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~~June~~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 ~~_____v___________~~______________ to _______________ Commission File Number 1-5532-99

	PORTLAND GENERAL ELECTRIC COMPANY
	(Exact name of registrant as specified in its charter)

Oregon		93-0256820
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)


	121 SW Salmon Street, Portland, Oregon 97204
	(Address of principal executive offices) (zip code)

Registrant's telephone number, including area code:(503) 464-8000

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

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of ~~July~~October 31, 2002: 42,758,877 shares of Common Stock, $3.75 par value. (All shares are owned by Enron Corp.)

Table of Contents

		Page Number
Definitions		3

Part I. Financial Information

	Item 1. Financial Statements

	Consolidated Statements of Income	4
	Consolidated Statements of Retained Earnings	4
	Consolidated Statements of Comprehensive Income	5
	Consolidated Balance Sheets	6
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8

	Item 2. Management's Discussion and Analysis of
	Financial Condition and Results of Operations	2426

	Item 3. Quantitative and Qualitative Disclosures
	About Market Risk	4755

	Item 4. Controls and Procedures	57

Part II. Other Information

	Item 1. Legal Proceedings	4958
	Item 5. Other Information	5059
	Item 6. Exhibits and Reports on Form 8-K	5260
	Signature Page	5361
	Certifications	62

Definitions

BPA

Bonneville Power Administration

Bankruptcy Court

United States Bankruptcy Court For The Southern District of New York

COBRA

Consolidated Omnibus Budget Reconciliation Act

CUB

Citizens' Utility Board

DEQ

Oregon Department of Environmental Quality

Enron

Enron Corp., as Debtor and Debtor in Possession in Chapter 11, Case No. 01-16034 pending in the US Bankruptcy Court For The Southern District of New York

EPA

Environmental Protection Agency

ERISA

Employee Retirement Income Security Act

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

IRS

Internal Revenue Service

kWh

Kilowatt-Hour

Mill

One tenth of one cent

MWh

Megawatt-hour

NW Natural

Northwest Natural Gas Company

NYMEX

New York Mercantile Exchange

OPUC ~~or the Commission~~

Oregon Public Utility Commission

PBGC

Pension Benefit Guaranty Corporation

PGC

Portland General Corporation

PGE or the Company

Portland General Electric Company

SFAS

Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board

Trojan

Trojan Nuclear Plant

Unsecured Creditors' Committee

Enron Unsecured Creditors' Committee

URP

Utility Reform Project

VEBA

Voluntary Employee Beneficiary Association

WSCC

Western Systems Coordinating Council

WTC

World Trade Center

PART I

Financial Information

Item 1. Financial Statements

Portland General Electric Company and Subsidiaries Consolidated Statements of Income (Unaudited)	Portland General Electric Company and Subsidiaries Consolidated Statements of Income (Unaudited)																					Portland General Electric Company and Subsidiaries Consolidated Statements of Income (Unaudited)
		Three Months Ended June 30,													Six Months Ended June 30,								Three Months Ended September 30,													Nine Months Ended September 30,
			2002							2001						2002				2001				2002							2001						2002				2001
			(In Millions)																					(In Millions)

Operating Revenues	Operating Revenues	$	553	$				831			$				1,093			$			1,597	Operating Revenues	$	458	$				480			$				1,361			$			1,777

Operating Expenses	Operating Expenses																					Operating Expenses
	Purchased power and fuel		383						636						716						1,214	Purchased power and fuel		311						381						837						1,295
	Production and distribution		32						36						60						60	Production and distribution		28						29						88						89
	Administrative and other		33						37						71						65	Administrative and other		33						30						104						95
	Depreciation and amortization		39						41						81						86	Depreciation and amortization		39						29						120						115
	Taxes other than income taxes		16						17						36						34	Taxes other than income taxes		17						15						53						49
	Income taxes		17						21						45						45	Income taxes		6						(15)						51						30
			520						788						1,009						1,504			434						469						1,253						1,673

Net Operating Income	Net Operating Income		33						43			1			84						93	Net Operating Income		24						11						108						104

Other Income (Deductions)	Other Income (Deductions)																					Other Income (Deductions)
	Miscellaneous		(3)						4						(1)						2	Miscellaneous		(2)						-						(3)						2
	Income taxes		3						-						4						2	Income taxes		2						2						6						4
			-						4						3						4			-						2						3						6

Interest Charges	Interest Charges																					Interest Charges
	Interest on long-term debt and other		15						18						32						36	Interest on long-term debt and other		16						16						48						52
	Interest on short-term borrowings		2						-						3						-	Interest on short-term borrowings		-						2						3						2
			17						18						35						36			16						18						51						54

Net income before cumulative effect of a change in	Net income before cumulative effect of a change in																					Net income before cumulative effect of a change in
accounting principle	accounting principle		16						29						52						61	accounting principle		8						(5)						60						56
Cumulative effect of a change in accounting principle,	Cumulative effect of a change in accounting principle,																					Cumulative effect of a change in accounting principle,
net of related taxes of $(6)	net of related taxes of $(6)		-						-						-						11	net of related taxes of $(6)		-						-						-						11

Net Income	Net Income		16						29						52						72	Net Income		8						(5)						60						67

Preferred Dividend Requirement	Preferred Dividend Requirement		-						-						1						1	Preferred Dividend Requirement		1						1						2						2

Income Available for Common Stock	Income Available for Common Stock	$	16		$				29			$			51			$			71	Income Available for Common Stock	$	7		$				(6)			$			58			$			65
Portland General Electric Company and Subsidiaries Consolidated Statement of Retained Earnings (Unaudited)
Portland General Electric Company and Subsidiaries Consolidated Statements of Retained Earnings (Unaudited)																						Portland General Electric Company and Subsidiaries Consolidated Statements of Retained Earnings (Unaudited)

		Three Months Ended June 30,												Six Months Ended June 30,									Three Months Ended September 30,												Nine Months Ended September 30,
			2002			2001							2002						2001					2002			2001							2002						2001
			(In Millions)																					(In Millions)

Balance at Beginning of Period	Balance at Beginning of Period	$	486		$		481				$			451			$			459		Balance at Beginning of Period	$	502		$		490				$			451			$			459
Net Income	Net Income		16				29							52							72	Net Income		8				(5)							60							67
			502				510							503							531			510				485							511							526

Dividends Declared	Dividends Declared																					Dividends Declared
	Common stock		-				20							-							40	Common stock (non-cash dividend in 2002)		27				-							27							40
	Preferred stock		-				-							1							1	Preferred stock		1				1							2							2
			-				20							1							41			28				1							29							42
Balance at End of Period	Balance at End of Period	$	502		$		490				$5			502				$			490	Balance at End of Period	$	482		$		484				$			482				$			484
																																											The accompanying notes are an integral part of these consolidated financial statements.

Portland General Electric Company and Subsidiaries

Consolidated Statements of Comprehensive Income

(Unaudited)

				Three Months					Six Months						Three Months					Nine Months
				Ended					Ended						Ended					Ended
				June 30,					June 30,						September 30,					September 30,
				2002		2001		2002			2001				2002		2001		2002			2001
				(In Millions)											(In Millions)

Accumulated other comprehensive income (loss) - Beginning of Period	Accumulated other comprehensive income (loss) - Beginning of Period		$	(2)	$	31	$	(2)		$	-	Accumulated other comprehensive income (loss) - Beginning of Period		$	(2)	$	(12)	$	(2)		$	-

Net Income	Net Income		$	16	$	29	$	52		$	72	Net Income		$	8	$	(5)	$	60		$	67

Other comprehensive income, net of tax:	Other comprehensive income, net of tax:											Other comprehensive income, net of tax:
	Unrealized gains (losses) on derivatives classified as cash flow hedges:											Unrealized gains (losses) on derivatives classified as cash flow hedges:
		Unrealized holding gain due to cumulative effect of change in											Unrealized holding gain due to cumulative effect of change in
		accounting principle, net of related taxes of ($23)		-		-		-			35		accounting principle, net of related taxes of ($23)		-		-		-			35
		Other unrealized holding net gains (losses) arising during the period,											Other unrealized holding net gains (losses) arising during the period,
		net of related taxes of $2 and $30 for the three months ended											net of related taxes of ($1) and $10 for the three months ended
		June 30, 2002 and 2001 and ($1) and $27 for the six months											September 30, 2002 and 2001 and ($2) and $36 for the nine
		ended June 30, 2002 and 2001		(3)		(45)		2			(41)		months ended September 30, 2002 and 2001		2		(15)		4			(56)
		Reclassification adjustment for contract settlements included in											Reclassification adjustment for contract settlements included in
		net income, net of related taxes of $1 and $7 for the three											net income, net of related taxes of ($1) for the three months
		months and six months ended June 30, 2001		-		(2)		-			(10)		ended September 30, 2002 and ($1) and $8 for the nine months
		Reclassification adjustment in net income due to discontinuance											ended September 30, 2002 and 2001		1		-		1			(10)
		of cash flow hedges, net of related taxes or ($3) for the three											Reclassification adjustment in net income due to discontinuance
		months and six months ended June 30, 2001		-		4		-			4		of cash flow hedges, net of related taxes of ($10) and ($12) for
		Reclassification of unrealized (gains) losses to FAS 71 regulatory											the three months and nine months ended September 30, 2001		-		15		-			19
		liability, net of related taxes of ($2) and $1 for the three											Reclassification of unrealized (gains) losses to FAS 71 regulatory
		months and six months ended June 30, 2002		3		-		(2)			-		(liability) asset, net of related taxes of $2 and ($8) for the three
		Total Other comprehensive income (loss)		-		(43)		-			(12)		months ended September 30, 2002 and 2001 and $3 and ($8) for
													the nine months ended September 30, 2002 and 2001		(3)		12		(5)			12
													Total Other comprehensive income (loss)		-		12		-			-

Comprehensive income	Comprehensive income		$	16	$	(14)	$	52		$	60	Comprehensive income		$	8	$	7	$	60		$	67

Accumulated other comprehensive income (loss) - End of Period	Accumulated other comprehensive income (loss) - End of Period		$	(2)	$	(12)	$	(2)		$	(12)	Accumulated other comprehensive income (loss) - End of Period		$	(2)	$	-	$	(2)		$	-

The accompanying notes are an integral part of these consolidated financial statements.

Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)	Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)						Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)
				June 30,		December 31,				September 30,		December 31,
				2002		2001				2002		2001
				(In Millions)						(In Millions)
Assets	Assets						Assets
Electric Utility Plant - Original Cost	Electric Utility Plant - Original Cost						Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $126 and $97)		$	3,635	$	3,596	Utility plant (includes construction work in progress of $93 and $97)		$	3,676	$	3,596
	Accumulated depreciation			(1,705)		(1,643)	Accumulated depreciation			(1,746)		(1,643)
				1,930		1,953				1,930		1,953
Other Property and Investments	Other Property and Investments						Other Property and Investments
	Receivable from parent (less allowance for uncollectible accounts of $77 and $74)			-		-	Receivable from parent (less allowance for uncollectible accounts of $79 and $74)			-		-
	Nuclear decommissioning trust, at market value			32		30	Nuclear decommissioning trust, at market value			31		30
	Trust owned life insurance			76		81	Trust owned life insurance			66		81
	Note receivable - Pelton Round Butte project sale			23		-	Note receivable - Pelton Round Butte project sale			21		-
	Miscellaneous			30		35	Miscellaneous			31		35
				161		146				149		146
Current Assets	Current Assets						Current Assets
	Cash and cash equivalents			39		8	Cash and cash equivalents			41		8
	Accounts and notes receivable (less allowance for uncollectible accounts of $29 and $29)			244		272	Accounts and notes receivable (less allowance for uncollectible accounts of $25 and $29)			233		272
	Contract termination receivable			13		28	Contract termination receivable			5		28
	Unbilled and accrued revenues			63		80	Unbilled and accrued revenues			58		80
	Power cost mechanism			31		-	Unamortized regulatory asset - power cost mechanism			26		-
	Assets from price risk management activities			137		170	Assets from price risk management activities			82		170
	Inventories, at average cost			49		44	Inventories, at average cost			46		44
	Margin deposits			25		89	Margin deposits			-		89
	Prepayments and other			81		78	Prepayments and other			100		78
	Deferred income taxes			9		6	Deferred income taxes			11		6
				691		775				602		775
Deferred Charges	Deferred Charges						Deferred Charges
	Unamortized regulatory assets			554		582	Unamortized regulatory assets			528		582
	Miscellaneous			20		18	Miscellaneous			18		18
				574		600				546		600
			$	3,356	$	3,474			$	3,227	$	3,474
Capitalization and Liabilities	Capitalization and Liabilities						Capitalization and Liabilities
Capitalization	Capitalization						Capitalization
	Common stock equity						Common stock equity
		Common stock, $3.75 par value per share, 100,000,000						Common stock, $3.75 par value per share, 100,000,000
		shares authorized; 42,758,877 shares outstanding	$	160	$	160		shares authorized; 42,758,877 shares outstanding	$	160	$	160
		Other paid-in capital - net		481		481		Other paid-in capital - net		481		481
	Retained earnings			502		451	Retained earnings			482		451
	Accumulated other comprehensive income (loss)			(2)		(2)	Accumulated other comprehensive income (loss)			(2)		(2)
	Cumulative preferred stock subject to mandatory redemption			27		29	Cumulative preferred stock subject to mandatory redemption			27		29
	Long-term obligations			622		769	Limited voting junior preferred stock			-		-
				1,790		1,888	Long-term obligations			579		769
										1,727		1,888
Commitments and Contingencies (Notes 4-8)

Commitments and Contingencies (Notes 3-7)							Commitments and Contingencies (Notes 3-7)

Current Liabilities	Current Liabilities						Current Liabilities
	Long-term debt due within one year			301		173	Long-term debt due within one year			341		173
	Preferred stock maturing within one year			1		1	Preferred stock maturing within one year			1		1
	Short-term borrowings			135		174	Short-term borrowings			70		174
	Accounts payable and other accruals			193		250	Accounts payable and other accruals			209		250
	Liabilities from price risk management activities			160		196	Liabilities from price risk management activities			99		196
	Customer deposits			5		5	Customer deposits			5		5
	Accrued interest			14		13	Accrued interest			13		13
	Dividends payable			1		1	Dividends payable			1		1
	Accrued taxes			13		15	Accrued taxes			44		15
	Unamortized regulatory liabilities			16		42	Unamortized regulatory liabilities			-		42
				839		870				783		870
Other	Other						Other
	Deferred income taxes			379		339	Deferred income taxes			383		339
	Deferred investment tax credits			21		23	Deferred investment tax credits			20		23
	Trojan decommissioning and transition costs			194		205	Trojan decommissioning and transition costs			187		205
	Unamortized regulatory liabilities			26		44	Unamortized regulatory liabilities			19		44
	Nonqualified benefit plan liabilities			62		62	Nonqualified benefit plan liabilities			59		62
	Miscellaneous			45		43	Miscellaneous			49		43
				727		716				717		716
			$	3,356	$	3,474			$	3,227	$	3,474
													The accompanying notes are an integral part of these consolidated financial statements.

