East of California had to decide by July 31, 2002, how much El Paso capacity rights they need in contract demand and how much capacity they would give up.

In July 2002, the CPUC issued a decision that required California IOUs to sign up for El Paso pipeline capacity given up by the shippers, and pre-approved such costs as just and reasonable. The IOUs were required to purchase a proportionate amount of the released capacity. The decision ordered that current capacity held by the IOUs on any interstate pipeline must be retained for the benefit of California ratepayers. Any capacity in excess of the IOU's need should be released under short-term capacity release arrangements. The decision also finds that to the extent the IOUs complied with the decision, they also shall receive full cost recovery for their costs associated with existing capacity contracts on all gas transmission pipelines.

In Phase II of this proceeding, the CPUC will address other issues that relate to these rules, including:

Cost allocation of El Paso capacity among the Utility's customers,

Short-term capacity releases, and

Details about the guaranteed rate recovery of the IOUs' costs for subscription to interstate pipeline capacity.

Since the July 2002 CPUC decision was issued, the Utility signed contracts for El Paso pipeline capacity rights totaling approximately $50.7 million beginning October 2002 and ending December 2007. The Utility has filed advice letters proposing to recover both pre-payments made to El Paso and ongoing capacity costs on the Transwestern Pipeline Company (Transwestern). Under the Gas Accord, the Utility could not recover any costs paid to Transwestern for gas pipeline capacity through 1997 and would have limited recovery during the period 1998 through 2002. Because of the El Paso decision, the Utility expects to fully recover its future purchases of gas pipeline capacity under the existing contract, resulting in additional revenues of approximately $90 million over the remaining contract period that began in July 2002 and ends in March 2007.

ORA and TURN filed protests arguing that the Utility acted "prematurely" in putting these pipeline capacity costs into rates and asked that they be backed out of rates until Phase II of the proceeding. In August 2002, the Utility filed a response to the protests with the CPUC. The Utility believes that immediate cost recovery in rates is appropriate based on the CPUC decision.

In September and October 2002, the CPUC issued two alternate draft resolutions that would delay the Utility's recovery of some of these costs. The first draft resolution would delay recovery of prepayments made to El Paso and ongoing capacity costs for the Transwestern pipeline. The alternate draft resolution would only delay the recovery of ongoing capacity costs for the Transwestern pipeline (and allow current recovery of pre-payments made to El Paso). The Utility does not expect the outcome of this matter to have a material adverse impact on its consolidated statement of income of financial position.

Rate Reduction Bonds

AB 1890 mandated a rate freeze and a 10 percent rate reduction for residential and small commercial customers. Under the original mandate, the Utility expected the 10 percent rate reduction to end the earlier of March 31, 2002, or when its transition costs were fully recovered.

To pay for the 10 percent rate reduction, the Utility financed $2.9 billion of its transition costs with the proceeds of rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. The transition costs financed by the bonds were deferred to the Rate Reduction Bond regulatory asset and are to be recovered in the future through separate non-bypassable charges mandated by AB 1890 called Fixed Transition Amount (FTA) charges. The Utility stopped deferring transition costs to the Rate Reduction Bond regulatory asset in the first quarter of 2002, when the financed transition costs in the regulatory asset equaled the remaining principal balance of the Rate Reduction Bonds. At this time, the Utility started amortizing the regulatory asset concurrent with the amortization of the Rate Reduction Bond principal. At September 30, 2002, the Rate Red
uction Bond regulatory asset amounted to $1,430 million. The Utility recorded net amortization expense of $206 million for the nine months ended September 30, 2002.

Annual Earnings Assessment Proceeding (AEAP)

The Utility administers general and low-income energy efficiency programs funded through a public goods component in customers' rates. The Utility has been authorized to receive incentives for successful past programs, including 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. Annually, the Utility files an earnings claim in the AEAP, a forum for stakeholders to comment on, and for the CPUC to verify, the Utility's claim. On March 21, 2002, the CPUC issued a decision that prospectively eliminated the opportunity for shareholder incentives in connection with the California IOUs' 2002 energy efficiency programs.

In May 2000 and 2001, the Utility filed its annual AEAP applications, which establish incentives for the prior program years that were to be collected during 2001 and 2002, respectively. The CPUC has combined the two proceedings and delayed action on them. The Utility's outstanding claim for shareholder incentives in this combined proceeding is approximately $80 million. The Utility has not included any earnings associated with incentives in its Consolidated Statements of Operations.

On May 1, 2002, the Utility filed its 2002 AEAP application requesting collection of a $25.6 million in program incentives. In its filing, the Utility proposed to increase its electric and gas distribution revenue requirements by $15.8 million and $3.3 million, respectively, and to recover $6.5 million from Electric Public Goods Charge funds. The electric distribution increase would be incorporated into rates established in the next Revenue Adjustment Proceeding (RAP). The gas distribution amount would be incorporated into rates established in the next gas transportation rate change, such as the Biennial Cost Allocation Proceeding.

On March 13, 2002, an ALJ for the CPUC requested comments on whether incentives adopted for pre-1998 energy efficiency programs should be reduced or eliminated. The CPUC has not yet ruled on the comments.

The Utility cannot predict what the outcome of these proceedings will be or whether the outcome will have a material adverse effect on its results of operations or financial condition.

Baseline Allowance Increase

On April 9, 2002, the CPUC issued a Phase 1 decision that required the Utility to increase baseline allowances for certain residential customers by May 1, 2002. An increase to a customer's baseline allotment increases the amount of their monthly usage that will be covered under the lowest possible rate and that is exempt from surcharges. The decision deferred consideration of corresponding rate changes until Phase 2 of the proceeding and ordered the IOUs to track the under-collections associated with their respective baseline quantity changes in an interest-bearing balancing account. The Utility estimates the Phase 1 annual revenue shortfall to be approximately $96 million for electric service, and $6 million for gas service. The total electric revenue shortfall recorded for the period May through August 2002 was $29 million.

Hearings for Phase 2 issues ended in September 2002. Phase 2 issues that may be resolved later in 2002 or early 2003 include items that could involve additional revenues at risk such as demographic revisions to baseline allowances, a special allowance for well water pumping, revisions to reflect vacation homes, and changes to baseline territories or seasons. The Utility generally opposed these proposals, and estimated additional Phase 2 annual revenue shortfalls if adopted of $79.6 million for electric service and $11 million for gas service, plus $11.6 million in administration costs spread out over three to five years.

The Utility proposed immediate recovery of base revenue shortfalls, but deferral of surcharge shortfalls to a future consolidated proceeding. The Utility cannot predict what the outcome of Phase 2 will be, nor can it conclude that recovery of the electric baseline related balancing account is probable. Therefore, the electric revenue shortfall will be charged to earnings and will reduce revenue available to recover previously written-off under-collected purchase power costs and transition costs.

Nuclear Decommissioning Cost Triennial Proceeding Application

On March 15, 2002, the Utility filed its 2002 Nuclear Decommissioning Cost Triennial Proceeding (NDCTP) application, seeking to increase its nuclear decommissioning revenue requirements for the years 2003 through 2005. The Utility seeks recovery of $24 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 seeks recovery of $7.3 million in CPUC-jurisdictional revenue requirements for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs, and escalation associated with that amount in 2004 and 2005. The Utility proposes continuing to collect the revenue requirement through a non-bypassable charge in electric rates, and to record the revenue requirement and the associated revenues in the Nuclear Decommissioning Adjustment Mechanism Balancing Account. Until post-rate freeze ratemaking is implemented, the increase in revenue requirements wou
ld reduce the amount of revenues available to offset electric generation costs. The CPUC held hearings on the application in September 2002 and is scheduled to issue a final decision in April 2003.

Revenue Adjustment Proceeding

The CPUC established the RAP to verify amounts recorded in the Utility's Transition Revenue Account (TRA) and to verify authorized revenue requirements, including adjustments approved in other proceedings. The RAP also establishes revenue allocation and rate design, and identifies all electric balancing and memorandum accounts for continued retention or elimination. The RAP consolidates the revenue requirements approved in other proceedings and sets the unbundled electric rate components.

In June 2001, the Utility filed its RAP application addressing revenues and costs recorded in the TRA from July 1, 1999, through April 30, 2001. As an interceding party, ORA urged the CPUC to disallow $40.2 million for these contracts. On October 3, 2002, the CPUC issued a decision verifying undisputed entries in the TRA and other specialized accounts. The decision disallowed $33,166 in special electric contracts during the period beginning July 1, 1999, through April 30, 2002.

FERC Transmission Rate Cases

Electric transmission revenues and both wholesale and retail transmission rates are subject to authorization by the FERC. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $391 million in electric transmission rates for the 14-month period of April 1, 1998, through May 31, 1999. During this period, somewhat higher rates were collected, subject to refund. A FERC order approving this settlement is expected by the end of 2002. The Utility has accrued $29 million for potential refunds related to the 14-month period ended May 31, 1999. In April 2000, the FERC approved a settlement that permits the Utility to recover $298 million in electric transmission rates retroactively for the 10-month period from May 31, 1999, to March 31, 2000.

In July 2001, the FERC approved a settlement that permits the Utility to collect $262 million annually in retail electric transmission rates beginning on May 6, 2001. The reduction in the level of retail transmission rates relative to previous time periods is due to unusually large balances paid to the Utility by the ISO for congestion management charges and other transmission-related services billed by the ISO that are recorded in the Transmission Revenue Balancing Account. These balances paid by the ISO are offset against the Utility's transmission revenue requirement and lower the amount collected from retail customers. The Utility does not expect the outcome of these settlements to have a material adverse effect on its results of operations or financial condition.