Portland General Electric Company and Subsidiaries Consolidated Statements of Cash Flows (Unaudited)	Portland General Electric Company and Subsidiaries Consolidated Statements of Cash Flows (Unaudited)						Portland General Electric Company and Subsidiaries Consolidated Statements of Cash Flows (Unaudited)
				Six Months Ended						Nine Months Ended
				June 30,						September 30,
				2002		2001				2002		2001
				(In Millions)						(In Millions)

Cash Flows From Operating Activities:	Cash Flows From Operating Activities:						Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities	Reconciliation of net income to net cash provided by operating activities						Reconciliation of net income to net cash provided by operating activities
	Net income		$	52	$	72	Net income		$	60	$	67
	Non-cash items included in net income:						Non-cash items included in net income:
		Cumulative effect of a change in accounting principle, net of tax		-		(11)		Cumulative effect of a change in accounting principle, net of tax		-		(11)
		Depreciation and amortization		81		86		Depreciation and amortization		120		115
		Deferred income taxes		44		1		Deferred income taxes		47		9
		Net change from price risk management activities		2		(33)		Net assets from price risk management activities		(1)		47
		Power cost adjustment		(26)		-		Power cost adjustment		(15)		(90)
		Other non-cash income and expenses (net)		(30)		-		Other non-cash income and expenses (net)		(27)		-
	Changes in working capital:						Changes in working capital:
		Net margin deposit activity		64		(188)		Net margin deposit activity		89		(199)
		(Increase) decrease in receivables		45		(26)		(Increase) decrease in receivables		34		(36)
		Increase (decrease) in payables		(58)		1		Increase (decrease) in payables		(12)		23
		Other working capital items - net		(8)		(15)		Other working capital items - net		(24)		(37)
	Other - net			(2)		3	Other - net			-		2
Net Cash Provided by (Used in) Operating Activities	Net Cash Provided by (Used in) Operating Activities			164		(110)	Net Cash Provided by (Used in) Operating Activities			271		(110)

Cash Flows From Investing Activities:	Cash Flows From Investing Activities:						Cash Flows From Investing Activities:
	Capital expenditures			(75)		(106)	Capital expenditures			(117)		(149)
	Other - net			3		14	Other - net			9		9
Net Cash Used in Investing Activities	Net Cash Used in Investing Activities			(72)		(92)	Net Cash Used in Investing Activities			(108)		(140)

Cash Flows From Financing Activities:	Cash Flows From Financing Activities:						Cash Flows From Financing Activities:
	Net increase (decrease) in short-term borrowings			(39)		188	Net increase (decrease) in short-term borrowings			(104)		285
	Repayment of long-term debt			(19)		(4)	Repayment of long-term debt			(22)		(51)
	Preferred stock retired			(2)		-	Preferred stock retired			(2)		-
	Dividends paid			(1)		(41)	Dividends paid			(2)		(42)
Net Cash Provided by (Used in) Financing Activities	Net Cash Provided by (Used in) Financing Activities			(61)		143	Net Cash Provided by (Used in) Financing Activities			(130)		192

Increase (Decrease) in Cash and Cash Equivalents	Increase (Decrease) in Cash and Cash Equivalents			31		(59)	Increase (Decrease) in Cash and Cash Equivalents			33		(58)
Cash and Cash Equivalents, Beginning of Period	Cash and Cash Equivalents, Beginning of Period			8		60	Cash and Cash Equivalents, Beginning of Period			8		60
Cash and Cash Equivalents, End of Period	Cash and Cash Equivalents, End of Period		$	39	$	1	Cash and Cash Equivalents, End of Period		$	41	$	2

Supplemental disclosures of cash flow information	Supplemental disclosures of cash flow information						Supplemental disclosures of cash flow information
	Cash paid during the period:						Cash paid during the period:
		Interest, net of amounts capitalized	$	31	$	31		Interest, net of amounts capitalized	$	46	$	48
		Income taxes		2		35		Income taxes		2		35

Supplemental disclosure of non-cash financing activity							Supplemental disclosure of non-cash financing activity
								Non-cash dividend to parent	$	27	$	-

The accompanying notes are an integral part of these consolidated financial statements.

Notes to Consolidated Financial Statements (Unaudited)

Note 1 - Principles of Interim Statements

The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim periods presented. Such statements, which are unaudited, are presented in accordance with the SEC's interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received or activity associated with the interim period; accordingly, such costs are subject to year-end adjustment. It is ~~PGE's~~management's opinion that, when the interim statements are read in conjunction with the 2001 Annual ~~Report~~Rep ort on Form 10-K and the other reports filed with the Securities and Exchange Commission since its 2001 Form 10-K was filed, the disclosures are adequate to make the information presented not misleading.

Reclassifications - Certain amounts in prior years have been reclassified for comparative purposes. These reclassifications had no material effect on PGE's previously reported consolidated financial position, results of operations, or cash flows.

Note 2 - Price Risk Management

PGE ~~engages in non-trading~~utilizes derivative instruments, including electricity forward and ~~trading activities by utilizing derivative financial instruments~~option, and natural gas forward and swap contracts, in its retail (non-trading) electric utility ~~business.~~business to manage its exposure to commodity price risk and endeavor to minimize net power costs for its retail customers, and in its trading electric utility business to take advantage of price movements in electricity and natural gas. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), which the Company adopted on January 1, 2001, derivative instruments are recorded on the Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings, ~~(in Purchased power and fuel),~~ unless specific hedge accounting criteria are met. ~~As contracts settle, sales are recorded in Operating revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel on the Statement of Income.~~ Upon adoption of SFAS No. 133, PGE recorded after-tax gains of $11 million and $35 million in earnings and Other Comprehensive Income (OCI), respectively, from the cumulative effect of a change in accounting principle.

For retail (non-trading) activities, changes in fair value of derivative instruments prior to settlement are recorded net in Purchased power and fuel. As these derivative instruments are settled, sales are recorded in Operating revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel.

For energy trading activities, Emerging Issues Task Force (EITF) Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, which became effective in the third quarter of 2002, requires that all unrealized and realized gains and losses associated with "energy trading activities" be reported on a net basis. EITF Issue 02-3 also requires that the comparative financial statements for prior periods be reclassified to conform to the new presentation. As a result, PGE is now required to record unrealized and realized gains and losses from trading activities on a net basis as a component of Operating revenues. Previously, PGE had recorded unrealized gains and losses from trading activities on a net basis in Purchased power and fuel. As power trading contracts were settled, PGE recorded, on a gross basis, sales in Operating revenues and purchases in Purchased power and fuel. In addition, PGE has reclassified its prior period financial statements to meet the requirements of EITF Issue 02-3.

Special accounting for qualifying hedges allows ~~a derivative's~~ gains and losses on a derivative instrument to be recorded in OCI until they can offset the related results on the hedged item in the income statement. As discussed below, the effects of changes in the fair value of derivative instruments entered into to hedge the company's future non-trading retail resource requirements are subject to regulation and are deferred pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

Non-Trading Activities

As PGE's primary business is to serve its retail customers, it ~~enters into~~uses derivative instruments, including electricity forward and option, and natural gas forward and swap contracts to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers. Effective October 1, 2001, PGE's base rates changed as a result of an OPUC general rate order. The new rates reflect an update of PGE's net variable power costs to include electricity and natural gas contracts, including derivative instruments, that will settle over the 15-month period ended December 31, 2002. In addition, the OPUC approved a 15-month power cost adjustment mechanism, effective October 1, 2001, ~~to mitigate~~by which the ~~Company's~~Company shares with retail customers its risk of exposure to ~~risk from~~ power and natural gas price volatility. Such mechanism provides an incentive for the Company to continue to actively manage resources it has procured to serve its retail load and reduce retail power costs over the 15-month period October 1, 2001 to December 31, 2002. The mechanism provides that PGE recover from or refund to customers a portion of the difference in changes in power costs and energy revenues from baseline amounts as a result of ~~continuing~~continuin g management of its resources and changes in the forecasted load. At the end of 2002, any balance for collection or refund will be subject to ~~OPUC approval.~~disposition by the OPUC. Each year thereafter, PGE will provide updates of its net variable power costs to the OPUC for inclusion in base rates for the following year. PGE has received an OPUC order related to an update of its net variable power costs for inclusion in base rates for 2003, with new prices to become effective January 1, 2003.

SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. OPUC-approved rates are based on the value of all the Company's resources, including non-trading derivative instruments, that will settle during the 15-month period from October 1, 2001 to December 31, 2002. The timing difference between the recognition of gains and losses on derivative instruments and their realization and subsequent collection in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. As a result, in the third quarter of 2001, PGE began recording a regulatory asset or regulatory liability pursuant to SFAS No. 71 to offset the effects of unrealized gains and losses from changes in fair values of ~~these contracts~~the derivative instruments recorded prior to settlement. As ~~contracts~~these derivative instruments are ~~settled,~~set tled, the regulatory asset or regulatory ~~lia bility~~liability is reversed. ~~PGE recorded in~~In the first ~~half~~nine months of 2002 and 2001, PGE recorded net unrealized gains of $1$5 million and $6net unrealized losses of $8 million, respectively, in earnings on natural gas swaps in its retail portfolio, including net gains of ~~$5 million and $7~~$4 million in the ~~second~~third quarter of 2002 and net losses of $31 million in third quarter of 2001. The earnings effects in 2002 ~~gains~~and 2001 were fully offset by the recording of a SFAS No. 71 regulatory asset and liability. However, beginning in 2003, PGE will no longer record a SFAS No. 71 regulatory asset or liability for contracts that will settle in 2003 since there will be no power cost adjustment mechanism in place.

Derivative activities in OCI for the ~~three- and six-month periods~~nine-month period ended ~~June~~September 30, 2002 from cash flow hedges consist of $6 million net unrealized gains in new contracts and changes in fair value, $2 million in net losses reclassified to earnings for contracts that settled during the period, and $3zero for the discontinuance of cash flow hedges due to the probability that the original forecasted transactions will not occur. For the comparative nine-month period ended September 30, 2001, there were $34 million net unrealized losses in new contracts and changes in fair values, $18 million in net gains ~~respectively,~~was reclassified to earnings for contracts that settled during the period and $31 million net losses were discontinued and reversed to Purchased power and fuel. In both years, the entire amount of OCI was fully offset by the recording of a SFAS No. 71 regulatory ~~liability. For the comparative three-~~asset and six-month periods ended June 30, 2001, $75 million and $67 million net unrealized losses, respectively, in new contracts and changes in fair values were recognized in OCI; in addition, $4 million and $17 million net gains, respectively, were reclassified to earnings from OCI for contracts that settled during the 2001 periods.liability. No amounts were reclassified into earnings as a result of hedge ineffectiveness in the first ~~half~~nine months of 2002 or 2001. ~~Cash flow hedges~~A s of zero and $7 million losses were discontinued and reversed to Purchased power and fuel during the first half of 2002 and 2001, respectively, due to the probability that the original forecasted transactions will not occur. As of J uneSeptember 30, 2002, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 2118 months. The Company estimates that of the $1$6 million of net unrealized gains at ~~June~~September 30, 2002, a $1$5 million ~~loss~~gain will be reclassified into earnings within the next twelve months, ~~with~~and a $2$1 million gain towill be reclassified over the remaining ~~other nine~~six months.

New Accounting Guidance - On December 19, 2001, the FASB approved the interpretations issued by the Derivatives Implementation Group (DIG) that are outlined in SFAS No. 133 Implementation Issues No. 15, Scope Exceptions: Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, and No. C16, Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract. Under Issue No. C15, the FASB included "clearly and closely related" pricing requirements for contracts to qualify for the normal purchases and normal sales exception. Issue No. C16 disallows normal purchases and normal sales treatment for commodity contracts (except as provided in Issue No. C15 with respect to certain power purchase or sales agreements) that contain volumetric variability or optionality. Such interpretations and guidance became effective April 1, 2002. PGE determined that there was no material impact of implementing this guidance on its financial statements.

Trading Activities

PGE trading activities utilize electricity forward and option contracts and natural gas forward, swap and futures contracts to take advantage of price movements in electricity and natural gas. Such activities are not ~~subject to regulation. In the first half of 2002, PGE recorded~~reflected in earnings $2 million in unrealized losses that were offset by $2 million in realized gains from trading activities. In the first half of 2001, PGE recorded in earnings an $11 million loss from trading activities, comprised of $27 million in unrealized gains and $38 million in realized losses. In the second quarter of 2002, PGE recorded in earnings $1 million in realized gains from trading activities,PGE's retail prices. As indicated above, beginning with unrealized gains and losses netting to zero. In the second quarter of 2001, PGE recorded in earnings an $11 million loss from trading activities, comprised of $14 million in unrealized gains and $25 million in realized losses.

Emerging Issues Task Force Issue- The Emerging Issues Task Force (EITF) of the FASB recently reached a consensus in Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, regarding financial statement presentation of revenues and expenses associated with "energy trading contracts". The EITF requires that, effective for the third quarter of 2002, ~~such revenues~~all unrealized and ~~expenses~~realized gains and losses associated with "energy trading activities" are to be reported on a net basis for all periods presented. PGE has historically presented such activities on a gross basis as contracts are settled, with sales recorded in Operating revenues and power purchases recorded in Purchased power and fuel expense.

~~PGE continues to evaluate the financial statement reclassification required by~~under EITF Issue ~~No.~~ 02-3. ~~PGE believes~~Amounts included in the comparative financial statements for the prior periods in 2001 have been reclassified to conform to the new presentation.

The following table indicates unrealized and realized gains and losses on electricity and gas trading activities for the three-month and nine-month periods ended September 30, 2002 and 2001:

	Trading Activities
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	(In Millions)
	2002		2001		2002		2001
Unrealized Gain (Loss)	$	(2)	$	(49)	$	(4)	$	(22)
Realized Gain (Loss)		1		51		3		13
Net Gain (Loss) in Operating Revenues	$	(1)	$	2	$	(1)	$	(9)

The following table indicates the transaction volumes for electricity trading contracts that ~~implementation of~~physically settled in the ~~consensus in EITF Issue No. 02-3 will likely have a material impact on total revenues~~three-month and ~~expenses, but will have no impact on its financial condition or results of operations.~~nine-month periods ended September 30, 2002 and 2001:

	Electricity Trading
	Megawatt-Hours (thousands)
	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2002	2001	2002	2001
Sales	2,774	1,498	8,761	2,695
Purchases	2,774	1,488	8,761	2,681

Note 3 ~~- Termination of Proposed Acquisition of PGE by NW Natural~~

On May 17, 2002, Enron and NW Natural entered into a Termination Agreement in which they agreed to terminate the Stock Purchase Agreement to sell PGE to NW Natural. The Termination Agreement was subject to, and effective upon, approval of the Bankruptcy Court and the consent of the lenders from whom Enron has obtained debtor-in-possession financing, both of which have been obtained. The Termination Agreement also provides for mutual releases from any legal action associated with the Stock Purchase Agreement.

~~Note 4~~ - Legal and Environmental Matters

Trojan Investment Recovery -In 1993, PGE sought full recovery of and a rate of return on its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. The filing was a result of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals and requested reviews have been filed in Marion County, Oregon Circuit Court, Oregon Court of Appeals and with the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of and a return on the Trojan investment. The primary plaintiffs in the litigation are the Citizens' Utility Board (CUB) and the Utility Reform Project (URP). Rulings issued to date by the Circuit Court and the Court of Appeals have been inconsistent on the issue. The Court of Appeals issued the latest ruling in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upheld the OPUC's authorization of PGE's recovery of the Trojan investment. PGE and the OPUC requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision on the return on investment issue. In addition, URP requested the Oregon Supreme Court to review the Court of Appeals decision on the return of investmen t issue. ~~The Supreme Court has indicated it will conduct a review.~~

In 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of its investment in the Trojan plant. Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and about $80 million of the remaining obligation under terms of the Enron/PGC merger. The settlement also ~~allows~~allowed PGE ~~recovery of~~to recover approximately $47 million in income tax benefits related to the Trojan investment which had been flowed through to customers in prior years; such amount is presently being recovered from PGE customers, with no return on the unamortized balance, over an approximate five year ~~period.~~period, which began in October 2000. After offsetting the investment in Trojan with ~~these~~the credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was ~~expensed.~~expensed in the third quarter of 2000. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. ~~The URP challenged the settlement agreements and the OPUC order.~~ Collection of decommissioning costs at Trojan is unaffected by the settlement agreements or the OPUC order. The URP challenged the settlement agreements and the OPUC rate order implementing such agreements.

PGE ~~had~~ requested the Oregon Supreme Court to hold in abeyance ~~its~~the review of the Court of Appeals decision that had been requested by PGE and URP, pending resolution of URP's complaint with the OPUC challenging PGE's application for approval of the accounting and ratemaking elements of the settlement agreements approved by the ~~Commission on~~OPUC in September ~~29,~~ 2000. On March 25, 2002, the OPUC issued an order denying all of URP's challenges, and approving PGE's application of the accounting and ratemaking elements of the settlement. On May 29, 2002, URP appealed the OPUC's decision to the Multnomah County Circuit Court, and on

June 4, 2002, URP also filed in Marion County Circuit Court. On July 1, 2002, PGE filed with the Oregon Supreme Court a Notice of Mootness and Motion to Dismiss and Vacate the ~~Case.~~Case to terminate the review of the Court of Appeals decision sought by URP and PGE. On October 17, 2002, URP filed in Marion County a Motion for Continuance to allow defendants more time to appeal. In the Motion, they indicated that they planned to move forward in Marion County and not in Multnomah County. On October 30, 2002, the OPUC filed its answer in this proceeding in Marion County.

Management cannot predict the ultimate outcome of the above litigation. However, it believes this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for a future reporting period.

Union Grievances - Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enron, n ot PGE. The IBEW filed an answer and counterclaim that the issue is arbitrable, and PGE filed a reply which denied the counterclaim and raised four affirmative defenses. ~~It is not likely that~~The Circuit Court set a ~~hearing on these motions and counterclaim will take place before the fall~~trial date of ~~2002.~~May 22, 2003. No reserves have been established by PGE for any amounts related to this issue. Management cannot predict the ultimate outcome of these grievances.

Other Legal Matters - PGE is party to various other claims, legal actions and complaints arising in the ordinary course of business. ~~These claims are~~The Company does not ~~material.~~believe that these matters will have a material adverse impact on the financial condition or results of operations of the Company. In addition, PGE has been requested to provide information and documents with respect to various federal and state actions and investigations of Enron.

Environmental Matter - A 1997 investigation of a 5.5 mile segment of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ~~("Superfund")~~(Superfund) in 2000.

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" ~~(Voluntary~~(the Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement. ~~Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.~~

In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice included a "Portland Harbor Initial General Notice List" containing sixty-eight other companies that the EPA believes may be Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

In accordance with the Voluntary Agreement, in March 2001, PGE submitted a final ~~study~~investigation plan to the DEQ for ~~approval, with testing initiating~~approval. DEQ approved the plan and in June ~~2001.~~2001 PGE ~~has~~ performed initial investigations and remedial activities based upon the approved ~~study~~investigation plan. The investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

In February 2002, PGE submitted a final investigation report to the DEQ summarizing its ~~pre-remedial~~ investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette River because no likely sources of hazardous substance releases were identified. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE.

Although management does not believe it has any responsibility for contamination of the Portland Harbor, it cannot predict the ultimate outcome of this matter or estimate any possible loss.

Note 54 - Related Party Transactions

The tables below detail the Company's related party balances and transactions (in millions):

June 30, 2002

December 31, 2001

Receivables from affiliated companies

Enron Corp and other Enron Subsidiaries:

Merger Receivable
$
77
$
74

Allowance for Uncollectible - Merger Receivable

(77)

(74)

Income Taxes Receivable^(a)

4

4

Accounts Receivable^(b)

1

2

Other Allowance for Uncollectible Accounts^(b)

(5)

(5)

Portland General Holdings and its subsidiaries:

Accounts Receivable^(b)

35

33

Payables to affiliated companies

Enron Corp:

Accounts Payable^(a)

11

11

(a)Included in Accounts payable and other accruals on the Consolidated Balance Sheets
(b)Included in Accounts and notes receivable on the Consolidated Balance Sheets
For the Six Months Ended June 30

2002

2001

Revenues from affiliated companies

Other Enron subsidiaries:

Sales of electricity and transmission^(a)
$
1
$
125

Expenses billed to affiliated companies

Enron Corp:

Intercompany services^(b)

-

3

Portland General Holdings and its subsidiaries:

Intercompany services^(b)

1

1

Expenses billed from affiliated companies

Enron Corp:

Intercompany services^(b)

11

14

Other Enron subsidiaries:

Purchases of electricity^(c)

-

124

Interest (net) from affiliated companies

Enron Corp:

Interest income^(d)

3

4

Portland General Holdings and its subsidiaries:

Interest income^(d)

2

2

(a)Included in Operating Revenues on the Consolidated Statements of Income
(b)Included in Administrative and other on the Consolidated Statements of Income
(c) Included in Purchased power and fuel on the Consolidated Statements of Income
(d)Included in Other Income (Deductions) on the Consolidated Statements of Income

			September 30, 2002	December 31, 2001

Receivables from affiliated companies
	Enron Corp and other Enron Subsidiaries:
		Merger Receivable	$ 79	$ 74
		Allowance for Uncollectible - Merger Receivable	(79)	(74)
		Income Taxes Receivable^(c)	-	4
		Accounts Receivable^(b)	2	2
		Other Allowance for Uncollectible Accounts^(b)	(2)	(5)
	Portland General Holdings and its subsidiaries:
		Accounts Receivable^(b)	8	33
		Note Receivable^(b)	1	-

Payables to affiliated companies
	Enron Corp:
		Accounts Payable^(a)	15	11
		Income Taxes Payable^(c)	6	-

(a)Included in Accounts payable and other accruals on the Consolidated Balance Sheets
(b)Included in Accounts and notes receivable on the Consolidated Balance Sheets
(c)Included in Accrued taxes on the Consolidated Balance Sheets

For the Nine Months Ended September 30			2002	2001

Revenues from affiliated companies
	Other Enron subsidiaries:
		Sales of electricity and transmission^(a)	$ 1	$ 136

Expenses billed to affiliated companies
	Enron Corp:
		Intercompany services^(b)	-	3
	Portland General Holdings and its subsidiaries:
		Intercompany services^(b)	2	1

Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services^(b)	20	22
	Other Enron subsidiaries:
		Purchases of electricity^(c)	-	135

Interest (net) from affiliated companies
	Enron Corp:
		Interest income^(d)	5	5
	Portland General Holdings and its subsidiaries:
		Interest income^(d)	2	2

(a)Included in Operating Revenues on the Consolidated Statements of Income
(b)Included in Administrative and other on the Consolidated Statements of Income
(c) Included in Purchased power and fuel on the Consolidated Statements of Income
(d)Included in Other Income (Deductions) on the Consolidated Statements of Income

Merger Receivable - Under terms of the companies' 1997 merger agreement, Enron and PGE agreed to provide $105 million of benefits to PGE's customers through price reductions payable over an eight-year period. Although the remaining liability to customers was reduced to zero under terms of a 2000 settlement agreement related to PGE's recovery of its investment in Trojan, Enron remained obligated to PGE for the approximate $80 million remaining balance and continued to make monthly payments, as provided under the merger agreement.

Enron suspended its monthly payments to PGE in September 2001, pursuant to its Stock Purchase Agreement with NW Natural, under which NW Natural was to have assumed Enron's merger payment obligation upon its purchase of PGE. The Stock Purchase Agreement was terminated on May 17, 2002. At ~~June~~September 30, 2002, Enron owed PGE approximately ~~$77~~$79 million, including accrued interest. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001.

On October 15, 2002, PGE submitted proof of claims to the Bankruptcy Court for amounts owed PGE by Enron, including approximately $73 million (including accrued interest) for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. For further information, see Note 8,7, Enron Bankruptcy.

Income Taxes Receivable- As a member of Enron's consolidated income tax return, PGE made income tax payments to Enron for PGE's income tax liabilities. The $4 million income taxes receivable balance at ~~June 30, 2002~~December 31, 2001 represents a receivable from Enron for refunds of prior income taxes paid by ~~PGE.~~PGE through May 7, 2001, when PGE ceased to be a part of the Enron consolidated tax group. The $6 million balance at September 30, 2002 represents a payable to Enron for income taxes owed by PGE up to May 7, 2001 as a result of the 2002 income tax adjustments. For further information, see Note 7, Enron Bankruptcy.

Intercompany Receivables and Payable-As part of its ongoing operations,PGE bills affiliates for various services provided. These include services provided by PGE employees along with other corporate ~~governance~~ services and are billed at the higher of cost or market. Also, PGE is billed for services received ~~at the lower of cost or market,~~from affiliates, primarily for employee benefit plans and corporate overhead ~~costs.~~costs, at the lower of cost or market. All affiliated interest transactions with PGE are subject to approval of the ~~OPUC and are described below.~~OPUC.

Enron - PGE receives ~~management services~~corporate overhead and employee benefit charges from Enron and provides incidental services to Enron. In the first ~~six~~nine months of 2002, Enron billed PGE approximately $5$10 million for retirement savings plan matching and medical and dental ~~benefits and~~benefits. PGE has recorded an additional $6$10 million for Enron corporate overhead costs. For the same period in 2001, Enron billed PGE ~~$14~~$22 million for allocated overhead and other direct costs, comprised of $4$6 million for retirement savings plan matching, $3$5 million for medical and dental benefits, and $7$11 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001. PGE has since stopped making payments to Enron, except those for employee benefit plans, pending the ultimate disposition of payables to and receivables from Enron resulting from Enron's bankruptcy proceedings. The ~~$11~~$15 million payable to Enron at ~~June~~September 30, 2002 consisted primarily of corporate overhead costs.

In 2001, PGE received $3 million from Enron for expenses related to the proposed merger with Sierra Pacific Resources.

Other Enron Subsidiaries - In 2001, PGE provided services and sublease of office space to other Enron subsidiaries, including Enron Broadband Services, Inc. and Enron North America Corp. (ENA). PGE purchased and sold electricity and transmission services to Enron Power Marketing, Inc. (EPMI), a subsidiary of ENA. Under these transactions with EPMI, the purchases and sales of energy were primarily for like quantities and ~~hours.~~hours at different points of delivery. PGE purchased power at prices no higher than the Dow Jones Mid-Columbia Index and charged at prices at or higher than the Dow Jones Mid-Columbia Index. In 2002, PGE is no longer purchasing and selling electricity with EPMI; however, PGE continues to provide transmission ~~services.~~services related to existing contracts. As of February 2002, PGE is no longer subleasing office space to ENA due to the sale of ENA's trading operations. For the first ~~six~~nine months of 2002, PGE billed EPMI $1 million for transmission services, which have been paid by EPMI. At ~~June~~September 30, 2002, PGE is owed approximately $1 million by EPMI for power and transmission services provided in 2001.

Portland General Holdings and Subsidiaries -Portland General Holdings, Inc. (PGH) is a wholly owned subsidiary of Enron. Prior to Enron's bankruptcy, Enron had provided a portion of the funding for operations of PGH and its subsidiaries. With Enron's bankruptcy, any future funding from Enron will be subject to approval by Enron, and must be in compliance with the Order of the Bankruptcy Court Authorizing Continued Use Of Existing Bank Accounts, Cash Management System, Checks and Business Forms dated December 3, 2001, as amended on February 25, 2002 (the ~~"Cash Order")~~Cash Order). PGH and its subsidiaries are not part of Enron's bankruptcy proceedings. At ~~June~~September 30, 2002, PGE has an outstanding receivable balance from PGH and its subsidiaries of ~~$35~~$8 million, comprised of ~~$30~~$2 million related to non-regulated asset sales, $4 million related to PGH employee benefit plans, and $1$2 million for employee services and other corporate governance services. In June 2002, Enron loaned PGH $475 ~~thousand~~thousan d to ~~fu nd~~fund current operating activities, in compliance with the Cash Order. No additional funds have been advanced from Enron to PGH, and the $475 thousand remains outstanding as of September 30, 2002.