In March 2001, the Utility filed an application at the FERC to increase its power and transmission-related rates charged to the Western Area Power Administration (WAPA). The majority of the requested increase is related to passing through market power prices billed to the Utility by the ISO and others for services, which apply to WAPA under a pre-existing contract between the Utility and WAPA. On September 21, 2001, the FERC ALJ issued an Initial Decision denying the Utility the ability to increase the rates as requested. On October 24, 2001, the FERC confirmed the ALJ's Initial Decision in its entirety. The FERC denied the Utility's November 21, 2001, request for rehearing, and that decision has been appealed to the U.S. Court of Appeals for the D.C. Circuit. Pending a decision from the Court of Appeals, until December 31, 2004, the date the WAPA contract expires, WAPA's rates will continue to be calculated on a yearly basis pursuant to the formula specified in WAPA's contract. Any revenue shortfal
l or benefit resulting from this contract is included in rates through the end of the contract period as a purchased power cost. The difference between the Utility's cost to meet its obligations to WAPA and the revenues it receives from WAPA cannot be accurately estimated, since both the purchase price and the amount of energy that WAPA will need from the Utility through the end of the contract are uncertain.

Scheduling Coordinator Costs

In connection with electric industry restructuring, the ISO was established to provide operational control over most of the state's electric transmission facilities and to provide comparable open access for electric transmission service. The Utility serves as the scheduling coordinator to schedule transmission with the ISO to facilitate continuing service under existing wholesale transmission contracts that the Utility entered into before the ISO was established. The ISO bills the Utility for providing certain services associated with these contracts. These ISO charges are referred to as the "scheduling coordinator (SC) costs."

In April 1998, as part of the Utility's Transmission Owner rate case filed at the FERC, the Utility established the Transmission Revenue Balancing Account (TRBA) to record these SC costs and congestion costs in order to recover these costs through transmission rates. Certain transmission-related revenues collected by the ISO and paid to the Utility also were recorded in the TRBA.

In September 1999, an ALJ of the FERC issued a proposed decision denying recovery of these SC costs from retail and new wholesale customers in the TRBA. The ALJ indicated that the Utility should try to recover these costs from existing wholesale customers. On August 5, 2002, the FERC issued a final decision rejecting the Utility's proposal to pass these SC costs through to retail and new wholesale customers through the TRBA. On September 4, 2002, the Utility filed a request for rehearing at the FERC. On October 30, 2002, the FERC issued an order denying the request for rehearing of its August 5 order. In the absence of an order from FERC granting recovery of these costs in the TRBA, the Utility has made accounting entries to reflect the SC costs as accounts receivable under the Scheduling Coordinator Services (SCS) Tariff described below.

In January 2000, the FERC accepted a filing by the Utility to establish the SCS Tariff. The SCS Tariff was filed to serve as a back-up mechanism if the FERC ultimately decides that SC costs may not be recovered in the TRBA. The SCS Tariff would allow the Utility to pass through its SC costs to existing wholesale customers. The FERC conditionally granted the Utility's request that the SCS Tariff be effective retroactive to March 31, 1998. However, the FERC suspended the procedural schedule until the final decision is issued regarding the inclusion of SC costs in the TRBA. In September 2002, the Utility filed a notice with the FERC indicating its intent to request that the FERC resume the SCS Tariff proceeding if the request for rehearing of the August 5 order was not granted. For the period beginning April 1998 through September 30, 2002, the Utility transferred $102 million of scheduling coordinator costs from the TRBA to accounts receivable net of a $63 million reserve for potential uncollectible c
osts. The Utility also has disputed approximately $27 million of these costs as incorrectly billed by the ISO. Any refunds that ultimately may be made by the ISO would offset the accounts receivable.

The Utility does not expect the outcome of this proceeding to have a material adverse effect on its results of operations or financial condition.

FERC Prospective Price Mitigation Relief

The FERC issued a series of significant orders in the spring and summer of 2001 that prescribed prospective price mitigation relief for the extreme wholesale energy prices in 2000 and 2001. On April 26, 2001, the FERC issued an order that prescribed price mitigation for those hours in which the ISO declared an emergency. The order also imposed a requirement that effectively all generators in California offer available generation for sale to the ISO's real-time energy market during all hours. While the Utility recognized the importance of the FERC's action, it sought rehearing of the April 26, 2001, order on the premise that the price mitigation methodology could be made more comprehensive, both in terms of the hours in which it was to be applied and the types of transactions that it covered. The Utility also has sought rehearing of the FERC orders on price mitigation on the grounds that recent disclosure of fraudulent trading strategies by Enron Corp. and others that artificially raised market ene
rgy prices in California should be considered by the FERC to increase the amount of refunds owed or the time period for which refunds are due.

Starting July 12, 2002, the FERC modified the maximum market-price methodology for spot market sales in all hours from a variable formula-based cap to a fixed price cap of $91.87 per megawatt-hour (MWh). On September 27, 2002, the FERC issued an order granting the ISO's request for a limited extension of the current price mitigation methodology, including the fixed price cap of $91.87 per MWh, through October 30, 2002.

On July 17, 2002, the FERC further modified the prospective price mitigation for the wholesale spot markets throughout both California and the Western Electricity Coordinating Council (WECC, formerly known as Western Systems Coordinating Council). Features of this current methodology, effective October 31, 2002, include:

A bid cap of $250 per MWh;

The reaffirmation of the FERC's requirement that effectively all generators in California offer available generation for sale to the ISO's real-time energy market; and

Adoption of the ISO's Automatic Mitigation Procedures (AMP) using conduct, price and impact screens that will, when triggered, reduce bids to a reference price for each generator in California to be determined by an independent organization. The AMP will apply only to bids above the cap of $91.87 per MWh.

The FERC also directed the ISO to use to the extent possible Reliability Must Run (RMR) units to alleviate intra-zonal congestion. If sufficient RMR is not available, additional accepted bids would be subject to local market power mitigation through AMP, with the provision that a bit of the $91.87 taken for this purpose would not be subject to any mitigation.

The FERC also ordered the ISO to file its integrated day-ahead market proposal, ancillary service reforms, and hour-ahead and real-time reforms by October 21, 2002, for implementation by January 1, 2003. On September 20, 2002, the ISO requested an extension until October 1, 2003, for the implementation of an integrated day-ahead market. The FERC also placed a bid cap of negative $30.00 per MWh on decremental bids.

In June and July 2001, the FERC's chief ALJ conducted settlement negotiations among power sellers, the State, and the California IOUs in an attempt to resolve disputes regarding past power sales. The negotiations did not result in a settlement, but the judge recommended that the FERC conduct further hearings to determine possible refunds and what the power sellers and buyers are each owed. These hearings, in which the State is seeking up to $8.9 billion in refunds for electricity overcharges on behalf of buyers including the California IOUs, were concluded in October 2002. The Utility does not believe these matters will be resolved until early to mid-2003, nor can it predict whether a refund will be ordered or the amount the Utility might receive. A FERC decision is not expected before the first quarter of 2003.

An August 21, 2002, order from the U. S. Court of Appeals for the Ninth Circuit ordered the FERC to allow the California parties "to adduce additional evidence of market manipulation by various sellers." The Utility and other California parties have filed a request at the FERC for additional discovery and the opportunity to present evidence of market manipulation, including for periods before October 2, 2000, the current beginning of the refund period. This request is pending before the FERC and is expected to be acted upon in the near future.

ADDITIONAL SECURITY MEASURES

Since the September 11, 2001, terrorist attacks, PG&E Corporation and the Utility have been working to assess the need for physical security upgrades at critical facilities. Various federal regulatory agencies have issued orders requiring additional safeguards, including a May 2002 Nuclear Regulatory Commission (NRC) order requiring decommissioned nuclear facilities, such as the Utility's Humboldt Bay Power Plant, to implement interim security compensatory measures. Facilities affected by PG&E Corporation's and the Utility's assessments include generation facilities, transmission substations, and gas transmission facilities. The security upgrades will require additional capital investment and an increased level of operating costs. However, neither PG&E Corporation nor the Utility believes these costs will have a material impact on their consolidated financial position or results of operations.

CRITICAL ACCOUNTING POLICIES

Effective 2001, PG&E Corporation and the Utility adopted SFAS No. 133, "Accounting 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 financial instruments to be recognized in the financial statements at market value. See further discussion in "Quantitative and Qualitative Disclosure about Market Risk" above, and in Notes 1 and 6 of the Notes to the Consolidated Financial Statements. PG&E NEG accounts for its energy trading activities in accordance with EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10), and SFAS No. 133, which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. For the third quarter ended September 30, 2002, PG&E Corporation adopted the net method of recognizing energy trading contract
s in the income statement. Under the net method, revenues and expenses are netted and only the trading margin (or loss) is reflected in revenues.

PG&E Corporation also has derivative commodity contracts for the physical delivery of purchase and sale quantities 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 "New Accounting Policies" above.

PG&E Corporation and the Utility apply SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," to their regulated operations. This standard allows capitalizing of a cost that otherwise would be charged to expense if it is probable that the cost is recoverable through regulated rates. This standard also allows amounts to be recorded as liabilities for rate actions of a regulator that will result in amounts that are to be credited to customers through the ratemaking process. At September 30, 2002, the Utility reported regulatory assets of $2.0 billion and regulatory liabilities of $1.1 billion.