In 1999, PGE transferred $21 million of corporate owned life insurance policies to PGH, creating a receivable balance ~~due~~owed by PGH to PGE. PGH transferred these policies to a trust ~~for~~to pay certain non-qualified benefit plan obligations owed by PGH, leaving awith PGH the receivable balance due PGE. Later in 1999, PGH recorded a capital transaction with its wholly owned subsidiary PGH II, Inc. (PGH2), ~~transferring~~reflecting an assumption by PGH2 of the obligation to pay the $21 million ~~PGE intercompany payable~~owed to ~~PGH2.~~PGE. PGH retained the residual interest in the trust owned life insurance ~~policies in this transaction.~~policies. The transfer to PGH2 was the result of negotiations between Enron and Sierra Pacific Resources related to the proposed sale of PGE and PGH2 to Sierra (the sale of which was later ~~terminated)~~terminated in April 2001). In the proposed sale of PGE and PGH2 to NW Natural, the ~~PGE~~obligation to pay the intercompany payable ~~was also~~ to PGE would have been assumed by NW Natural. In June 2002, due to the termination of the sale agreement with NW Natural, the PGE ~~intercompany~~int ercompany payable was transferred back to PGH. Due to the effects of both the termination of the sale ~~agree ment~~agreement with NW Natural and the complexities of the Enron bankruptcy on the length of time to collect this receivable balance from PGH, PGE's board of directors on July 25, 2002 approved the transfer of the intercompany receivable at PGE to Enron in the form of a non-cash dividend. ~~As of June 30,~~In July 2002, the balance due PGE from PGH ~~was~~of $27 million, including accrued ~~interest.~~interest, was transferred to Enron as a non-cash dividend.

PGH2 is the parent company of various subsidiaries that receive services from PGE. These include Portland General Distribution, ~~Company~~LLC and Portland General Broadband Wireless, LLC (telecommunications companies), Microclimates, Inc. (a project management company), and Portland Energy Solutions Company, LLC (PES), which provides cooling services to buildings in downtown Portland, Oregon. For the first ~~six~~nine months of 2002, PGE billed PGH and its subsidiaries $1$2 million for various employee services and corporate governance services. At ~~June~~September 30, 2002, PGE has a $3$2 million receivable balance from Portland General Distribution Company, LLC related to assets sold for a capital project and for employee services provided by PGE.

PGE has entered into a one-year revolving credit agreement to loan PES $2 million. The agreement, approved by the OPUC, expires on April 1, 2003. Under the agreement, PGE will advance funds to PES to complete a district cooling system project, with advances to accrue interest at 16% per annum. The OPUC order further provides that interest paid by PES to PGE in excess of PGE's authorized cost of capital (9.083%) be deferred for refund to customers. PGE also has a security interest in certain contracts and equipment related to the project. As of ~~June~~September 30, 2002, ~~no funds have been advanced by~~PES owes PGE approximately $1 million, including accrued interest, under the agreement.

PGE also provides services to its consolidated subsidiaries, including funding under a cash management agreement and the sublease of office space in the WTC. Intercompany balances and transactions have been eliminated in consolidation.

PGE maintains no compensating balances and provides no guarantees for related parties.

Interest Income and Expense -Interest is accrued on the Enron Merger Receivable balance at PGE's current authorized cost of capital (9.083%) and is being fully reserved, as discussed above. ~~Receivable~~Accounts receivable balances from PGH and its subsidiaries accrue interest at 9.5%. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its other subsidiaries. Beginning in 2001, interest was no longer accrued on those other outstanding balances with Enron due to the proposed merger with Sierra Pacific Resources. Although the proposed merger was terminated in April 2001, interest accrual has not resumed.

Management Assessment ~~-Due~~- Due to Enron's bankruptcy, management cannot predict the ultimate outcome of the above matters and the realization of its receivables. In particular, the collectibility of the ~~$77~~$79 million Enron Merger Receivable ~~would be~~is uncertain under Enron's bankruptcy proceedings. As a result, the Company has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve of $5 million was established in December 2001 for the ~~entire $5 million remaining~~ balance of such ~~receivables.~~receivables, of which $3 million was reversed in the third quarter of 2002. The $2 million receivable balance at September 30, 2002 continues to be fully reserved.

Note 65 - Receivables - California Wholesale Market

As of ~~August~~November 1, 2002, PGE has accounts receivable totaling approximately ~~$74~~$66 million that may be affected by the financial condition of two California utilities. ~~Remaining payments totaling approximately $11 million (including imputed interest at 6.79%) are owed by~~ Southern California Edison Company (SCE) owes one remaining payment of approximately $3 million, due December 1, 2002, under terms of a 1996 agreement providing for the termination of a Power Sales Agreement between the two companies. ~~SCE has made its scheduled monthly payments under the termination agreement, with the final payment due in December 2002. In addition, a~~A balance of approximately $63 million is currently owed the Company by the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to SCE and Pacific Gas & Electric Company (PG&E).

On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, PG&E retains control of its assets and is authorized to operate its business as a debtor in possession while subject to the jurisdiction of the Bankruptcy Court.

PGE is pursuing collection of all past due ~~amounts.~~amounts through the PX and PG&E bankruptcy proceeding and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to its California receivables and has established a credit reserve for amounts due under its wholesale electricity contracts.

The Company ~~has retained legal counsel on the bankruptcy matters and has~~is examining numerous options, including legal, regulatory, and other means to pursue collection of any amounts ultimately not ~~received.~~received through the bankruptcy process. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.

Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

Note 76 - Refunds on Wholesale Transactions

California

In a June 19, 2001 ~~FERC~~ order adopting a price mitigation program for 11 states within the WSCC area, the FERC referred to a settlement judge the issue of refunds for ~~spot market sales~~non federally-mandated transactions made between October 2, 2000 ~~through~~and June 20, 2001 ~~was referred to a settlement judge.~~

~~On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds related to non federally-mandated transactions~~ in the spot markets operated by the ISO and the PX. ~~In addition,~~

On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding ~~was ordered~~ to develop a factual record to provide the basis for the refund calculation. ~~The~~Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in March 2002, to determine the appropriate proxy prices to use, and in August through October, 2002, to determine how to calculate amounts owed to and refunds owed by sellers into the California market. Using the established methodology, the Company's potential refund obligation ~~using the FERC methodology,~~ is currently estimated to be in the range of $20 million to $30 ~~million, with final~~million. Final determination of refunds is to be made after review by FERC ~~review~~ of calculations filed by the ISO. ~~Hearings were held in March 2002, with additional hearings scheduled for August 2002.~~ PGE will have the opportunity to challenge the FERC's determination of the amount of any proposed refunds.

On August 13, 2002, the FERC staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a guil ty plea to conspiracy to commit wire fraud in connection with California's energy market.

Appeals of the FERC orders establishing the refund methodology have been filed and are pending in the Ninth Circuit Federal Court of Appeals. On August 21, 2002 the Ninth Circuit issued an order requiring the FERC to reopen the record to allow the parties to adduce additional evidence of market manipulation.

The FERC has not yet determined how the comments or these subsequent events will affect the methodology used in the refund hearings.

Pacific Northwest

In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. Upon completion of hearings, the appointed Administrative Law Judge issued a recommended order, dated September 24, 2001, that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.

Several of the complainants in this case have filed motions to reopen the ~~hearing. Those~~hearing, with such motions ~~are~~awaiting FERC action. FERC could consider all of the factors discussed in this Note in reaching a decision whether to grant such motions.

Potential Refund Mitigation

The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California (as discussed in Note 5, Receivables - California Wholesale Market). The FERC has also ~~awaiting Commission action.~~indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.

~~Any~~In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism. This could ~~potentially~~further mitigate the financial effect of any refunds made or received by the Company. In addition, PGE believes that any refunds related to California sales that may be required by the FERC can be offset by accounts receivable related to sales in California (as discussed in Note 6, Receivables - California Wholesale Market).

Management cannot predict the ultimate outcome of these matters. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

Note 87 - Enron Bankruptcy

On December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the filing.

On May 3, 2002, Enron presented to its creditors committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of PGE in the new company would be subject to potential sale to a different buyer under a Section 363 auction process, which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the creditors committee and is one of many options Enron may pursue. There can be no assurance as to whether PGE would ultimately be included in a new company or separately sold to a bidder in a Section 363 auction. Until this process results in a filing with the Bankruptcy Court, management will not know the role of PGE in the proposed structure and cannot assess the impact on PGE's business and operations.

In connection with its proposed restructuring, Enron has stated that it believes that the total amount of the liquidated, undisputed claims against Enron and its subsidiaries exceeds and will exceed the current fair market value of the consolidated operations and assets of Enron and its subsidiaries. Accordingly, Enron has stated that it believes its existing equity has and will have no value and that any Chapter 11 plan confirmed by the Bankruptcy Court will not provide Enron's existing equity holders with any interest in the reorganized debtor. Any and all Chapter 11 plans are subject to creditor approval and judicial determination of confirmability.

Management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997 ~~(the merger conditions)~~(Merger Conditions), Enron's access to PGE cash or assets (through dividends or otherwise) is limited. Under the ~~merger conditions,~~Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC ~~approva l. The merger conditions~~approval. T he Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances ~~itself~~its operations separately from Enron, on both a short-term and long-term basis. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder. For further information, see Note 9, Preferred Stock.

Notwithstanding the above, PGE may have potential exposure to certain liabilities and asset impairments as a result of Enron's bankruptcy. These are:

Amounts Due from Enron and Enron-Supported Affiliates - As described in Note 5,4, Related Party Transactions, PGE is owed approximately ~~$77~~$79 million from Enron relating to the Merger Receivable (including interest accrued to ~~June~~September 30, 2002). Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proof of claims to the Bankruptcy Court for amounts owed PGE by Enron, including approximately $73 million (including accrued interest) for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve ~~was~~has been established ~~in December 2001~~ for the entire $5$2 million remaining balance of such ~~receivables.~~receivables at September 30, 2002.

Control Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plan and tax obligations of Enron.

Pension Plans

The pension plan for the employees of PGE ~~(PGE~~(the PGE Plan) is separate from the Enron pension plan ~~(Enron~~(the Enron Plan). As of December 31, 2001, the PGE Plan had assets that exceeded the present value of all accrued benefits on a SFAS No. 87 (Employers' Accounting for Pensions) basis and, management believes, on a plan termination basis. Based on discussions with Enron management, it is PGE management's understanding that, as of December 31, 2001, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $90 million on a SFAS No. 87 basis and approximately $120 million on a plan termination basis. The Pension Benefit Guaranty Corporation ~~(the PBGC)~~(PBGC) insures pension plans, including the PGE Plan and the Enron Plan.

Subject to applicable law, separate pension plans established by companies in the same controlled group may be merged. If the Enron Plan and PGE Plan were merged, the excess assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC and the PGE ~~Plan's~~Plan assets would be undiminished.

Since the Enron Plan is underfunded and Enron is in bankruptcy, in certain circumstances the Enron Plan may be terminated and taken control of by the PBGC upon approval of a Federal District Court. In addition, with consent of the PBGC, Enron could seek to terminate the Enron Plan while it is underfunded.

Upon termination of a pension plan, all of the members of the controlled group of the plan sponsor become jointly and severally liable for the plan's underfunding. The PBGC can demand payment from one or more of the members of the controlled group. If payment is not made, a lien in favor of the PBGC automatically ~~attaches~~arises against all of the assets of that member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all of the controlled group members. In addition, if the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in favor of the plan in the amount of the missed funding automatically ~~attaches to~~arises against the assets of every member of the controlled group. In either case, the PBGC may file ato perfect the lien and attempt to enforce it against the assets of members of the Enron controlled group. PGE management believes that the lien ~~is subor dinate~~would be subordinate to prior perfected liens on the assets of the member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted by the PBGC would be subordinate to that lien. Based on discussions with Enron's management, PGE's management understands that Enron has made all required contributions to date through ~~July~~October 15, 2002.

Management cannot predict the outcome of the above matters or estimate any potential loss. In addition, if the PBGC did look solely to PGE to pay any amount with respect to the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of the controlled group. No reserves have been established by PGE for any amounts related to this issue.

Retiree Health Benefits

Under COBRA, if certain retirees of Enron ~~who~~ lose coverage under Enron's group health plan due to Enron's bankruptcy proceedings, ~~are~~they would be entitled to ~~obtain~~elect continuation of their health coverage in a group plan maintained by Enron or a member of its controlled group. PGE management understands, based on discussions with Enron management, that Enron had provided a plan for retiree health insurance and that the actuarial liability for such coverage was approximately $70 million as of December 31, 2001. Management further understands that to meet its obligation, Enron, at December 31, 2001, had set aside approximately $34 million of assets in a VEBA trust, which may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million.

In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan, if any, or the most appropriate existing group health plan of another member of the Enron controlled group. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the appropriate existing plan. Retirees electing to purchase COBRA coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the ~~average~~ cost of coverage for similarly situated beneficiaries. Retirees are not required to purchase coverage under COBRA. Retirees may, instead, shop for coverage from third party sources and determine which is the least expensive coverage.

Management cannot predict the outcome of the above matter or estimate any potential loss. However, management believes that in the event Enron terminates coverage, any liability to PGE associated with the number of retirees that choose to remain under Enron's retiree health plan will not be material. No reserves have been established by PGE for any amounts related to this issue.

Income Taxes

Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with Portland General Corporation. Based on discussions with Enron's management, PGE management understands that PGE ceased to be a member of Enron's consolidated group on May 7, 2001.

Enron's management has provided the following information to PGE:

A. Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS ~~has essentially completed its audit of the consolidated tax returns for 1996-1997 and~~ is currently auditing ~~such~~the consolidated returns for ~~1998-2000.~~1996-2001. Enron's consolidated tax return for 2001 ~~is expected to be~~was filed ~~in the fall of~~on September 13, 2002 and Enron expects this return and claims by the IRS, if any, ~~will~~to be included in the bankruptcy process, as ~~discussed~~described below.

For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. ~~Enron and its subsidiaries anticipate that the~~Enron's 2001 consolidated tax return ~~will show~~showed a substantial loss, which ~~would~~will be carried back to tax year 2000, and is anticipated to result in a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from the ongoing IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns. However, to the extent that such audit results in interest owing by the Enron consolidated group for periods after Enron filed its bankruptcy petition ("postpetition interest") or in penalties that would not have a statutory priority over general unsecured creditors, the IRS could seek to collect such amounts from consolidated group members not in bankruptcy, such a s PGE. The last day that the IRS can file a proof of claim for prepetition taxes in the bankruptcy case is March 31, 2003. It is anticipated that the IRS will file a proof of claim for periods through 2001 prior to that date. If there were additional tax liabilities claimed by the IRS, these would be satisfied by funds in the bankruptcy ~~estat e~~estate ahead of unsecured Enron creditors, but claims for postpetition interest would not be allowed, and claims for penalties would be treated on a par with the claims of general unsecured creditors.

Although management cannot predict with certainty the outcome of the IRS ~~audits,~~audit, based on the above, it believes it is unlikely at this time, that any tax claims by the IRS would ~~offset~~exceed the substantial NOLs available to the Enron consolidated tax returns. Claims for postpetition interest and claims for penalties, if any, could not be offset by these NOLs. If the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS did look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated ~~group, who are not debtors in the bankruptcy case.~~group. As a result, management believes the income tax, interest, and penalty exposure to PGE would not be ~~minimal, if any,~~material related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's ~~consolidated~~con solidated tax returns. No reserves have been established by PGE for any amounts ~~relat ed~~related to this issue.

Enron Debtor in Possession Financing- PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a ~~debtor-~~

~~in-possession~~debtor in possession credit agreement with Citicorp USA Inc. and JP Morgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the ~~debtor-in-possession~~debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged ~~shares~~share s of PGE stock or to exercise control over PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.

~~Note 9 - Credit Facilities~~Enron Auction Processes Related to PGE

On May 3, 2002, Enron presented to its Unsecured Creditors Committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and ~~Debt~~

~~PGE entered into~~operated prospectively as a new ~~$72 million 364-day revolving credit facility with a group~~integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of ~~commercial banks, replacing a $200 million credit facility that expired on June 12, 2002. Under~~PGE in the new ~~credit facility, PGE has the option~~company would be subject to ~~issue letters of credit, in addition~~potential sale to borrowings, totaling up to the $72 million. This new facility, along with an existing $150 million revolving credit facility (which expires in June 2003), provides total available liquidity to PGE of $222 million. Both facilities are secured by First Mortgage Bonds issueda different buyer under a Section 363 auction process, which would be supervised by the ~~Company.~~Bankruptcy Court. Enron's proposal has not been endorsed or approved by the Unsecured Creditors' Committee and is one of many options Enron may pursue.

On August 27, 2002, Enron announced that it has commenced a formal sales process for its interests in certain major assets, including PGE. In its announcement, Enron indicated that it is extending invitations to visit electronic data rooms containing information on 12 of its most valuable businesses to a broad universe of potential bidders with whom Enron has executed confidentiality agreements.

Enron's announcement stated that the sales process continues Enron's efforts to maximize value and enhance recovery for its creditors. Enron and its advisors, in consultation with the Unsecured Creditors' Committee and its advisors, will evaluate all offers received to determine the combination of bids that maximizes the value of all assets.

Enron and its advisors received initial indications of interest in October 2002. Enron has stated that it reserves the right not to sell any of its assets if the bids received are not deemed fully reflective of the assets' value.

There can be no assurance as to whether PGE will be sold to a bidder in the auction process described above or ultimately be included in a new integrated power and pipeline company under the proposal presented by Enron to its Unsecured Creditors' Committee in May 2002. A sale of PGE under either scenario would require the consideration and approval of regulatory agencies, including the OPUC. Until these processes result in a filing with the Bankruptcy Court, management cannot assess its impact on PGE's business and operations.

Note 108 - New Accounting Standards

SFAS No. 143, Accounting for Asset Retirement Obligations, requires the recognition ~~as an Asset Retirement Obligation (ARO),~~ of ~~a liability for dismantlement and restoration costs~~any legal obligations associated with ~~the retirement of~~retiring tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized amount of the related long-lived assets. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ~~ARO~~ liability classified as an operating expense on the income statement. PGE is required to comply with SFAS No. 143 beginning January 1, 2003 and is currently evaluating the impact of SFAS No. 143 to its tangible long-lived assets, substantially all of which are included in rate-regulated operations.

SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, requires the recognition of a liability for costs related to exit or disposal activities when the costs are incurred. Previous accounting guidance required the liability to be recorded at the date of commitment to an exit or disposal plan. PGE is required to comply with SFAS No. 146 beginning January 1, 2003. PGE does not expect the adoption of SFAS No. 146 to have an effect on its financial statements.

Note 9 - Preferred Stock

On September 30, 2002, a single share of a new class of Limited Voting Junior Preferred Stock (Stock) was issued by PGE to an independent party. The new class of stock, created by an amendment to PGE's Articles of Incorporation, was issued following approval by the Bankruptcy Court, Debtor-in-Possession lenders, the OPUC, and PGE's board of directors.

The Stock has a par value of $1.00, a liquidation preference to the Common Stock as to par value but junior to existing preferred stock, an optional redemption right, and certain restrictions on transfer. The Stock also has voting rights, which limit, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings (Bankruptcy) without the consent of the holder of the share of Stock. The consent of the holder of the share of Stock will not be required if the reason for the Bankruptcy is to implement a transaction pursuant to which all of PGE's debt will be paid or assumed without impairment.

Note 10 - Long-term Debt

On October 10, 2002, PGE issued $150 million of 8-1/8% First Mortgage Bonds, maturing February 2010. The bonds were issued as a private placement. Net proceeds from this issue will be used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes.

On October 28, 2002, PGE issued $100 million of 5.6675% First Mortgage Bonds, maturing October 2012. The bonds were issued as a private placement. The Company purchased a policy insuring the principal and interest payments on the bonds, which will add approximately 1.5% to annual interest costs. Net proceeds from this issue will be used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes.

On October 29, 2002, PGE utilized a portion of the proceeds from the above two bond issues for the early retirement of $150 million in variable rate First Mortgage Bonds due December 16, 2002.

In addition to the issuance of new long-term debt, management believes that PGE has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the consolidated financial ~~statements.~~statements and related notes included elsewhere in this report. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2002.

2002 Compared to 2001 for the Three Months Ended ~~June~~September 30

PGE's net income in the ~~second~~third quarter of 2002 was ~~$16~~$8 million, compared to ~~$29~~a net loss of $5 million in the ~~second~~third quarter of 2001. The ~~$13 million decrease was due~~increase resulted primarily ~~to reduced~~from higher margins on energy ~~sales. A slowed economy~~sales, as the cost of purchased power and ~~conservation efforts combined to reduce~~generation decreased significantly from the third quarter of last year. In the third quarter of 2001, PGE sold power in excess of its retail ~~energy sales from last year's second quarter. Lower wholesale~~load at prices ~~further reduced operating margins as excess~~significantly lower than the cost of such power, which had been previously purchased under forward contracts at higher prevailing prices.

PGE purchases wholesale power to meet its retail load as the Company's generating resources are not currently sufficient to meet the demand of retail customers. The Company uses both long-term and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to seasonal fluctuations in the retail demand for electricity and variability in generating plant operations. Purchases are also made if they are less than the cost of operating the Company's generating facilities. Wholesale power is purchased in advance to meet forecasted demand, to provide continuing reliability in the event that actual demand exceeds forecasted demand, and to provide for potential outages when conditions threaten future supply. PGE purchases power in the forward market in advance of need, especially when the wholesale market is volatile and future supplies are uncertain.

During most of the 2000-2001 period, reliability concerns were heightened as wholesale market prices were high and volatile and region-wide demand approached supply. These factors, along with forecasted poor hydro conditions, an expected two-year lag in the availability of new generation, and speculation and concerns related to potential FERC-imposed wholesale price caps, led to predictions of regional power supply shortages in the winter and summer of 2001 and abnormally high power prices.

The inability to sell excess power at prices covering the cost of such power, combined with poor hydro conditions, led to last year's third-quarter loss.In addition, although PGE was able to defer for future recovery from customers substantial third quarter 2001 power costs, it was also necessary for the Company to absorb considerably higher costs last year under terms of the power cost mechanism then in effect. Last year's third quarter results also included a nonrecurring $12 million (before taxes) third quarter positive adjustment reflecting results of PGE's SAVE program, under which the Company is allowed recovery in rates of certain costs and incentives related to the installation of energy efficiency measures.

The following table summarizes Operating Revenues for the three-month periods ending September 30, 2002 and 2001:

	Operating Revenues
	Three Months Ended
	September 30,
	2002		2001		Increase/(Decrease)
	(In Millions)				Amount		%
Retail	$	352	$	237	$	115	49%
Wholesale - Non Trading		113		235		(122)	(52%)
Wholesale - Trading (net)		(1)		2		(3)	*
Other		(6)		6		(12)	*
Total Operating Revenues	$	458	$	480	$	(22)	(5%)

(* not meaningful)

The decrease in total Operating Revenues from the third quarter of 2001 was due to significantly lower wholesale prices for sales of energy in excess of retail customer requirements. The decrease in Wholesale - Non Trading revenues is attributable to a 67% average price decrease from last year's third quarter due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to the continued slow economy. Wholesale - Non Trading sales volume increased 46% as energy marketing activity returned from the low levels of 2001 caused by price volatility and uncertainty related to the western energy crisis, with power purchases in excess of retail customer requirements sold in the wholesale market.

~~Total~~ The increase in Retail revenues was due primarily to a general rate increase that became effective October 1, 2001; energy sales increased 2%, with an approximate 9,500 (1.3%) increase in total customers since the end of last year's third quarter partially offset by a slow economy and energy conservation. The decrease in Other operating revenues was due largely to lower prices on sales of natural gas in excess of generating requirements, as power purchases economically displaced higher priced thermal generation. For further information regarding Wholesale - Trading activities, see Note 2, Price Risk Management, in the Notes to Financial Statements.

The following table indicates retail and wholesale energy sales for the third quarters of 2002 and 2001:

Megawatt-Hours Sold (thousands)

	2002	2001
Retail	4,600	4,509
Wholesale - Non Trading	3,733	2,565
Wholesale - Trading	2,774	1,498

Purchased power and fuel costs decreased ~~$278~~$70 million ~~(33%~~(18%) due to both lower prices for power purchases and reduced thermal generation. Lower regional power and natural gas prices resulted in a 56% drop in the average cost of firm power purchases from last year's third quarter. Combined with lower prices for spot market purchases and a 46% decrease in thermal generation, PGE's average variable power cost was 57% of last year's third quarter (for further information, see "Power Supply" in the Financial and Operating Outlook section). A 17% increase in total system load resulting from higher wholesale activity, due to both the Company's increased participation in the wholesale energy market and from the sale of power in excess of retail requirements, partially offset the effect of the average cost decrease. Purchased power and fuel expense for the third quarter of 2001 included an $87 million credit related to PGE's power cost mechanism. Although PGE was able to defer this amount for future rate recovery, it was necessary for the Company to absorb $54 million in costs exceeding the power cost baseline established by the OPUC under the mechanism then in effect. In the third quarter of 2002, it was necessary for the Company to absorb $12 million under the power cost mechanism currently in effect. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).

PGE energy generation decreased 42% from last year's third quarter due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance outages at the Company's coal fired generating plants. Despite significantly improved hydro conditions, the Company's hydro energy production decreased 16%, reflecting the January 1, 2002 sale of a 33.33% interest in the Company's Pelton Round Butte project. Total Company generation met approximately 37% of PGE's retail load during the third quarter, compared to 66% last year, as lower cost power purchases were utilized to replace higher cost generation.

The following table indicates PGE's total system load (including both retail and wholesale) for the ~~second~~third quarters of 2002 and 2001 (excludes energy trading activities). Average variable power costs exclude the effect of PGE's power cost mechanisms on purchased power and fuel costs.

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)

	2002	2001	2002	2001
Generation	1,809	3,146	16.6	14.4
Firm Purchases	5,408	3,890	42.8	98.1
Spot Purchases	1,361	324	15.8	26.8
Total Send-Out	8,578	7,360	34.8*	60.7*
(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) increased $2 million (3%). Administrative and other expenses increased $3 million, with increased corporate overhead expenses, including certain employee benefit costs, partially offset by a reduction in customer support expenses, due primarily to a change in accounting for energy efficiency expenses. Beginning March 1, 2002, as provided by Oregon energy restructuring legislation (Senate Bill 1149), conservation, renewable resource, and weatherization measures are funded by a 3% Public Purpose Charge from retail customers and administered by the non-profit Energy Trust of Oregon. All incurred energy efficiency expenses (previously included in Operating expenses), and related amounts received from the Energy Trust, are included within Other income. Production and distribution expenses decreased by $1 million, due primarily to the termination of fees previously paid to the Confederated Tribes of Warm Springs related to the operation of PGE's Pelton Round Butte hydroelectric project. Such fees, which totaled $2 million in last year's third quarter, are no longer required due to the sale of a 33.33% interest in the project to the Tribes in January 2002. This was partially offset by a $1 million increase in service restoration and other distribution expenses.

Depreciation and amortization expense increased $10 million due primarily to the effect of last year's nonrecurring $12 million regulatory credit reflecting final 2000 and estimated 2001 results of PGE's SAVE program. A $6 million increase in depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's 2001 general rate case, was largely offset by amortization of certain regulatory liabilities, related to certain refunds to customers, and other regulatory amortization.

Taxes other than income taxes increased $2 million primarily due to higher franchise fees resulting from increased retail revenue.

Income taxes increased $21 million primarily due to higher taxable income in this year's third quarter. In addition, there were certain nonrecurring credit adjustments recorded in the third quarter of 2001 related to prior years' amended tax returns and deferred tax and audit adjustments.

Other miscellaneous income decreased $2 million, due primarily to a reserve for interest accrued on the Merger Receivable from Enron in the third quarter of 2002 and to lower interest income related to the Company's power cost mechanism. These were partially offset by the $3 million reversal of a credit reserve established in December 2001 related to income taxes receivable from Enron (for further information, see Note 4, Related Party Transactions, in the Notes to Financial Statements).

2002 Compared to 2001 for the Nine Months Ended September 30

PGE's net income in the first nine months of 2002 was $60 million, compared to $67 million in the same period for 2001. Last year's results included an $11 million gain from a cumulative effect of a change in accounting principle resulting from the adoption of SFAS No. 133 on January 1, 2001. The $4 million increase in net income before the effect of last year's accounting change was due primarily to increased margin on energy sales, as power prices decreased significantly from last year. Last year's results for the first nine months included a nonrecurring $12 million (before taxes) positive adjustment reflecting results of PGE's SAVE program. The effect of higher retail rates was partially offset by lower retail energy sales caused by a slowed economy and customer conservation efforts. In addition, last year's results for the first nine months reflect the sale of excess power at prices significantly lower than the cost of such power, previously purchased under forward contracts a t higher prevailing prices. In addition, although PGE was able to defer substantial power costs in the first nine months of 2001, it was also necessary for the Company to absorb considerably higher costs last year under terms of the power cost mechanism then in effect.