PG&E Corporation's and the Utility's regulated gas and electric revenues are recorded as services and provided based upon applicable tariffs and include amounts for services rendered but not yet billed.

PG&E Corporation's and the Utility's 2001 financial statements are presented in accordance with SOP 90-7, which is used for entities in reorganization under the Bankruptcy Code. As of September 30, 2002, PG&E Corporation and the Utility reported liabilities subject to compromise of $8.9 billion and $9.1 billion, respectively. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

PG&E Corporation and the Utility have recorded an environmental remediation liability associated with both owned and divested generation facilities, gas sites, and compressor stations. At September 30, 2002, this liability amounted to $330 million. See Note 7 of the Notes to the Consolidated Financial Statements for further discussion.

The Utility recognizes as income the current recovery of previously written-off under-collected purchased power and generation-related transition costs (also known as headroom). The amount of headroom recognized by the Utility can fluctuate materially due to many factors, including the outcome of regulatory proceedings and other regulatory actions, sales volatility, the impact of the end of the rate freeze period and post-rate freeze ratemaking, and the impact of the proceedings to determine the level of revenue requirements for the DWR's power procurement costs. For the nine months ended September 30, 2002, total headroom recorded was $1.3 billion (after-tax). See Note 2 of the Notes to the Consolidated Financial Statements and the overview of risk factors in this MD&A.

See Note 1 of the Notes to the Consolidated Financial Statements for further discussion of accounting polices and new accounting developments.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Rescission of EITF 98-10 - In October 2002, the EITF rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133 will continue to qualify for fair value accounting under SFAS No. 133. Contracts that had been marked to market under EITF 98-10 that do not meet the definition of a derivative will be recorded on a cost basis with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003.

The EITF also delayed the implementation (to January 1, 2003) of EITF 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk Management Activities,' and EITF 00-17, 'Measuring the Fair Value of Energy Related Contracts in Applying EITF 98-10'" (EITF 02-03). The official guidance related to EITF 02-03 will be outlined in the final minutes of the recent EITF meeting, scheduled for release in November of 2002.

The reporting requirements associated with the rescission of EITF 98-10 should be applied prospectively for all EITF 98-10 energy trading contracts entered into after October 24, 2002. For all EITF 98-10 energy trading contracts in existence at or prior to October 24, 2002, the effective date is the fiscal quarter beginning after December 15, 2002.

PG&E Corporation currently is assessing the impact of this ruling.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3. PG&E Corporation will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. 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 Issue No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related asset. PG&E Corporation currently is evaluating the impact of SFAS No. 143 on its Consolidated Financial Statements.

TAXATION MATTERS

The Internal Revenue Service (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 $69 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. 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, the IRS has proposed adjustments totaling $75 million (including interest). In addition, PG&E Corporation initiated discussions with the IRS regarding advance determination of a 2001 tax return position with respect to energy tax credits. Those discussions were not completed by the deadline for filing the 2001 tax return and the discussions were terminated. The resolution of these matters with the IRS is not expected to have
a material adverse effect on PG&E Corporation's earnings. 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. The results of these audits are not expected to have a material adverse effect on PG&E Corporation's earnings.

In the quarter ended September 30, 2002, PG&E Corporation re-evaluated its position with respect to the expected realization of certain synthetic fuel tax credits, and as a result recorded additional, tax benefits totaling $43 million.

ENVIRONMENTAL AND LEGAL MATTERS

PG&E Corporation and the Utility are subject to laws and regulations established both to maintain and to 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 7 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters and significant pending legal matters.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation's and Pacific Gas and Electric Company's (the Utility) primary market risk results from changes in energy prices and interest rates. PG&E Corporation engages in price risk management activities for both trading and non-trading purposes. Additionally, PG&E Corporation and the Utility may engage in trading and non-trading activities using forwards, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See Risk Management Activities, included in 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 the Utility's disclosure controls and procedures conducted on October 24, 2002 and October 21, 2002, respectively, PG&E Corporation's and the Utility's principal executive officers and principal financial officers have concluded that such controls and procedures effectively 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 (SEC) rules and forms.

There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II. OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS

Pacific Gas and Electric Company Bankruptcy

As previously disclosed in PG&E Corporation's and Pacific Gas and Electric Company's (the Utility) combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002 and June 30, 2002, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). On June 17, 2002, the disclosure statements relating to the proposed plan of reorganization sponsored by PG&E Corporation and the Utility (Utility Plan) and an alternative proposed plan of reorganization (Alternative Plan) sponsored by the California Public Utilities Commission (CPUC) were sent to creditors entitled to vote on the plans.

On July 29, 2002, shortly before the voting period ended, the CPUC filed an application with the Bankruptcy Court alleging that the Utility, PG&E Corporation, and their third-party solicitor improperly solicited votes and seeking a temporary restraining order to prohibit the continuing solicitation of votes, an order to require the distribution of corrective materials, an order extending the deadline for creditors to vote on the competing plans of reorganization, and an order allowing creditors to recast their ballots. The Bankruptcy Court denied the application for such relief on August 5, 2002. The CPUC's underlying complaint, which also was filed with the Bankruptcy Court on July 29, 2002, against the Utility, PG&E Corporation, and their third-party solicitor, alleges that the defendants improperly solicited votes by allegedly making false and misleading statements to creditors and equity holders. The CPUC has granted the defendants an indefinite period of time to file a response to the comp
laint. The CPUC may terminate the extension period after providing 10 days notice of termination to the defendants. After the 10 day period, the defendants' response would be due. A status conference regarding this matter was held on October 21, 2002. The Bankruptcy Court granted the CPUC's request to continue the status conference to November 14, 2002.

On August 22, 2002, 10 days after the voting period ended, the CPUC and the Official Committee of Unsecured Creditors (OCC) announced that they had reached an agreement to make certain modifications to the Alternative Plan. The CPUC and the OCC jointly filed an amended Alternative Plan of reorganization on August 30, 2002, and requested the Bankruptcy Court's permission to resolicit votes and preferences for the CPUC's and the OCC's amended Alternative Plan. PG&E Corporation and the Utility opposed the request to reopen the voting. On September 9, 2002, the results of the creditor vote on the plans of reorganization were filed in Bankruptcy Court. The Utility Plan received approval from 9 out of 10 voting creditor classes, while the original plan sponsored by the CPUC was rejected by all but one voting creditor class. In order to proceed to the confirmation trial, each plan of reorganization needed to obtain the acceptance of at least one class of creditors holding impaired cla
ims. On September 20, 2002, the Bankruptcy Court denied the CPUC's and the OCC's request to reopen the voting. The Bankruptcy Court declined to rule on the CPUC's and the OCC's additional request for an order authorizing the resolicitation of creditor preferences. On November 6, 2002, the CPUC and the OCC filed a second amended Alternative Plan and also filed a motion asking the Bankruptcy Court to authorize the resolicitation of creditor preferences. The hearing on the CPUC and the OCC's motion is set for November 27, 2002. Neither plan will become effective unless it is confirmed by the Bankruptcy Court.

On August 30, 2002, the U.S. District Court for the Northern District of California issued an order in PG&E Corporation's and the Utility's pending appeal of the Bankruptcy Court's March 18, 2002, order, which had disapproved PG&E Corporation's and the Utility's contentions that bankruptcy law permits express preemption of state law in connection with the implementation of a plan of reorganization. In its August 30, 2002, order, the District Court reversed the Bankruptcy Court's March 18, 2002, order and remanded the case back to the Bankruptcy Court for further proceedings, ruling that the Bankruptcy Code expressly preempts "nonbankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan." The District Court entered judgment on September 19, 2002, and thereafter, on or about September 30, 2002, the CPUC, the California Attorney General (AG), the City and County of San Francisco, and the California Hydropower Reform Coalition
filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In addition, on or about September 17, 2002, such parties also filed a protective motion asking the District Court to amend its August 30, 2002, decision to include findings authorizing them to appeal the decision on an interlocutory basis to the Ninth Circuit under 28 U.S.C. Section 1292(b). PG&E Corporation and the Utility informed the District Court that they have no objection to certifying its express preemption decision for interlocutory review, and the motion was submitted for decision without argument. On September 19, 2002, such parties also filed a motion requesting the District Court to stay its August 30, 2002, decision pending an appeal to the Ninth Circuit. Arguments on the stay motion were heard on October 8, 2002, and the District Court took the stay motion under submission. On October 11, 2002, the Ninth Circuit issued a scheduling order in the appeal, setting a briefing schedule that commenc
es on January 19, 2003; however, on October 30, 2002, PG&E Corporation and the Utility filed a motion asking the Ninth Circuit to expedite its review of the District Court's August 30, 2002, decision.

With respect to the application filed with the Nuclear Regulatory Commission (NRC) for permission to transfer the NRC operating licenses held by the Utility for its Diablo Canyon Power Plant to Electric Generation, LLC (Gen) (which would become a subsidiary of PG&E Corporation after consummation of the Utility Plan) as contemplated by the Utility Plan, on June 25, 2002, the NRC issued a Memorandum and Order denying various petitions to intervene and requests for hearing that had been filed by the CPUC, the County of San Luis Obispo, and the OCC, among others. In particular, with respect to the CPUC, the NRC found that the CPUC did not have standing to participate at the NRC with respect to public health and safety matters, as opposed to economic regulatory matters. In addition, the NRC found that the CPUC did not raise any litigable issues within the NRC's jurisdiction and that the CPUC's issues were being addressed more properly in other forums, such as the Bankruptcy Court and the Federal Energy
Regulatory Commission (FERC). On August 23, 2002, the CPUC and the County of San Luis Obispo filed a petition for review of the NRC decision in the Ninth Circuit. That matter remains pending.