The following table summarizes Operating Revenues for the nine-month periods ending September 30, 2002 and 2001:

	Operating Revenues
	Nine Months Ended
	September 30,
	2002		2001		Increase/(Decrease)
	(In Millions)				Amount		%
Retail	$	1,095	$	749	$	346	46%
Wholesale - Non Trading		274		1,014		(740)	(73%)
Wholesale - Trading (net)		(1)		(9)		8	*
Other		(7)		23		(30)	*
Total Operating Revenues	$	1,361	$	1,777	$	(416)	(23%)

(* not meaningful)

The decrease in total Operating Revenues from the first nine months of 2001 was due to significantly lower wholesale prices for sales of energy ~~sold~~ in excess of retail customer requirements. The decrease in Wholesale - Non Trading revenues is attributable to a 79% average price decrease from the ~~wholesale market. Wholesale revenues decreased $371 million (from $587 million to $216 million), as prices dropped 86% from~~first nine months of last ~~year's second quarter~~year due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale - Non Trading sales volume increased ~~158%~~31% as ~~PGE~~energy marketing activity returned from lower levels in 2001 caused by price volatility and uncertainty related to the western energy crisis. In addition, power purchases in excess of retail requirements were sold onin the wholesale ~~market excess power purchased;~~market; in last ~~year,~~year's first nine months, such purchases were used to replace ~~lower~~low hydro generation to meet ~~second quarter~~ retail ~~load requirements.~~load. The increase in Retail revenues ~~increased $102 million~~was due primarily ~~due~~ to a general rate increase that became ~~effective~~ef fective October 1, 2001; energy sales decreased 4%2% as a slowing economy and conservation more than offset an approximate ~~10,000 (1.4%~~9,500 (1.3%) increase in total customers from the end of last year's ~~second~~third quarter. ~~O ther~~Other operating revenues decreased $8$22 million ~~primarily~~ due largely to lower prices ~~for~~on sales of natural gas in excess of generating ~~plant requirements.~~requirements, as power purchases economically replaced higher cost thermal generation. For further information regarding Wholesale - Trading activities, see Note 2, Price Risk Management, in the Notes to Financial Statements.

The following table indicates retail and wholesale energy sales for the nine-month periods ending September 30, 2002 and 2001:

Megawatt-Hours Sold (thousands)	Megawatt-Hours Sold (thousands)		Megawatt-Hours Sold (thousands)

	2002	2001	2002	2001
Retail	4,302	4,472	13,920	14,172
Wholesale	7,821	3,035
Wholesale - Non Trading			9,378	7,140
Wholesale - Trading			8,761	2,695

Purchased power and fuel costs decreased ~~$253~~$458 million primarily due to significantly lower energy prices. Lower regional power and natural gas prices resulted in a 70% drop in the average cost of firm power purchases from last year's second quarter. Combined with lower prices for spot market purchases and a 60% decrease in thermal generation, PGE's average variable power cost was 36% of last year's second quarter (for further information, see "Power

Supply" in the Financial and Operating Outlook section). Partially offsetting the effect of the average cost decrease was a 59% increase in total system load resulting from higher wholesale energy sales.

PGE energy generation decreased 49% from last year's second quarter due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance outages at the Company's coal fired generating plants. Improved hydro conditions resulted in energy production approximately equal to that of 2001's second quarter despite the loss in generation attributable to the January 1, 2002 sale of a portion of the Company's interest in the Pelton Round Butte project. Total Company generation met approximately 31% of PGE's retail load during the second quarter, compared to 59% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the second quarters of 2002 and 2001. Average variable power costs exclude the effect of PGE's power cost mechanisms on purchased power and fuel costs.

Megawatt/Variable Power Costs
Megawatt-Hours
(thousands)
Average Variable
Power Cost (Mills/kWh)
2002
2001
2002
2001
Generation
1,441
2,827
14.2
19.6
Firm Purchases
9,939
4,500
32.8
111.7
Spot Purchases
1,058
   491
16.6
177.2
Total Send-Out
12,438
7,818
30.5*
83.6*
(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) decreased $8 million (11%). Production expenses decreased by $4 million, due primarily to the termination of fees previously paid to the Confederated Tribes of Warm Springs related to the operation of PGE's Pelton Round Butte hydroelectric project, a 33.33% interest in which was sold to the Tribes in January 2002. In addition, lower maintenance costs were incurred at the Company's thermal generating plants. Corporate overhead expenses, including certain employee benefit costs, decreased $5 million, due partially to the timing of allocated overhead costs from Enron, which in 2001 were not recorded until the second quarter due to the proposed sale of PGE to Sierra Pacific Resources (which sale was later terminated). Increased provision for uncollectible customer accounts partially offset the decrease in corporate overhead costs.

Depreciation and amortization expense decreased $2 million. Increased amortization of regulatory liabilities, related to various refunds to customers, was partially offset by an increase in depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's recent general rate case.

~~Income taxes decreased $4 million (19%~~(35%) due to lower ~~taxable income.~~

Other income decreased $7 million, caused by a $4 million loss in the market value of trust owned life insurance assets, a $2 million reserve for interest accrued on the Merger Receivable from Enron in the second quarter, and a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company. Partially offsetting these items was increased interest on regulatory assets, including the deferred Power Cost Adjustment.

~~2002 Compared to 2001 for the Six Months Ended June 30~~

PGE's net income in the first half of 2002 was $52 million, compared to $72 million in the first half of 2001. Last year's first half results include the $11 million cumulative effect of a change in accounting principle resulting from the adoption of SFAS No. 133 on January 1, 2001. The $9 million decrease in net income before the effect of the accounting change was due primarily to reduced margins on energy sales. A slowed economy and conservation efforts combined to reduce retail energy sales from last year's first half. Lower wholesale prices in this year's first half further reduced operating margins as excess power purchased under forward contracts at higher prevailing market prices was sold in the wholesale market.

~~Total operating revenues decreased $504 million (32%) compared to the first half of 2001 due to significantly lower~~ prices for energy sold in the wholesale market. Wholesale revenues decreased $715 million (from $1,067 million to $352 million), as prices dropped 84% from last year's first half due to market forces within the region, including the effects of improved hydro conditions,power purchases, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale sales volume approximately doubled as PGE sold on the wholesale market excess power purchased; during the first half of last year, such purchases were used to replace lower hydro generation to meet retail load requirements. Retail revenues increased $231 million primarily due to a general rate increase that became effective October 1, 2001; energy sales decreased 4% as a slowing economy and conservation more than offset an approximate 10,000 (1.4%) increase in total customers from the end of last year's first half. Other operating revenues decreased $19 million due primarily to lower prices for sales of natural gas in excess of generating plant requirements.

Megawatt-Hours Sold (thousands)
2002
2001
Retail
9,244
9,663
Wholesale
11,632
5,774

~~Purchased power and~~ fuel costs, ~~decreased $498 million due primarily to significantly lower energy prices.~~and reduced thermal generation. Due to both lower regional power and natural gas prices, the average cost of firm power purchases ~~dropped over 62% from last year's~~was approximately half that of the first ~~half.~~nine months of 2001. Combined with lower prices for spot market purchases and a ~~48%~~47% decrease in thermal generation, PGE's average variable power cost was ~~56%~~57% of last year's first ~~half~~nine months (for further information, see "Power Supply" in the Financial and Operating Outlook section). ~~Partially offsetting the average cost decrease was a 34% increase in total system load resulting from higher wholesale energy sales.~~ Purchased power and fuel costs in the first ~~half~~nine months of 2002 ~~includes~~include a credit of approximately ~~$23~~$26 million related to the Company's current power cost ~~mechanisms,~~mechanism, compared to an $87 million credit in ~~which a portion~~the first nine months of 2001 under the ~~Power Cost Variance is deferred~~former mechanism. The current year credit reflects lower revenues from the base established in the Company's most recent rate proceeding. Although PGE was able to defer substantial power costs last year for future recovery from ~~customers.~~customers, it was necessary for the Company to absorb $54 million in costs that exceeded the baseline established by the OPUC under the power cost mechanism then in effect. In the first nine months of 2002, under the current power cost mechanism, it was necessary to absorb $28 million, which contributed to the decrease in this year's costs from those of last year. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).

~~PGE energy~~Energy generation from PGE's plants decreased ~~39%~~40% from last year's first ~~half~~nine months due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance and forced repair outages at the Company's coal fired generating plants. Improved ~~hydro conditions~~stream flows resulted in hydro energy production ~~approximately~~almost equal to that of 2001's first ~~half~~nine months despite the loss in generation attributable to the January 1, 2002 sale of a ~~portion of the Company's~~33.33% interest in the Company's Pelton Round Butte project. Total Company generation met approximately 37% of PGE's retail load during the first ~~half~~nine months of 2002, compared to ~~59%~~62% last ~~year.~~year, as lower cost power purchases were utilized to displace higher cost company generation.

The following table indicates PGE's total system load (including both retail and wholesale) for the first ~~half~~nine months of 2002 and ~~2001.~~2001 (excludes energy trading activities). Average variable power costs exclude the effect of ~~2002~~ credits to purchased power and fuel costs related to PGE's power cost mechanisms, as discussed above.

	Megawatt/Variable Power Costs				Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)		Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)

	2002	2001	2002	2001	2002	2001	2002	2001
Generation	3,710	6,115	15.3	22.2	5,519	9,261	15.6	19.5
Firm Purchases	15,711	8,837	38.5	101.6	15,397	11,679	42.5	84.2
Spot Purchases	2,122	1,119	20.9	175.3	3,219	1,298	18.7	134.0
Total Send-Out	21,543	16,071	34.2*	77.6*	24,135	22,238	35.1*	61.5*
(*includes wheeling costs)	(*includes wheeling costs)				(*includes wheeling costs)

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) increased $8 million (4%). Administrative and other expenses increased $9 million as corporate overhead expenses, including certain employee benefit costs, increased $6 million ~~(5%).~~and customer support expenses increased $3 million due to increased provisions for uncollectible customer accounts and to costs related to the implementation of a new customer information and billing system. Production and distribution expenses ~~were unchanged~~approximated last year's first nine months as ~~higher delivery system costs were offset by~~ lower plant maintenance expenses and the termination of fees to the Confederated Tribes of Warm Springs. (Such fees related to the Pelton Round Butte hydroelectric project, a 33.33% interest in which was sold to the Tribes in January 2002). Expenditures for energy efficiency, including an expanded program encouraging use of compact fluorescent lighting, and increased provisions for uncollectible customer accounts,Springs were ~~partially~~largely offset by ~~lower corporate overhead expenses,~~higher delivery system costs, including ~~certain employee benefit costs.~~tree trimming and other distribution-related work.

Depreciation and amortization expense ~~decreased~~increased $5 million. Increased ~~amortization of regulatory liabilities, related to various refunds to customers, was partially offset by an increase in~~ depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's ~~recent~~2001 general rate ~~case.~~case, resulted in a $19 million increase. In addition, a nonrecurring $12 million regulatory credit related to PGE's SAVE program was recorded in the third quarter of 2001. Such increases from last year's first nine months were partially offset by increased amortization of regulatory liabilities, related to various refunds to customers.

Taxes other than income taxes increased $2$4 million primarily due to higher franchise fees resulting from increased retail revenue.

Income taxes increased $21 million primarily due to higher taxable income in this year's first nine months. In addition, there were certain nonrecurring credit adjustments recorded in the first nine months of 2001 related to prior years' amended tax returns and deferred tax and audit adjustments.

Other miscellaneous income decreased $3$5 million, caused primarily by a $3$5 million reserve for interest accrued on the Merger Receivable from Enron in the first ~~half~~nine months of 2002, a $3$4 million decrease in the allowance for equity funds used during construction (AFDC), and certain non-utility interest income, a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company, and the $1 million write-off of certain non-utility investments. These were partially offset by a $2$3 million increase in interest income related to the Company's power cost mechanism, a $2 million reduction in market value oflosses on trust owned life insurance assets, and the $3 million reversal of a ~~$4 million increase~~credit reserve established in ~~interest on regulatory assets, including~~December 2001 related to income taxes receivable from Enron (for further information, see Note 4, Related Party Transactions, in the ~~deferred Power Cost Adjustment.~~Notes to Financial Statements).

Capital Resources and Liquidity

Review of Cash Flow Statement

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.

A significant portion of cash from operations comes from depreciation and amortization of utility plant charges which are recovered in customer revenues but require no current cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash.

Cash provided by operating activities totaled ~~$164~~$271 million in the first ~~half~~nine months of 2002 compared to $110 million used in the same period last year. The increase is due primarily to a ~~$252~~$288 million ~~net decrease~~reduction in cash collateral ~~deposits made~~deposit requirements with certain wholesale customers related to the settlement of certain energy contracts, and anto a $102 million increase in payments received from wholesale electricity sales.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, generation, and ~~generation~~general plant facilities. A ~~$31~~$32 million reduction in capital expenditures in the first ~~half~~nine months of 2002 is primarily attributable to reduced expenditures for transmission ~~substation~~ and distribution ~~line construction activities. In addition, costs~~construction. Such decreases were partially offset by increased expenditures related to the Company's new customer information and billing system which became operational in August 2002. Capital expenditures in the first ~~half~~nine months of 2001 include $6 million related to construction of a new 24.5 megawatt combustion turbine unit at the Beaver plant site.

Financing Activitiesprovide supplemental cash for day-to-day operations and capital requirements as needed. PGE currently relies on short-term bank loans and cash from operations to manage its day-to-day financing requirements. During the first ~~half~~nine months of 2002, the Company reduced its short-term borrowings by ~~$39 million, as it~~$104 million. It repaid $129 million in outstanding commercial paper, utilizing both cash collateral deposits returned by wholesale customers and cash from operations, and borrowed ~~$90~~$25 million under its committed credit lines. In addition, PGE paid $15 million in matured First Mortgage Bonds and $4$7 million of conservation bonds and other long-term debt, retired $2 million of preferred stock, and paid $1$2 million in preferred stock dividends. In July 2002, upon approval of the Company's board of directors, PGE made a non-cash dividend of $27 million to Enron related to the transfer of a receivable balance due from PGH (for further information, see Note 4, Related Party Trans actions, in the Notes to Financial Statements). No other common stock dividends were declared in the first ~~half~~nine months of 2002; management continues to evaluate future declaration of common stock dividends in light of expected cash requirements and other considerations.

In June 2002, PGE entered into a new $72 million 364-day revolving credit facility with a group of commercial ~~banks. For further information, see Note 9, Credit Facilities and Debt,~~banks, replacing a $200 million credit facility that expired in June 2002. The Company also has a $150 million revolving credit facility that expires in July 2003. Both facilities are secured by First Mortgage Bonds issued by the ~~Notes to Financial Statements.~~Company.

On ~~July 25,~~October 10, 2002, ~~PGE's board~~PGE issued $150 million of ~~directors approved~~8-1/8% First Mortgage Bonds, maturing February 2010, and on October 28, 2002, PGE issued $100 million of 5.6675% First Mortgage Bonds, maturing October 2012. The Company purchased a ~~non-cash dividend~~policy insuring the principal and interest payments on the bonds issued October 28^th, which will add approximately 1.5% to annual interest costs. Both bond issues were private placements, with net proceeds from both issues to be used to reduce short-term debt, refinance current maturities of ~~$27~~long-term debt, and for other general corporate purposes. On October 29, 2002, PGE utilized a portion of the proceeds of these two bond issues for the early retirement of $150 million in variable rate First Mortgage Bonds due December 16, 2002.