With respect to the application filed with the FERC for approval of the bilateral power sales agreement to be entered into between the reorganized Utility and Gen as contemplated in the Utility Plan, the FERC must find that the power sales agreement is just and reasonable before the agreement could become effective. In order to demonstrate that the pricing, terms, and conditions of the proposed power sales agreement are just and reasonable, Gen submitted benchmark evidence of contemporaneous sales made by non-affiliated parties for similar services in the California electric market.

On October 10, 2002, the Administrative Law Judge (ALJ) issued an initial decision finding that Gen successfully had "carried its burden" with respect to the benchmark analysis and had shown that the power sales agreement between the reorganized Utility and Gen was in fact comparable to the selected benchmark contracts. The ALJ found no evidence in the record of any exercise of market power on Gen's behalf. In addition, the ALJ found that Gen's selection of contracts used as a comparison group in the benchmark analysis was appropriate and met all of the FERC's criteria. The ALJ's findings provide a basis for the FERC to approve the power sales agreement as just and reasonable. There is no specific time by which the FERC is required to take final action on the initial decision.

On October 1, 2002, the Bankruptcy Court issued a scheduling order governing the trials on confirmation of the competing plans of reorganization. The trial on confirmation of the CPUC's Alternative Plan of reorganization (as amended jointly by the CPUC and the OCC on August 30, 2002, and November 6, 2002) will begin on November 18, 2002, and is tentatively scheduled to end by December 5, 2002. The trial on the Utility Plan is scheduled to begin on December 16, 2002. Objections common to both plans are slated for hearing during the trial on the Utility Plan.

Neither PG&E Corporation nor the Utility can predict what the outcome of the Utility's bankruptcy proceeding will be.

Pacific Gas and Electric Company v. California Public Utilities Commissioners

As previously disclosed in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002, and June 30, 2002, the Utility filed a lawsuit in the U.S. District Court for the Northern District of California against the CPUC Commissioners, asking the court to declare that the federally approved wholesale power costs that the Utility has incurred to serve its customers are recoverable in retail rates (Filed Rate Case).

On April 18, 2002, the Utility filed a motion for summary judgment requesting the court to order the relief sought in the Filed Rate Case. Also, on April 18, 2002, the CPUC Commissioners and The Utility Reform Network (TURN), a ratepayer advocacy group which filed a request to intervene in the Filed Rate Case, filed motions to dismiss the Utility's claim as well as motions for summary judgment asking the court to rule against the Utility on its federal preemption claim as a matter of law. The principal ground for the CPUC's and TURN's motions is that, by adopting the retroactive change in the accounting mechanisms for recovery of transition and power procurement costs in March 2001, the CPUC already has allowed the Utility to recover its wholesale procurement costs. (The retroactive accounting change, adopted by the CPUC in March 2001, appeared to eliminate the Utility's true under-collected wholesale electricity costs by applying amounts that previously were applied first to transition cost recovery to
under-collected procurement costs, effectively transforming under-collected procurement costs to under-collected transition costs. The Utility requested the Bankruptcy Court to enjoin the CPUC from enforcing the accounting order but the Bankruptcy Court denied the Utility's request. The Utility's appeal of the Bankruptcy Court's order has been deemed a related case to the Filed Rate Case and has been transferred to Judge Walker of the District Court.)

On July 25, 2002, the District Court issued an order denying the CPUC's and TURN's motions to dismiss the Filed Rate Case, as well as motions for summary judgment that had been filed by the CPUC, the Utility, and TURN. (TURN's request to intervene in the Filed Rate Case also was granted.) However, much of the District Court's order is a discussion of the merits of the Utility's federal preemption claims. The court rejected every argument advanced by the CPUC and TURN against the application of the federal filed rate doctrine, stating: "in most instances today a utility must purchase the power delivered to consumers pursuant to the rate filed with the appropriate federal agency."

After concluding that the Utility's federal preemption claims as pleaded are meritorious, the District Court denied the motions to dismiss without substantial discussion. The court found, however, that the Utility's preemption claims could not be decided on summary judgment because two factual issues remain in dispute: (1) the appropriate period for considering whether a net under-collection has occurred, and (2) the determination of which revenue sources, within constitutional bounds, may be applied against the Utility's operating costs.

At an August 16, 2002, case management conference, the court adopted the pretrial and trial schedule stipulated to by the parties, including a trial date set for June 9, 2003. On August 23, 2002, the defendants filed a Notice of Appeal from those portions of the July 25, 2002, order denying defendants' motion to dismiss on Eleventh Amendment (sovereign immunity) and Johnson Act grounds. (The Johnson Act prohibits the district courts from enjoining, suspending, or restraining the operation of or compliance with any order affecting rates chargeable by a public utility and made by a state administrative agency as long as certain conditions are met.) On September 4, 2002, the Utility filed a motion with the District Court seeking written certification that the CPUC's appeal of the July 25, 2002, order on Eleventh Amendment and Johnson Act grounds was frivolous. On or about October 21, 2002, the District Court granted the Utility's motion and certified the CPUC's appeal as frivolous, which allows the Distr
ict Court to retain jurisdiction to proceed to trial while the CPUC's appeal to the Ninth Circuit is pending.

Neither PG&E Corporation nor the Utility can predict what the outcome of the Filed Rate Case litigation will be.

Federal Securities Lawsuit

For information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002 and June 30, 2002.

In re: Natural Gas Royalties Qui Tam Litigation

For information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001.

Baldwin Associates

As previously disclosed in PG&E Corporation's and the Utility's Annual Report on Form 10-K for the year ended December 31, 2001, Baldwin Associates, Inc. (Baldwin) filed a notice of appeal in the U.S. District Court for the Northern District of California. Baldwin sought to appeal the Bankruptcy Court's decision sustaining the Utility's objection to Baldwin's bankruptcy claim. In a written order dated May 6, 2002, the District Court granted the Utility's motion to dismiss Baldwin's appeal. On May 29, 2002, the court entered an amended order holding Baldwin and its counsel of record jointly and severally liable for the attorneys' fees and costs related to the appeal. Neither Baldwin nor its counsel filed a further appeal. The Utility considers the matter closed.

Wayne Roberts

On October 23, 2002, the Bankruptcy Appellate Panel (BAP) for the Ninth Circuit heard oral argument on Wayne Roberts' appeal of the Bankruptcy Court's order denying his $4 billion claim. The BAP then took the matter under submission. For more information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001.

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

Moss Landing Power Plant

For more information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2002.

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 (DTSC) alleging that the Diablo Canyon Power Plant (Diablo Canyon) failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months during 2001. Under the California Health and Safety Code, operators of hazardous waste facilities must demonstrate to the DTSC (using a limited number of alternative methods specified by regulation) that the operator can close and clean up the facility at the end of its useful life. The Utility has used a "balance sheet" method in the past, but was unable to do so after the Utility's financial condition deteriorated in early 2001. Nevertheless, the Utility was able to secure an endorsement to its existing insurance policy that met the DTSC's requirements. The draft order seeks $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 directs 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 Diablo Canyon. The violations were identified in an April 2001 inspection. The draft order seeks $24,330 in civil penalties. On October 7, 2002, the hazardous waste draft order was consolidated with the financial assurance draft order. Settlement discussions are ongoing.

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.

For more information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.

Compressor Station Chromium Litigation

As previously disclosed in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, the Utility has been named in several civil lawsuits relating to alleged chromium contamination. There are currently 15 of such civil actions pending in California courts against the Utility. One additional civil suit, Kearney v. Pacific Gas and Electric Company, filed November 15, 2001, in Los Angeles County Superior Court, was filed after the Utility's bankruptcy filing and was dismissed without prejudice while the plaintiffs seek the right to file and pursue late claims in the Bankruptcy Court.

In the case of Adams v. Pacific Gas and Electric Company and Betz Chemical Company, after a hearing on July 17, 2002, the state court dismissed 35 plaintiffs with prejudice because their claims are barred by the statute of limitations. The state court dismissed another 65 plaintiffs without prejudice, so these plaintiffs may attempt to plead that their claims are not barred by the statute of limitations. Thirty of these plaintiffs filed a Fourth Amended Complaint on October 16, 2002.

In the case of Kearney v. Pacific Gas and Electric Company, the Bankruptcy Court ruled that six adult plaintiffs could not file untimely bankruptcy claims against the Utility. The court also ruled that 24 minor plaintiffs in the case could file untimely bankruptcy claims against the Utility.

PG&E Corporation and the Utility believe that, in light of the reserves that already have been accrued with respect to this matter, 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 results of operations. See Note 7 of the Notes to Consolidated Financial Statements.

California Energy Trading Litigation

As previously disclosed in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, PG&E Energy Trading Holdings Corporation and various of its affiliates (collectively ET-Power) have been named, along with multiple other defendants, in four class action lawsuits against marketers and other unnamed sellers of electricity in California markets. These cases are pending in the U.S. District Court for the Southern District of California. Plaintiffs have a filed motion to remand the proceedings to state court. In September 2002, the court heard oral argument on plaintiffs' motion to remand the proceeding as well as to dismiss certain claims pending against various cross-defendants. The judge has not yet ruled on these motions.