PGE has $49 million in long-term debt maturing in 2003, consisting of $40 million in First Mortgage Bonds that mature in August and $9 million of conservation bonds maturing throughout the year. The Company anticipates meeting these obligations through the sale of other long-term debt or the use of its existing credit facilities. In addition, PGE expects to ~~Enron related~~re-market $142 million of unsecured tax-exempt pollution control bonds that will be put back to PGE in May 2003. If the bonds are not re-marketed, PGE anticipates using proceeds from the sale of other long-term debt to pay the bonds.

PGE currently plans to utilize letters of credit to provide funding assurance for certain future decommissioning activities at Trojan. Decommissioning funding assurance is required by the Nuclear Regulatory Commission for the amount by which total estimated future radiological decommissioning costs exceed actual balances in decommissioning trust accounts. It is currently anticipated that such funding assurance, for an estimated initial amount of $25 million, will be required upon completion of the transfer of spent nuclear fuel to an on-site storage facility in October 2003. Such amount would decrease through late 2005, as radiological decommissioning is completed. The timing and amount of actual funding assurance requirements are subject to change. PGE does not expect that such obligation will have a ~~receivable balance due from PGH. (For further information, see Note 5, Related Party Transactions, in the Notes to Financial Statements).~~material effect on its financing requirements.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in ~~the~~its Articles of Incorporation and the Indenture securing its First Mortgage Bonds. As of ~~June~~September 30, 2002, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital requirements.

Credit Ratings

~~As a result of the May 2002 termination of the stock purchase agreement~~PGE's secured and unsecured debt ratings continue to ~~sell PGE to NW Natural, credit rating agencies reviewed their ratings of PGE.~~be investment grade from both Moody's Investors Service (Moody's) ~~lowered its ratings~~ and ~~retained the Company "on review for possible downgrade."~~Standard and Poor's (S&P), with Fitch Ratings (Fitch) ~~also lowered its ratings and retained the Company on "Rating Watch Negative." Standard & Poor's (S&P) reaffirmed PGE's ratings and maintained its "CreditWatch with Negative Implications" listing.~~

~~On August 1, 2002, Fitch further lowered its ratings of PGE to~~currently carrying a below investment grade ~~and maintained a "Ratings Watch Negative" status~~rating on the ~~Company. This action by Fitch reflects its view that the~~ Company, ~~has~~citing PGE's reduced financial flexibility resulting from ~~its~~the Company's status as a subsidiary of an insolvent parent and a difficult capital market environment. Fitch also considered the risk associated with PGE's ongoing exposure to the Enron bankruptcy and the uncertainty regarding ongoing investigations into PGE's energy trading activities in the western U.S. power markets (see "Federal Investigations - Wholesale Power Markets" in the Financial and Operating Outlook section).

PGE's current ratings are as follows:

	Moody's	S&P	Fitch

First Mortgage Bonds	Baa2	BBB+	BB+
Senior unsecured debt	Baa3	BBB	BB-
Preferred stock	Ba2	BBB-	B
Commercial paper	P-3	A-2	Withdrawn

Status:	On review for possible downgrade	CreditWatch with Negative Implications	~~Rating~~Ratings Watch Negative

~~Due~~In order to increase the ~~latest ratings action by Fitch,~~degree of insulation between PGE could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral, with an exposure estimated at $8 million. Currently, no additional performance collateral has been requested as a result of this ratings action.

~~PGE's secured~~ and unsecured debt ratings continue to be investment grade from both Moody's and S&P. However, S&P has indicated that its ratings could be lowered if PGE were to remain a wholly owned subsidiary of Enron, reflecting the general vulnerability of a wholly owned subsidiary to its insolvent ~~parent. S&P~~parent company, PGE on September 30, 2002 created a new class of Limited Voting Junior Preferred Stock and issued a single share of such stock to an independent party. The stock has ~~indicated that,~~voting rights which limit PGE's right to commence a voluntary bankruptcy proceeding without the consent of the holder of the share. For further information, see Note 9, Preferred Stock, in the ~~absence of effective structural separation ("ring-fencing") measures, PGE's ratings are likely~~Notes to ~~be downgraded well into the speculative grade category. PGE continues to actively pursue the satisfaction of S&P's structural separation criteria.~~Financial Statements.

Should Moody's and S&P reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. Based on PGE's non-trading and trading portfolio, estimates of current energy market prices and the current level of collateral outstanding, as of ~~July 22,~~November 1, 2002 the approximate amount of additional collateral that could be requested upon such a downgrade event is ~~$163 million. This amount~~$117 million and decreases to approximately ~~$29~~$46 million by year-end ~~2002 as current higher-priced energy contracts continue to settle.~~2002. In addition to collateral calls, such a credit ~~ratings~~rating reduction would likely have an adverse effect on ~~PGE's ability to issue~~the terms and conditions of future long-term debt. In addition, any such rating reductions would increase interest rates on PGE's two revolving credit facilities, increasing the cost of funding its day-to-day working capital requirements.

The Company's ability to access the commercial paper market has been adversely affected by ~~recent~~the May 2002 ratings ~~reductions~~reduction for commercial paper by Moody's and Fitch. PGE has $150 million in long-term debt maturing in December 2002 and $182 million in 2003 ($142 million in May 2003 and $40 million in August 2003). The Company is pursuing options to refinance these maturities, including the issuance of additional First Mortgage Bonds and the use of revolving lines of credit with commercial banks. PGE anticipates meeting these obligations.

Management believes that it has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

Financial and Operating Outlook

~~Enron's Proposed Sale of PGE~~

Enron Bankruptcy

In December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been suspended from trading on the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.

Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. PGE was also included inamong those Enron subsidiaries suspended from contracting with the federal government. Although no federal, state, or local governmental entity has ceased to transact business with PGE, and the BPA has stated that the suspension does not affect its sales and purchases of electricity with PGE, the Company believes it does not merit suspension and has begun the process to be removed from the suspension. Management believes the suspension will not have a material adverse effect on PGE business and operations.

In addition to the general effects discussed above, PGE may have potential exposure to certain liabilities and asset impairments as a result of Enron's bankruptcy. These are:

1. Amounts Due from Enron and Enron-Supported Affiliates - As described in Note 5,4, Related Party Transactions, in the Notes to Financial Statements, PGE is owed approximately ~~$77~~$79 million from Enron relating to the Merger Receivable (including accrued interest to ~~June~~September 30, 2002). Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proof of claims to the Bankruptcy Court for amounts owed PGE by Enron, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve ~~was~~has been established ~~in December 2001~~ for the entire $5$2 million remaining balance of such ~~receivables.~~receivable at September 30, 2002.

2. Control Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plans and tax obligations of Enron.

Pension Plans

Funding Status

The pension plan for the employees of PGE ~~(PGE~~(the PGE Plan) is separate from the Enron pension plan ~~(Enron~~(the Enron Plan). As of December 31, 2001, the PGE Plan had assets that exceeded the present value of all accrued benefits on a SFAS No. 87 (Employers' Accounting for Pensions) basis and, management believes, on a plan termination basis. Based on discussions with Enron management, it is PGE management's understanding that, as of December 31, 2001, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $90 million on a SFAS No. 87 basis and approximately $120 million on a plan termination basis. For additional information regarding PGE's pension plan, see below under "PGE Pension Plan".

It is permissible, subject to applicable law, for separate pension plans established by companies in the same controlled group to be merged. Enron could direct that the PGE Plan be merged with the Enron Plan. If the plans were merged, the assets in the PGE Plan would reduce the deficiency in the Enron Plan. However, if the plans are not merged, the deficiency in the Enron Plan could become the responsibility of the PBGC, which insures pension plans, including the PGE Plan and the Enron Plan, and the PGE Plan's surplus would be undiminished. Merging the plans would reduce the value of PGE, the stock of which is an asset available to Enron's creditors. ~~Management~~PGE's management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.

Although the Enron Plan is underfunded and Enron is in bankruptcy, Enron cannot itself terminate the Enron Plan unless it provides at least 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. In the opinion of management, PGE is a solvent entity that does not meet the financial distress test. Consequently, management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded.

The PBGC does have the authority, either by agreement with the Plan administrator or upon application to and approval by a Federal District Court, to terminate and take over control of underfunded pension plans in certain circumstances. In order to initiate this process, the PBGC must determine that either the minimum funding standard for the plan (see discussion below) has not been met, or that the plan will not be able to pay benefits when due, or that there is a reasonable risk that long-run losses to the PBGC will be unreasonably increased or that certain ~~improper~~ distributions have been made from the plan. The court must determine that plan termination is necessary to protect participants, the plan, or the PBGC.

Upon termination of a pension plan, all members of the controlled group of the plan sponsor become jointly and severally liable for the underfunding, but are not obligated to pay until a demand for payment is made by the PBGC. The PBGC can demand payment from one or more of the members of the controlled group. If payment of the full amount demanded is not made, a lien in favor of the PBGC automatically ~~attaches~~arises against all of the assets of each member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all controlled group members. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien does not take priority over other previously perfected liens on the assets of a member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted by the PBGC would be subordinate to that lien.

If the PBGC did look solely to PGE to pay any underfunded amount in respect of the Enron Plan, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover any contributions from the other solvent members of ~~the plan sponsor's~~Enron's controlled group. Until such time as the Enron Plan is terminated and the PBGC makes a demand on PGE to pay some or all of the underfunded amount, PGE has no liability for the underfunded amount and no termination liens ~~are attached to~~arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any underfunded amount assessed by the PBGC. No reserves have been established by PGE for any amounts related to this issue.

Minimum Funding Obligation

If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically ~~attaches to~~arises against the assets of every member of the controlled group. The lien is in favor of the plan, but may be enforced by the PBGC. The PBGC may perfect the lien by appropriate filings. PGE management believes that the lien ~~does~~would not take priority over other previously perfected liens on the assets of a member of the controlled group. If Enron does not timely satisfy its minimum funding obligation in excess of $1 million, a lien will ~~attach to~~arise against the assets of PGE and all other members of the Enron controlled group. The PBGC would be entitled to ~~file~~perfect the lien and enforce it in favor of the Enron Plan against the assets of PGE and other members of the Enron controlled group. However, substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of ~~i ts~~its First Mortgage Bonds. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien.

Based on discussions with Enron management, PGE management understands that Enron has made all required contributions to date through ~~July~~October 15, 2002. PGE does not know if Enron will make contributions as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the Enron controlled group. Until Enron ~~does miss a contribution,~~misses contributions exceeding $1 million, PGE has no liability and no liens will ~~attach to~~arise against any PGE property. Other members of Enron's controlled group could, to the extent of any legal rights available to them, seek contribution from PGE for their payment of any missed payments demanded by the PBGC. No reserves have been established by PGE for any amounts related to this issue.

Retiree Health Benefits

Under COBRA, retirees of a bankrupt employer who lose coverage under a group health plan of the employer as a result of certain bankruptcy proceedings, are entitled to elect continuation of health coverage in a group health plan maintained by the bankrupt employer or a member of its controlled group. PGE management understands, based on discussion with Enron management, that Enron ~~had provided~~provides a plan for health insurance for certain retirees, and that the actuarial liability ~~amounts~~for such coverage amounted to approximately $70 million at December 31, 2001. Management further understands that to meet its obligation, Enron has set aside approximately $34 million of assets in a VEBA trust which may be protected under ERISA from Enron's creditors, leaving an unfunded liability of approximately $36 million at December 31, 2001. In the event that Enron terminates its retiree group health plan, the retirees must be provided the opportunity to purchase continuing coverage from Enron's group health plan , if any, or the ~~appr opriate~~appropriate group health plan of another member of the controlled group. Neither Enron nor any member of the controlled group would be required to fully fund the benefit or create new plans to provide coverage, and retirees would not be entitled to choose from which plan to obtain coverage. Retirees electing to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the most appropriate plan in the Enron controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the ~~average~~ cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

Management believes that in the event Enron terminates retiree coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on discussion with Enron management, PGE management understands that most of the retirees that would be affected by termination of the Enron plan are from solvent members of the controlled group and few, if any, live in Oregon. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing COBRA coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be material. No reserves ~~ha ve~~have been established by PGE for any amounts related to this issue.

Income Taxes

Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with Portland General Corporation. Based on discussions with Enron's management, PGE management understands ~~based on discussion with Enron management,~~ that PGE ceased to be a member of Enron's consolidated group on May 7, 2001.

Enron's management has provided the following information to PGE:

~~1998-2000.~~ 1996-2001. Enron's consolidated tax return for 2001 ~~is expected to be~~was filed ~~in the fall of~~on September 13, 2002 and Enron expects this return and claims by the IRS, if any, ~~will~~to be included in the bankruptcy process, as ~~discussed~~described below.

B. For years 1996-1999, Enron and its subsidiaries generated substantial ~~NOLs.~~net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. ~~Enron and its subsidiaries anticipate that the~~Enron's 2001 consolidated tax return ~~will show~~showed a substantial loss, which ~~would~~will be carried back to tax year 2000, and is anticipated to result in a tax refund offor taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from the ongoing IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns. However, to the extent that such audit results in interest owing by the Enron consolidated group for periods after Enron filed its bankruptcy petition ("postpetition interest") or in penalties that would not have a statutory priority over general unsecured creditors, the IRS could seek to collect such amounts from consolidated group members not in bankruptcy, such as PGE. The last day that the IRS can file a proof of claim for prepetition taxes in the bankruptcy case is March 31, 2003. It is anticipated that the IRS will file a proof of claim through 2001 prior to that date. If there were additional tax liabilities claimed by the IRS, these would be satisfied by funds in the bankruptcy estate ahead of unsecured Enron ~~cred itors.~~creditors, but claims for postpetition interest would not be allowed, and claims for penalties would be treated on a par with the claims of general unsecured creditors.

Although management cannot predict with certainty the outcome of the IRS ~~audits,~~audit, based on the above, it believes it is unlikely at this time that any tax claims by the IRS would ~~offset~~exceed the substantial NOLs available to the Enron consolidated tax returns. Claims for postpetition interest and claims for penalties, if any, could not be offset by these NOLs. If the IRS did seek payment and Enron did not pay, the IRS could look to one or more members of the consolidated group, including PGE. If the IRS did look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, are available for recovery in Enron's bankruptcy proceeding, or to otherwise obtain contributions from the other solvent members of the consolidated group, who are not debtors in the bankruptcy case. As a result, management believes the income tax, interest, and penalty exposure to PGE would not be ~~minimal, if any,~~material related to any future liabilities from Enron's consolidated tax returns during the ~~period~~per iod PGE was a member of Enron's consolidated tax returns. If PGE is not de-consolidated from Enron's consolidated tax g roup for periods after 2001, PGE would be severally liable for the tax liability of the consolidated group for those periods along with any other members of the consolidated group. No reserves have been established by PGE for any amounts related to this issue.