As previously disclosed in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, the California AG filed a complaint at the FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. The California AG alleges that wholesale sellers of energy to the California Independent System Operator (ISO), the Power Exchange (PX), and the California Department of Water Resources (DWR) failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California AG claims that the FERC has not been able to determine whether the rates charged by such sellers are just and reasonable, that the FERC's reporting requirements are insufficient to provide the FERC the information necessary to make this determination, and that even if the FERC's policies and procedures did comply w
ith Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California AG requests that (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal Power Act; (2) sellers should be required to provide transaction-specific information to the FERC regarding their short-term sales to the ISO, the PX, and the DWR for the years 2000 and 2001; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) the FERC should declare that market-based rates are not subject to the filed rate doctrine; and (5) the FERC should institute proceedings to determine whether any further relief would be appropriate. On May 31, 2002, the FERC issued a decision denying most of the relief requested and on July 1, 2002, the California AG filed a petition with the FERC seeking rehearing of its order. The FERC denied rehearing on Se
ptember 23, 2002.

For more information regarding these matters, see PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.

PG&E Corporation believes that the outcome of these matters will not have a material adverse affect on PG&E Corporation's financial condition or results of operations.

California Attorney General Complaint

As previously disclosed in PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002, and June 30, 2002, the California AG filed a complaint in the state court against PG&E Corporation alleging violations of California's unfair business practices statute (California Business and Professions Code Section 17200). After removing the California AG's complaint to the Bankruptcy Court, on February 15, 2002, PG&E Corporation filed a motion to dismiss, or in the alternative, to stay, the California AG 's complaint with the Bankruptcy Court. Subsequently, the California AG filed a motion to remand the action to state court. The Bankruptcy Court held a hearing on April 24, 2002, to consider the remand motion. On June 20, 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand. (An initial order was issued on June 2, 2002). The Bankruptcy Court held t
hat federal law preempted the California AG's allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceedings. The Bankruptcy Court directed the California AG to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Defendants appealed the Bankruptcy Court's June 20, 2002, order and elected to have the appeal heard by the U.S. District Court for the Northern District of California. That appeal is pending. The issues on appeal involve, among other things, whether the Bankruptcy Court erred by (1) remanding the California AG's Section 17200 claim, because the claim is the property of the debtor's estate, and because the claim is within the exclusive jurisdiction of the Bankruptcy Court under 28 U.S.C. Section 1334(e), and (2) by finding that the police power exception under 28 U.S.C. Section 452(a) prevented removal of the California AG's claim for restitution under Section 17200, because such predomi
nantly monetary claims do not constitute enforcement of police power. The California AG cross-appealed the June 20, 2002, Order.

On August 9, 2002, the California AG filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's bankruptcy proceedings. PG&E Corporation and the directors named in the complaint have filed a motion to strike certain allegations of the amended complaint. PG&E Corporation and the directors also have moved to partially consolidate the case with the case brought by the City and County of San Francisco discussed below. Those motions are pending.

PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse effect on its financial condition or results of operations.

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 Reports on Form 10-Q for the quarters ended March 31, 2002, and June 30, 2002, on February 11, 2002, the City filed a complaint in state court against PG&E Corporation alleging violations of California's unfair business practices statute (California Business and Professions Code Section 17200), and for unjust enrichment and conversion. After removing the City's action to the Bankruptcy Court, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. On June 20, 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand. (An initial order was issued on June 2, 2002.) In its remand order, the court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City, but remanded the Section 17200 cause of action to t
he San Francisco Superior Court. Defendants timely appealed the Bankruptcy Court's June 20, 2002, Order and elected to have the appeal heard by the U.S. District Court for the Northern District of California. That appeal is pending. The issues on appeal involve, among other things, whether the Bankruptcy Court erred by (1) remanding plaintiffs' Section 17200 claim, because the claim is the property of the debtor's estate, and because the claim is within the exclusive jurisdiction of the Bankruptcy Court under 28 U.S.C. Section 1334(e), and (2) by finding that the police power exception under 28 U.S.C. Section 452(a) prevented removal of plaintiffs' claim for restitution under Section 17200, because such predominantly monetary claims do not constitute enforcement of police power.

Following remand, PG&E Corporation brought a motion to strike which is currently pending and scheduled to be heard on November 18, 2002. PG&E Corporation has moved to partially consolidate this case with the Section 17200 case brought by the California AG.

PG&E Corporation believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse affect on its financial condition or results of operations.

Sierra Pacific Industries v. Pacific Gas and Electric Company

As previously disclosed, on June 4, 2002, the Utility reached a settlement agreement with Sierra Pacific Industries (SPI) that calls for reinstatement of SPI's four power purchase agreements with certain modifications to increase SPI's flexibility in meeting contractual commitments. The Utility has agreed to pay SPI a fixed price of 5.37 cents per kilowatt hour (kWh) for energy delivered for four years. In addition, the Utility has agreed to pay for the energy and capacity that SPI delivered but for which the Utility had not paid when its bankruptcy petition was filed on April 6, 2001. SPI has agreed to dismiss its $1.1 billion complaint claim and to withdraw its bankruptcy claim. The settlement agreement was subject to receiving both Bankruptcy Court and CPUC approval. The Bankruptcy Court has approved the settlement agreement, and on October 24, 2002, the CPUC also unanimously approved the settlement agreement. The settlement agreement resolves SPI's state court lawsuit against the Utility and the
ISO, and also resolves SPI's $1.1 billion bankruptcy claim against the Utility.

For more information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.

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

For more information regarding this matter, see PG&E Corporation's and the Utility's combined Annual Report on Form 10-K for the year ended December 31, 2001, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002, and June 30, 2002.

PG&E National Energy Group's Brayton Point Generating Station

As previously disclosed in PG&E Corporation's and the Utility's combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2002, and June 30, 2002, on March 27, 2002, the AG of the State of Rhode Island notified USGen New England, Inc. (USGenNE) of his belief that the Brayton Point Generating Station (Brayton Point) is operating in violation of applicable statutory and regulatory provisions, including what he characterized as "protections afforded by common law." The AG of the State of Rhode Island purported to provide notice under the Massachusetts General Laws of his intention to seek judicial relief within the following 30 days to abate the alleged violations, to recover damages, and to obtain other unexplained statutory and equitable remedies. PG&E National Energy Group, Inc. (PG&E NEG) believes that Brayton Point is in full compliance with all applicable permits, laws, and regulations. The complaint has not yet been filed or served. In May 2002, the AG of the State of Rh
ode Island stated that he did not plan to file the action until the U.S. Environmental Protection Agency (EPA) issued a draft Clean Water Act National Pollutant Discharge Elimination System (NPDES) permit for Brayton Point. On July 22, 2002, the EPA and the Massachusetts Department of Environmental Protection issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay. The Rhode Island AG has since stated that he has no intention of pursuing this matter until he reviews USGenNE's response to the draft permit, which was submitted on October 4, 2002.

PG&E Corporation is unable to predict whether the Rhode Island AG will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E Corporation's financial condition or results of operations.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

In connection with the Second Amended and Restated Credit Agreement dated October 18, 2002 among PG&E Corporation, the lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and others (Second Amended Credit Agreement), PG&E Corporation has issued to the lenders additional warrants to purchase 2,669,390 shares of common stock of PG&E Corporation. The number of warrants was calculated by dividing $25.2 million (3.5 percent of the aggregate principal amount of the loans) by the average of the volume-weighted average price of PG&E Corporation common stock as reported on the New York Stock Exchange for each of the 10 trading days beginning on October 10, 2002, and ending October 24, 2002. The terms and provisions of the warrants, including a warrant exercise price of $0.01 per share, are substantially identical to the warrants previously issued to the Tranche B lenders on June 25, 2002. PG&E Corporation has agreed to provide, following consummation of a plan o
f reorganization of Pacific Gas and Electric Company, registration rights in connection with the shares issuable upon exercise of these warrants.

PG&E Corporation's 7.50 percent Convertible Subordinated Notes due 2007 in the aggregate principal amount of $280 million issued on June 25, 2002 (Notes), and the Indenture relating to the Notes have been amended to delete certain cross-default provisions which provided that a non-payment or an acceleration of indebtedness of PG&E NEG or any of its subsidiaries, or a bankruptcy event with respect to PG&E NEG or any of its subsidiaries, constituted a default or event of default under the Notes and the Indenture. Further, the Indenture and the Notes have been amended, among other things, to increase the interest rate on the Notes to 9.50 percent from 7.50 percent, to extend the maturity of the Notes to June 30, 2010, from June 30, 2007, and to provide the holder of the Notes with a one-time right to require PG&E Corporation to repurchase the Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including any liquidated damages and pass-t
hrough dividends, if any).

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Pacific Gas and Electric Company (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, 2002, 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 series and 2.5 million shares of the 6.30 percent series at September 30, 2002. The 6.57 percent series and 6.30 percent series may be redeemed at the Utility's option begi
nning in 2002 and 2004, respectively, 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, 2002, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are $4 million for 2002 and 2003 and $3 million per year beginning 2004, for the series 6.57 percent and 6.30 percent, respectively. The Utility is not permitted to make sinking fund payments unless all dividends on preferred stock have been paid. Therefore, the $4 million sinking fund payment that was due on July 31, 2002, to redeem 150,000 shares of the 6.57 percent series was not made. The sinking fund payments are cumulative so that if on any July 31 the sinking fund payment is not made, the remaining shares of the 6.57 percent series required to be redeemed must be redeemed before any shares
of another series with a required sinking fund can be redeemed, unless the redemption of shares of both series is pro rata.

Holders of the Utility's non-redeemable 5.0 percent, 5.5 percent, and 6.0 percent 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 bankruptcy, the Utility's Board of Directors has not declared the regular preferred stock dividends since the dividend paid with respect to the three-month period ended October 31, 2001.

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, 2002, amounted to $44.2 million. 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.

The Utility's total defaulted commercial paper outstanding at September 30, 2002, was $873 million. At September 30, 2002, the Utility had drawn and had outstanding $938 million under its bank credit facility, which was also in default. Per the terms of the Amended and Restated Settlement and Support Agreement, the Utility made interest payments totaling $99.6 million starting April 1, 2001, for its commercial paper and $115.2 million starting March 31, 2001, for the bank credit facility up to and including September 30, 2002.

With regard to certain pollution control bond-related debt of the Utility, the Utility has been in default 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 Bankruptcy Code, and non-payment of interest. As a result of these defaults, several of the letter of credit banks caused the acceleration and redemption of four series of pollution control bonds. All of these redemptions were funded by the letter of credit banks, resulting in loans from the banks to the Utility, which have not been paid. At September 30, 2002, the total principal of the bonds (and related loans) accelerated and redeemed was $454 million. Per the Amended and Restated Settlement and Support Agreement, the Utility made interest payments on these loans totaling $44.6 mi
llion in 2002.

In 2002, the Utility paid advances and interest on advances of $22.8 million to banks providing letters of credit on pollution control bonds series 96C, 96E, 96F, and 97B. The Utility also made interest payments on pollution control bond series 96A backed by bond insurance. Per the Amended and Restated Settlement and Support Agreement, unpaid interest advances totaling $13.7 million for the period from June 1, 2001, through June 30, 2002, was paid on May 6, 2002, May 31, 2002, and July 1, 2002. 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 bankruptcy filing.

The Utility's filing of a petition for reorganization under Chapter 11 of the Bankruptcy Code also constitutes a default under the indenture that governs its medium-term notes ($287 million aggregate amount outstanding), five-year 7.375 percent senior notes ($680 million aggregate amount outstanding), and floating rate notes ($1.24 billion aggregate amount outstanding). Per the Amended and Restated Settlement and Support Agreement, in 2002, the Utility made interest payments on its medium-term notes, its 7.375 percent senior notes, and its $1.24 billion floating rate notes totaling $326.9 million through the period September 30, 2002.

From the date of the filing of the bankruptcy petition (April 6, 2001) to September 30, 2002, the Utility has not made principal payments on unsecured long-term debt of $131 million.

With regard to the 7.90 percent Quarterly Income Preferred Securities (QUIPS) and the related 7.90 percent Deferrable Interest Debentures (debentures), the Utility's filing of a petition for reorganization under Chapter 11 of the Bankruptcy Code is 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 Subordinated Debentures, or QUIDS. See Note 5 of the Notes to Consolidated Financial Statements regarding current interest payments on the QUIDS.

ITEM 5. OTHER INFORMATION

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

Pacific Gas and Electric Company's earnings to fixed charges ratio for the nine months ended September 30, 2002, was 4.33. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2002, was 4.19. 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 Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959, relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits:

Exhibit 4.1

Supplemental Indenture related to PG&E Corporation's 9.50 percent Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee

Exhibit 4.2

Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto

Exhibit 10.1

Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.1)

Exhibit 10.2

Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.2)

Exhibit 10.3

Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.3)

Exhibit 10.4

Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.4)

Exhibit 10.5

Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.5)

Exhibit 11

Computation of Earnings Per Common Share

Exhibit 12.1

Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

Exhibit 12.2

Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

Exhibit 99.1

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

Exhibit 99.2

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

(b) The following Current Reports on Form 8-K were filed during the third quarter of 2002 and through the date hereof:

1. July 2, 2002

Item 5.

Other Events

A.

Pacific Gas and Electric Company Bankruptcy: Monthly Operating Report

B.

Dismissal of Federal Securities Lawsuit

C.

Motion to Extend Exclusivity Period

D.

Nuclear Regulatory Commission Ruling

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99 - Pacific Gas and Electric Company Income Statement for the month

Ended May 31, 2002, and Balance Sheet dated May 31, 2002

2. July 29, 2002

Item 5.

Other Events

A.

Recovery of Wholesale Power Purchase Costs

3. August 2, 2002

Item 9.

Regulation FD Disclosure

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit No. 99.1 - Statement Under Oath of principal executive officer Robert D. Glynn, Jr. dated August, 1, 2002

Exhibit No. 99.2 - Statement Under Oath of principal financial officer Peter A. Darbee dated August 1, 2002

4. August 6, 2002

Item 5.

Other Events

A.

PG&E Corporation Credit Agreement and PG&E National Energy Group, Inc. credit ratings downgrades

B.

Pacific Gas and Electric Company bankruptcy

5. August 19, 2002

Item 5.

Other Events

A.

PG&E Corporation Credit Agreement waiver extension

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99.1 - Waiver and Amendment Agreement, dated August 16, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc., as administrative agent, and the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

6. August 26, 2002

Item 5.

Other Events

A.

PG&E Corporation Credit Agreement waiver revision

B.

Extension of PG&E National Energy Group credit facility expiration date

C.

PG&E NEG projected cash management-potential sources and uses of cash table

D.

Pacific Gas and Electric Company bankruptcy

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99.1 - Waiver and Amendment Agreement, dated August 22, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

7. September 3, 2002 -

Item 5.

Other Events

         PG&E Corporation only

A.

Voluntary prepayment of loan to General Electric Capital Corporation

B.

New waiver extension from remaining lenders

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99 - Second Amended and Restated Waiver and Amendment Agreement, dated August 30, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and certain of the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

8. September 4, 2002

Item 5.

Pacific Gas and Electric Company bankruptcy

A.

District Court ruling in favor of PG&E Corporation's and Pacific Gas and Electric Company's express preemption argument

B.

Monthly Operating Report

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2002, and Balance Sheet dated July 31, 2002

9. September 10, 2002

Item 5.

Pacific Gas and Electric Company Bankruptcy

A.

Voting results

B.

Request to re-solicit votes; complaint regarding solicitation

10. October 3, 2002

Item 5.

Other Events

A.

PG&E Corporation-new waiver extension

B.

Pacific Gas and Electric Company bankruptcy: Monthly Operating Report

Item 7.

Financial Statements, Pro Forma, Financial Information, and Exhibits

Exhibit 99.1 - Amendment to Second Amended and Restated Waiver and Amendment Agreement, dated October 1, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and certain of the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

Exhibit 99.2 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2002, and Balance Sheet dated August 31, 2002

11. October 10, 2002 -

Item 5.

Other Events

         PG&E Corporation only

A.

PG&E National Energy Group, Inc. credit ratings downgrades

12. October 15, 2002

Item 5.

Other Events

A.

Pacific Gas and Electric Company's 2003 Cost of Capital Proceeding

B.

Pacific Gas and Electric Company bankruptcy

13. October 21, 2002 -

Item 5.

Other Events

         PG&E Corporation only

A.

PG&E National Energy Group credit ratings downgrades

14. October 22, 2002 -

Item 5.

Other Events

         PG&E Corporation only

Item 7.

Financial Statements, Pro Forma Financial Information, and Exhibits

Exhibit 99.1 - Second and Amended Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, the lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties

Exhibit 99.2 - Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002

Exhibit 99.3 - Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002

Exhibit 99.4 - Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002

Exhibit 99.5 - Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002

SIGNATURE

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

BY:   /S/ CHRISTOPHER P. JOHNS

-------------------------------------------------------

CHRISTOPHER P. JOHNS

Senior Vice President and Controller

(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

BY:  /S/ DINYAR B. MISTRY

-------------------------------------------------------

DINYAR B. MISTRY

Vice President and Controller

(duly authorized officer and principal accounting officer)

Dated:  November 12, 2002

I, Robert D. Glynn, Jr., certify that:

1.  I have reviewed this quarterly report on Form 10-Q of PG&E Corporation;

2.  Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a     material fact necessary to make the statements made, in light of the circumstances under which such statements were     made, not misleading with respect to the period covered by this quarterly report;

3.  Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly     present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,     the periods presented in this quarterly report;

4.  The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.  The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.  The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant     changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our     most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002

/S/  ROBERT D. GLYNN, JR.
ROBERT D. GLYNN, JR.
Chairman, Chief Executive Officer and President
PG&E Corporation

I, Peter A. Darbee, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of PG&E Corporation;

2.  Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a     material fact necessary to make the statements made, in light of the circumstances under which such statements were     made, not misleading with respect to the period covered by this quarterly report;

3.  Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly     present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,     the periods presented in this quarterly report;

4.  The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.  The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.  The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant     changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our     most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002

/S/  PETER A. DARBEE
PETER A. DARBEE
Senior Vice President and Chief Financial Officer
PG&E Corporation

I, Gordon R. Smith, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Pacific Gas and Electric Company;

2.  Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a     material fact necessary to make the statements made, in light of the circumstances under which such statements were     made, not misleading with respect to the period covered by this quarterly report;

3.  Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly     present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,     the periods presented in this quarterly report;

4.  The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.  The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.  The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant     changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our     most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002

/S/  GORDON R. SMITH
GORDON R. SMITH
President and Chief Executive Officer
Pacific Gas and Electric Company

I, Kent M. Harvey, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Pacific Gas and Electric Company;

2.  Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a     material fact necessary to make the statements made, in light of the circumstances under which such statements were     made, not misleading with respect to the period covered by this quarterly report;

3.  Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly     present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,     the periods presented in this quarterly report;

4.  The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and     procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant's disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.  The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's     auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.  The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant     changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our     most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002

/S/  KENT M. HARVEY
KENT M. HARVEY
Senior Vice President, Chief Financial Officer, and Treasurer
Pacific Gas and Electric Company

Exhibit Index

Exhibit No.

Description of Exhibit

Exhibit 4.1

Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee

Exhibit 4.2

Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto

Exhibit 10.1

Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.1)

Exhibit 10.2

Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.2)

Exhibit 10.3

Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.3)

Exhibit 10.4

Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.4)

Exhibit 10.5

Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.5)

Exhibit 11

Computation of Earnings Per Common Share

Exhibit 12.1

Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

Exhibit 12.2

Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

Exhibit 99.1

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

Exhibit 99.2

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}

	Prior Method Presentation (Gross Method) - --------------------------------------------				As Presented (Net Method) - -------------------------------------------
(in millions)	Three months ended September 30, 2002		Nine months ended September 30, 2002		Three months ended September 30, 2002		Nine months ended September 30, 2002
	--------------------		--------------------		--------------------		--------------------
Generation, transportation, and trading revenues	$	4,853	$	10,238	$	1,079	$	2,407
Cost of commodity sales and fuel	4,537		9,469		763		1,638
	---------------		---------------		---------------		---------------
Net Subtotal	$	316	$	769	$	316	$	769
	=========		=========		=========		=========

(in millions)	2002		2003		2004		2005		2006
	-----------		-----------		----------		-----------		----------
PG&E NEG	$	6	$	6	$	6	$	6	$	6
Utility	3		3		3		3		3

Liabilities Subject to Compromise at December 31, 2001	$	11.4
Interest accrual for the nine months ended September 30, 2002	0.3
Claims paid pursuant to Bankruptcy Court orders	(1.2)
Claims and Interest authorized by the Bankruptcy Court to be paid (transferred to accounts payable or interest payable)	(0.7)
Reclassification of debt upon liquidation of trust holding solely Utility Subordinated Debentures (Note 5)	0.3
Reversal of first quarter 2001 ISO accrual	(1.0)
	---------------
Liabilities Subject to Compromise at September 30, 2002	$	9.1
	=========

	On the Effective Date of the Plan, Creditors Would Receive Payment In
	---------------------------------
	Cash	Long-term Notes
	------------	--------------
Majority of secured creditors	100%	-
Majority of unsecured creditors with allowed claims of $100,000 or less	100%	-
Unsecured creditors with allowed claims in excess of $100,000	60%	40%
QUIDS (Note 5)	-	100%

	Amount Owed (in millions)		Agreed Upon Rate (per annum)
	--------------------		-----------------------

Commercial Paper Claims	$	873	7.466%
Floating Rate Notes	1,240		7.583%	(Implied yield of 7.690%)
Senior Notes	680		9.625%
Medium-Term Notes	287		5.810% to 8.450%
Revolving Line of Credit Claims	938		8.000%

	Standard & Poor's	Moody's Investors Service
	-----------------	----------------------
Rated Entities:
PG&E NEG	B-	B3
PG&E GTN	BB-	Ba1
PG&E ET	B-	Not Rated
PG&E Gen	B-	Not Rated
USGen New England (USGenNE)	B-	B2

Rated Debt Instruments:
Senior Unsecured Notes, due 2011 (PG&E NEG)	B-	B3
Senior Unsecured Notes, due 2005 (PG&E GTN)	BB-	Ba1
Senior Unsecured Debentures, due 2025 (PG&E GTN)	BB-	Ba1
Senior Unsecured Notes, due 2012 (PG&E GTN)	BB-	Ba1
Medium-term Notes - nonrecourse (PG&E GTN)	BB-	Ba1
Term loans (GenHoldings I, LLC)	CC	B3

(in millions)			Outstanding Balance of
Description	Maturity	Interest Rates	September 30, 2002		December 31, 2001
-----------------------------------------------------	--------------	--------------------------------	------------------		-----------------

PG&E NEG Senior Unsecured Notes	2011	10.375%	$	1,000	$	1,000
PG&E NEG Credit Facility - Tranche B (364-day)	11/14/02	LIBOR plus credit spread	431		330
Turbine and Equipment Facility	12/31/03	LIBOR plus credit spread	205		221

PG&E GTN Senior Unsecured Notes	2005	7.10%	250		250
PG&E GTN Senior Unsecured Debentures	2025	7.80%	150		150
PG&E GTN Senior Unsecured Notes	2012	6.62%	100		-
PG&E GTN Medium-Term Notes	Thru 2003	6.83% to 6.96%	6		39
PG&E GTN Credit Facility	5/2/05	LIBOR plus credit spread	-		84

GenHoldings Construction Facility	12/21/06	LIBOR plus credit spread	1,025		450
LaPaloma Construction Facility	3/7/05	LIBOR plus credit spread	646		588
Lake Road Construction Facility	8/28/04	LIBOR plus credit spread	446		417
USGenNE Credit Facility	9/1/03	LIBOR plus credit spread	75		75
Plains End Construction Facility	9/6/06	LIBOR plus credit spread	44		23

Other non-recourse project term loans	Various	Principally LIBOR plus credit spread	94		100
Mortgage loan payable	2010	CP rate + 6.07%	7		8
Other	Various	Various	17		17
			-----------------		-----------------
Total short-term borrowings and long-term debt			$	4,496	$	3,752
			==========		==========
Amounts classified as:
Short-term borrowings			$	431	$	330
Long-term debt, classified as current			773		48
Long-term debt			3,292		3,374
			-----------------		-----------------
Total short-term borrowings and Long-term debt			$	4,496	$	3,752
			==========		==========

Three months ended December 31, 2002	$	27
Three months ended March 31, 2003	604
Three months ended June 30, 2003	27
Three months ended September 30, 2003	115
Three months ended December 31, 2003	105
2004	24
2005	51
2006	297
2007	1,018
Thereafter	1,797
	------------
Total Long-term debt	4,065
Short-term borrowings	431
	------------
Total Short-term borrowings and Long-term debt	$	4,496
	=======

(in millions) Borrower		Maturity	Letter of Credit Capacity		Letter of Credit Outstanding September 30, 2002
----------------		--------------	-------------------		-------------------------
PG&E NEG		8/03 ⁽¹⁾	$	279	$	277
USGenNE		8/03	25		15
PG&E Gen		12/04	10		7
PG&E ET		12/02	25		24
PG&E ET		- ⁽²⁾	50		49
PG&E ET		11/03	35		34

⁽¹⁾	On October 21, 2002, PG&E NEG and the lenders under the two-year revolving credit facility entered into an amendment which reduced the lenders' commitments to $273 million, which is the amount outstanding at October 21, 2002.

⁽²⁾	This letter of credit facility provides for up to $50 million of non-domestic letters of credit to be issued, available to PG&E Energy Trading, Canada Corporation, an indirect subsidiary of PG&E NEG, to use to post non-domestic letters of credit to support counterparty obligations. There is no term for the facility, but the bank can review it for termination each year.

(in millions)	Three months ended September 30, 2002				Nine months ended September 30, 2002
	------------------------------				-----------------------------
	PG&E Corporation		Utility		PG&E Corporation		Utility
	----------------		-----------		----------------		-----------
Derivative gains (losses) included in accumulated other comprehensive income (loss) at beginning of period	$	(43)	$	- -	$	36	$	- -
Net gain (loss) from current period hedging transactions and price changes	(153)		- -		(237)		- -
Net reclassification to earnings	(2)		-		3		-
	---------------		------------		---------------		------------
Derivative losses included in accumulated other comprehensive loss at end of period	(198)		- -		(198)		- -
Foreign currency translation adjustment	(2)		-		(2)		-
Other	(1)		-		(1)		-
	---------------		------------		---------------		------------
Accumulated other comprehensive loss at end of period	$	(201)	$	-	$	(201)	$	-
	=========		=======		=========		=======

(in millions)	Three months ended September 30, 2001				Nine months ended September 30, 2001
	------------------------------				----------------------------
	PG&E Corporation		Utility		PG&E Corporation		Utility
	----------------		-----------		----------------		-----------
Derivative gains (losses) included in accumulated other comprehensive income (loss) at beginning of period	$	(106)	$	(41)	$	- -	$	- -
Cumulative effect of adoption of SFAS No. 133	-		-		(243)		90
Net gain (loss) from current period hedging transactions and price changes	21		1		170		(6)
Net reclassification to earnings	43		40		31		(84)
	---------------		------------		---------------		------------
Derivative losses included in accumulated other comprehensive loss at end of period	(42)		- -		(42)		- -
Foreign currency translation adjustment	(5)		(2)		(5)		(2)
	---------------		------------		---------------		------------
Accumulated other comprehensive loss at end of period	$	(47)	$	(2)	$	(47)	$	(2)
	=========		=======		=========		=======

	Assets					Liabilities				Net Assets (Liabilities)
	--------------------------					---------------------------				--------------
(in millions)	Current			Noncurrent		Current		Noncurrent
	-----------			--------------		-----------		--------------
Trading activities	$	235		$	288	$	(228)	$	(285)	$	10

Non-trading activities:
Cash flow hedges - offset to OCI	356			194		(473)		(320)		(243)
Derivatives marked to market through earnings			24	68		(40)		(231)		(179)
	-----------			-------------		-------------		-------------		------------
Total consolidated PRM Assets and Liabilities	$	615		$	550	$	(741)	$	(836)	$	(412)
	=======			=======		=======		=======		=======

(in millions)	Gross Exposure ⁽¹⁾		Credit Collateral ⁽²⁾		Net Exposure ⁽²⁾
	---------------		----------------		----------------
PG&E Corporation	$	1,266	$	221	$	1,045

Utility ⁽³⁾	236		102		134

2002	$	223
2003	412
2004	98
2005	82
2006	26
Thereafter	10
	--------------
Total	$	851
	========

New Loans	Balance From Existing Loan		New Borrowings		New Loan Balance
---------------------	----------------------		-----------------		------------------
Tranche A Loan	$	600	$	-	$	600

Tranche B Loan	92		328		420

	Credit Rating
	----------------------------------------------
	Standard & Poor's	Moody's Investors Service
	-----------------	----------------------
PG&E Corporation
LCPI Loans	Not Rated	Not Rated
Convertible Subordinated Notes	Not Rated	Not Rated

Utility
Mortgage Bonds	CCC	B3
Pollution Control Bonds-Bond Insurance	AAA	Aaa
Pollution Control Bonds-Letters of Credit	AA to AA-/A-1+	Not Rated
Medium-Term Notes	D	Caa2
San Joaquin Valley Power Authority Bond	Not Rated	Rating Withdrawn
DWR Loan	Not Rated	Not Rated
Senior 5-Year Note	D	Caa2
Revolving Credit Line	Not Rated	Not Rated
Floating Rate Notes	D	Not Rated
Matured Commercial Paper	D	Not Prime
Redeemed Pollution Control Bonds-Bank Loans	Not Rated	Not Rated
Deferrable Interest Subordinated Debentures (QUIDS)	Rating Pending	Caa3
Preferred Stock	D	Ca

PG&E NEG
Rated Entities:
PG&E NEG	B-	B3
PG&E GTN	BB-	Ba1
PG&E ET	B-	Not Rated
PG&E Gen	B-	Not Rated
USGen New England, Inc. (USGenNE)	B-	B2
Rated Debt Instruments:
Senior Unsecured Notes due 2011 (PG&E NEG)	B-	B3
Senior Unsecured Notes due 2005 (PG&E GTN)	BB-	Ba1
Senior Unsecured Debentures due 2025 (PG&E GTN)	BB-	Ba1
Senior Unsecured Notes due 2012 (PG&E GTN)	BB-	Ba1
Medium-Term Notes (nonrecourse) (PG&E GTN)	BB-	Ba1
Term Loans (GenHoldings I, LLC)	CC	B3

	Fair Value of Trading Contracts ⁽²⁾
	---------------------------------------------------------------------------------------------
Source of Prices Used in Estimating Fair Value	Maturity Less than One Year		Maturity One-Three Years		Maturity Four-Five Years		Maturity in Excess of Five Years		Total Fair Value
	-----------		-------------		-----------		-------------		-----------
(in millions)
Actively quoted markets	$	(10)	$	8	$	4	$	-	$	2
Provided by other external sources	14		(22)		(13)		(1)		(22)
Based on models and other
valuation methods ⁽¹⁾	3		(14)		(12)		53		30
	----------		----------		----------		----------		----------
Total Mark-to-Market	$	7	$	(28)	$	(21)	$	52	$	10
	======		======		======		======		======

(in millions)

Utility
Non-trading activities ⁽¹⁾	$	6
PG&E NEG
Trading activities	3
Non-trading activities:
Non-trading contracts that receive mark-to-market accounting treatment ⁽²⁾	2
Non-trading contracts accounted for as hedges ⁽³⁾	19


Exhibit 4.1	Supplemental Indenture related to PG&E Corporation's 9.50 percent Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee
Exhibit 4.2	Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto
Exhibit 10.1	Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.1)
Exhibit 10.2	Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.2)
Exhibit 10.3	Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.3)
Exhibit 10.4	Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.4)
Exhibit 10.5	Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.5)
Exhibit 11	Computation of Earnings Per Common Share
Exhibit 12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
Exhibit 12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
Exhibit 99.1	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
Exhibit 99.2	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

1. July 2, 2002	Item 5.	Other Events
		A.	Pacific Gas and Electric Company Bankruptcy: Monthly Operating Report
		B.	Dismissal of Federal Securities Lawsuit
		C.	Motion to Extend Exclusivity Period
		D.	Nuclear Regulatory Commission Ruling
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
		Exhibit 99 - Pacific Gas and Electric Company Income Statement for the month
		Ended May 31, 2002, and Balance Sheet dated May 31, 2002

2. July 29, 2002	Item 5.	Other Events
		A.	Recovery of Wholesale Power Purchase Costs

3. August 2, 2002	Item 9.	Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit No. 99.1 - Statement Under Oath of principal executive officer Robert D. Glynn, Jr. dated August, 1, 2002
			Exhibit No. 99.2 - Statement Under Oath of principal financial officer Peter A. Darbee dated August 1, 2002

4. August 6, 2002	Item 5.	Other Events
		A.	PG&E Corporation Credit Agreement and PG&E National Energy Group, Inc. credit ratings downgrades
		B.	Pacific Gas and Electric Company bankruptcy

5. August 19, 2002	Item 5.	Other Events
		A.	PG&E Corporation Credit Agreement waiver extension
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit 99.1 - Waiver and Amendment Agreement, dated August 16, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc., as administrative agent, and the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

6. August 26, 2002	Item 5.	Other Events
		A.	PG&E Corporation Credit Agreement waiver revision
		B.	Extension of PG&E National Energy Group credit facility expiration date
		C.	PG&E NEG projected cash management-potential sources and uses of cash table
		D.	Pacific Gas and Electric Company bankruptcy
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit 99.1 - Waiver and Amendment Agreement, dated August 22, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

7. September 3, 2002 -	Item 5.	Other Events
PG&E Corporation only
		A.	Voluntary prepayment of loan to General Electric Capital Corporation
		B.	New waiver extension from remaining lenders
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit 99 - Second Amended and Restated Waiver and Amendment Agreement, dated August 30, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and certain of the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002

8. September 4, 2002	Item 5.	Pacific Gas and Electric Company bankruptcy
		A.	District Court ruling in favor of PG&E Corporation's and Pacific Gas and Electric Company's express preemption argument
		B.	Monthly Operating Report
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit 99 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2002, and Balance Sheet dated July 31, 2002

9. September 10, 2002	Item 5.	Pacific Gas and Electric Company Bankruptcy
		A.	Voting results
		B.	Request to re-solicit votes; complaint regarding solicitation

10. October 3, 2002	Item 5.	Other Events
		A.	PG&E Corporation-new waiver extension
		B.	Pacific Gas and Electric Company bankruptcy: Monthly Operating Report
	Item 7.	Financial Statements, Pro Forma, Financial Information, and Exhibits
			Exhibit 99.1 - Amendment to Second Amended and Restated Waiver and Amendment Agreement, dated October 1, 2002, by and among PG&E Corporation, PG&E National Energy Group, LLC, Lehman Commercial Paper Inc. as administrative agent, and certain of the lenders party to the Amended and Restated Credit Agreement dated as of June 25, 2002
			Exhibit 99.2 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2002, and Balance Sheet dated August 31, 2002

11. October 10, 2002 -	Item 5.	Other Events
PG&E Corporation only
		A.	PG&E National Energy Group, Inc. credit ratings downgrades

12. October 15, 2002	Item 5.	Other Events
		A.	Pacific Gas and Electric Company's 2003 Cost of Capital Proceeding
		B.	Pacific Gas and Electric Company bankruptcy

13. October 21, 2002 -	Item 5.	Other Events
PG&E Corporation only
		A.	PG&E National Energy Group credit ratings downgrades

14. October 22, 2002 -	Item 5.	Other Events
PG&E Corporation only
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
			Exhibit 99.1 - Second and Amended Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, the lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties
			Exhibit 99.2 - Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002
			Exhibit 99.3 - Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002
			Exhibit 99.4 - Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002
			Exhibit 99.5 - Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002

Exhibit No.	Description of Exhibit
Exhibit 4.1	Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee

Exhibit 4.2	Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto

Exhibit 10.1	Second Amended and Restated Credit Agreement, dated as of October 18, 2002, among PG&E Corporation, as Borrower, the Lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and other parties (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.1)

Exhibit 10.2	Utility Stock Pledge Agreement (35 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.2)

Exhibit 10.3	Utility Stock Pledge Agreement (35 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.3)

Exhibit 10.4	Utility Stock Pledge Agreement (65 percent) - Continued Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.4)

Exhibit 10.5	Utility Stock Pledge Agreement (65 percent) - New Tranche B Loan, dated as of October 18, 2002 (incorporated by reference to PG&E Corporation's Current Report on Form 8-K filed October 22, 2002, Exhibit 99.5)

Exhibit 11	Computation of Earnings Per Common Share

Exhibit 12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

Exhibit 12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

Exhibit 99.1	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

Exhibit 99.2	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