Management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's ~~day to day~~day-to-day operations. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997 ~~(the merger conditions)~~(Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the ~~merger conditions,~~Merger Conditions, PGE cannot make any distribution to Enron that would ~~c ause~~cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The ~~merger conditions~~Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings.

Neither does management believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other transfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course.

Enron Debtor in Possession Financing

PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a ~~debtor-in-possession~~debtor in possession credit agreement with Citicorp USA Inc. and JP Morgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the ~~debtor-in-possession~~debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PG E unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 8,7, Enron Bankruptcy, in the Notes to Financial Statements.

Enron Auction Processes Related to PGE

On May 3, 2002, Enron presented to its Unsecured Creditors' Committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of PGE in the new company would be subject to potential sale to a different buyer under a Section 363 auction process, which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the Unsecured Creditors' Committee and is one of many options Enron may pursue.

Public Ownership Initiatives

In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 for professional advice regarding the City's potential acquisition of PGE, including condemnation of the Company's assets.

Initiative petitions are being circulated in counties within which PGE serves retail customers by groups attempting to gather sufficient signatures to place measures on March and May 2003 ballots. If passed, these measures could result in the formation of Peoples' Utility Districts (PUDs) which would have the authority to acquire PGE's distribution assets within the PUD districts.

PGE will oppose any efforts to condemn the Company's assets.

Power Cost Mechanisms

In order to protect both PGE and its customers from price volatility in the wholesale power and natural gas markets, the OPUC has authorized the Company to defer for later recovery from retail customers actual net variable power costs which differ from certain baseline amounts approved by the ~~Commission.~~OPUC. During the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received ~~Commission~~OPUC approval to recover the approximate $91 million balance (including $7 million of interest), over a period of ~~3 1/~~3-1/2 years (April 1, 2002 - September 30, 2005). Such recovery is being offset by the refund of approximately $22 million in ~~certain~~ customer credits over the period April 1, 2002 through December 31, 2002, with no net effect on customer rates during this time. Such customer credits consist ~~primarily~~ of a final distribution received in 2000 related to PGE's terminated ~~membership~~member ship in ~~Nuc lear~~Nuclear Electric Insurance Limited (NEIL).

In its August 2001 general rate order, the OPUC approved a Power Cost Adjustment mechanism extending from October 1, 2001 through the end of 2002. Under this mechanism, PGE shares with its retail customers the difference between actual net variable power costs and the amount used to establish base energy ~~rates.~~rates on October 1, 2001. In addition, PGE shares with customers the difference between actual energy revenues and a pre-determined base. A portion of the net difference between pre-determined levels and actual net variable power costs and revenues (termed "Power Cost Variance") is subject to recovery (or refund). Any Power Cost Variance exceeding $28 million is shared with PGE customers, with any variance between $28 million and $38 million shared equally. Of the next $62 million (up to $100 million), PGE will collect or refund 85% of the variance, and of the next $100 million (up to $200 million), PGE will collect or refund 90% of the variance. For variances that exceed $200 million, PGE will collect or ~~re fund~~refund 95% of the variance.

A Power Cost Adjustment Account is maintained to record both the calculated Power Cost Variance and amounts actually collected from or refunded to customers. Any tariff rate adjustments, calculated on a quarterly basis, are subject to review and approval by the OPUC. In the first ~~nine~~twelve months of the mechanism, approximately ~~$31~~$26 million was deferred for future recovery from retail customers, all of which applied to the first ~~half~~nine months of 2002. ~~In May~~On October 7, 2002, PGE filed with the OPUC a proposed tariff ~~schedules~~rate schedule that ~~offer two alternatives~~provides for collection from retail customers of the deferred ~~Power Cost Variance.~~power cost variance beginning in November 2002. The ~~Commission has postponed a decision on such alternatives pending PGE's filing of its next Power Cost Adjustment forecast, anticipated in August 2002.~~

~~PGE has filed a~~ proposed tariff ~~with~~would have no net effect on customer rates, as the ~~OPUC~~period over which it is currently collecting deferred power costs (applicable to ~~continue~~ the January 2001 - September 2001 period of the initial mechanism) would be extended in order to offset the increase resulting from the collection of deferred costs applicable to the period October 1, 2001 throu gh the end of 2002. Under the Company's proposal, PGE would collect both deferred balances by approximately 2006-2007. PGE will not have a power cost adjustment mechanism ~~beyond 2002.~~in place for 2003.

Power Cost Forecast/Rate Reduction

On July 1, 2002, PGE filed with the OPUC an updated 2003 power cost forecast that ~~estimates~~estimated a reduction in power costs utilized in the Company's most recent general rate filing. The updated forecast ~~projects~~projected a 7 ~~to13~~to 13 percent price decrease for the Company's business customers and a one percent decrease for residential customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased significantly in recent months. Benefits to residential customers are expected to be smaller as their rates are affected more by PGE's ~~cost~~costs of generation ~~which has increased due to higher natural gas prices, as well as the cost of~~and electricity from BPA, which ~~is expected~~increased its rates on October 1, 2002.

On October 30, 2002, the OPUC issued an order that addressed several issues related to ~~increase~~recovery of projected 2003 net variable power costs, among other things, the rate treatment of certain power purchase contracts that provide for delivery of power in 2003. In the order, the OPUC disallowed as imprudent about $15 million of power costs related to four forward power purchase contracts that were entered in early 2001 during the energy crisis when power prices were high and volatile. The order will result in ~~October 2002.~~

~~PGE anticipates~~an additional overall rate reduction of approximately two percent for PGE's retail customers. The exact amount of the rate reduction will be determined upon the Company's mid-November 2002 filing ~~additional~~of final power cost ~~updates throughout~~recovery for 2003. New prices, reflecting the ~~remainder of 2002 and~~above reductions, will ~~submit its final forecast for OPUC approval in mid-November, with new prices to~~ be effective January 1, 2003.

In addition, since PGE will not have a power cost adjustment mechanism in place in 2003, variances between actual net variable power costs and the final amount set in rates for 2003 will be reflected in PGE's 2003 earnings.

Resource Plan

Under OPUC rules implementing Oregon's electric industry restructuring law, electric utilities were required to file a resource plan, including an evaluation of, and recommendations regarding, the disposition of existing generating resources. Such recommendations were required to facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers.

Although the OPUC has not adopted final rules governing resource plan updates, PGE filed an Integrated Resource Plan onin August 9, 2002, updating its plan filed in late 2000. In its updated plan, PGE ~~has described~~describes its strategy to meet the electric energy needs of its customers, with an emphasis on long-term price stability, least cost, and supply reliability. ~~PGE~~The plan includes reduced reliance on volatile short-term wholesale power contracts and increased emphasis on longer-term supplies linked to the output of specific power plants. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, and meeting seasonal peaking requirements through a variety of measures. The plan includes continuing support for Oregon's electricity restructuring plan and for additional methods to address unique needs of individual customers. The OPUC has ~~requested~~initiated a ~~prehearing conference~~schedule for input and review, with ~~the Commission to schedule a review~~an acknowledgement of ~~the plan.~~PGE's pl an anticipated in early 2003.

~~Accounting for Energy Trading Contracts~~PGE Pension Plan

PGE and its actuary are in the process of evaluating the effects of changing conditions in the financial markets on the net periodic pension cost (NPPC), benefit obligations and funding status of PGE's pension plan (Plan). The discount rate used to calculate current benefit obligations under the Plan (which is based on rates at which pension benefits could be effectively settled) could be adjusted downward by as much as three-quarters of a percent from the 7.25% rate used at the beginning of 2002 depending upon activity in the bond market during the remainder of 2002. Due to this lower discount rate and also due to plan experience differences as compared to earlier assumptions, the projected benefit obligation (PBO) is anticipated to be much higher at December 31, 2002 than the PBO at December 31, 2001.

Additionally, based on PGE's latest evaluation through October 2002, it appears that the fair value of Plan assets at December 31, 2002 will be materially lower than the fair value of Plan assets at December 31, 2001. The primary cause of the reduction in value is the lower market value of the portfolio of assets in the Plan trust. However, the long-term rate of return on assets, derived from an assessment by our asset management consultant of the expected returns from the various classes of assets in the Plan trust, is not expected to change from the previous year.

The ~~Emerging Issues Task Force (EITF)~~Plan's positive funding status of $91 million at December 31, 2001, could move to an underfunded position by year-end 2002 if recent financial market conditions continue. A minimum liability recognition is not expected, however, since the ~~FASB recently reached~~fair value of Plan assets is expected to remain above the accumulated benefit obligation (ABO). The NPPC projection for 2003 is expected to continue to provide a ~~consensus~~credit to income, although a much lower credit than in Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, regarding financial statement presentation of revenues and expenses associated with "energy trading contracts." The EITF requires that, effective for the third quarter of 2002, such revenues and expenses be reported on a net basis for all periods presented. PGE has historically presented such activities on a gross basis as contracts settled, with sales recorded in Operating revenues and power purchases recorded in Purchased power and fuel expense.

PGE continues to evaluate the financial statement reclassification required by EITF Issue No. 02-3. PGE believes that implementation of the consensus in EITF Issue No. 02-3 will likely have a material impact on total revenues and expenses, but will have no impact on its financial condition or results of operations.2002.

Receivables - California Wholesale Market

As of ~~August~~November 1, 2002, PGE has accounts receivable totaling approximately ~~$74~~$66 million that may be affected by the financial condition of two major California utilities. Significant increases in wholesale power prices in the last half of 2000 and in early 2001 severely affected the financial stability of both companies and resulted in the declaration of bankruptcy by one of the utilities. A credit reserve has been established by PGE for amounts due under wholesale electricity contracts. For further information, see Note 6,5, Receivables-California Wholesale Market, in the Notes to Financial Statements.

Refunds on Wholesale Transactions

~~The FERC has issued an~~In a June 19, 2001 order ~~directing certain electricity suppliers, including PGE, to supply information regarding wholesale power sales to California made in 2000 and 2001. Settlement discussions have taken place between~~adopting a price mitigation program for 11 states within the ~~power suppliers, the state of California, and~~WSCC area, the FERC ~~regarding potential refunds by suppliers. The discussions did not resolve~~referred to a settlement judge the ~~issues and hearings were held in March 2002, with additional hearings scheduled for August 2002 to determine any potential~~issue of refunds for ~~sales in the California spot market~~non federally-mandated transactions made between October 2, 2000 and June 20, ~~2001.~~2001 in the spot markets operated by the ISO and the PX.

On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in March 2002, to determine the appropriate proxy prices to use, and in August through October, 2002, to determine how to calculate amounts owed to and refunds owed by sellers into the California market. Using the established methodology, the Company's potential refund obligation is currently estimated to be in the range of $20 million to $30 million. Final determination of refunds is to be made after review by FERC of calculations filed by the ISO. PGE will have the opportunity to challenge the FERC's determination of the amount of any proposed refunds.

The FERC has not yet determined how the comments or these subsequent events will affect the methodology used in the refund hearings.

FERC hearings have also been held to determine whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest by PGE and other suppliers from December 25, 2000 through June 20, 2001. A FERC Administrative Law Judge issued a recommended order, dated September 24, 2001, that claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action. Several of the complainants in this case have filed motions to reopen the ~~hearing. Those~~hearing, with such motions ~~are also~~ awaiting FERC action. FERC could consider all of the factors discussed above in reaching a decision whether to grant such motions.

~~Any~~The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.

In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism. This could potentially mitigate the financial effect of any refunds made or received by the Company. ~~In addition, PGE believes that any refunds related to California sales that may be required by the FERC can be offset by accounts receivable related to sales in California.~~

See Note 6,5, Receivables - California Wholesale Market, and Note 7,6, Refunds on Wholesale Transactions, in the Notes to Financial Statements for further information.

Wholesale Price Mitigation

In June 2001, the FERC adopted a price mitigation program for the power system serving 11 Western states, adopting a new benchmark formula ~~that limits~~limiting prices for electricity sold in the spot markets at all times throughout the region through September 2002. The program applies to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.

Under the program, a ceiling price is set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. ~~The ceiling~~Such price, ~~reflecting~~initially set at $91.87/MWh, reflects specified fuel, operations, and maintenance costs, and is based upon the bid submitted by the highest cost gas-fired generating unit ~~whose~~supplying power ~~is needed when reserves in California fall below 7 percent, triggering~~during a Stage 1 supply emergency. ~~No bid to sell power may exceed~~

In December 2001, the ceiling price as long as the reserve emergency is in place. When reserves again exceed 7 percent, removing the emergency, the ceiling price drops to 85 percent of the highest hourly price in effect during the most recent Stage 1 reserve emergency. Because of increased credit risk, wholesale electricity sales to California are allowed a 10 percent surcharge. The initial ceiling price was set at $91.87/MWh.

PGE and other Northwest utilities expressed concerns regarding potentially adverse consequences of price mitigation measures on Northwest citizens, utilities, power marketers and generators. In response, the FERC ~~in December 2001~~ temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ~~California Independent System Operator. The changes acknowledged~~ISO, recognizing differences between ~~the~~ Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. ~~They include the discontinuation~~The changes, including a ceiling price of ~~the above reserve deficiency method to formulate the mitigated price and utilize instead incremental changes in the cost of natural gas to trigger adjustments in the price, initially set at~~ $108/~~MWh. The changes~~MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.

In a July ~~17,~~ 2002, ~~order,~~ the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 1,31, 2002. The new ceiling price ~~which~~ applies to all sales of electricity in the Western Systems Coordinating Council, is intended to reflect market conditions and allow prices that properly signal energy supply scarcity and provide greater opportunity for generators to recover their costs.WSCC. In addition to the new price ceiling, the FERC order established conditions and rules ~~that will guide~~guiding participation in Western wholesale electricity markets, ~~after the current wholesale price mitigation plan expires in September 2002,~~ including automatic price mitigation procedures ~~that will~~to be implemented during periods of tight ~~supplies to help ensure fair prices.~~supplies.

Federal Investigations - Wholesale Power Markets

On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WSCC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. Although PGE was not specifically named in the FERC directive, the Company bought and sold power in the region during the relevant period and voluntarily submitted the requested information.

Enron Trading Strategies

In early May 2002, the FERC received information contained in memos released by Enron, indicating that Enron, through subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. On May 22, 2002, PGE submitted the results of its investigation ~~which~~to the FERC. The material submitted to FERC did not ~~uncover~~show any instances where the Company ~~itself,~~ engaged in or knowingly aided deceptive or misleading trading strategies. However, PGE ~~did discover~~reported that it was among other intermediaries in a series of trading activities that occurred on 15 days from ~~Apri l~~April through June 2000 where EPMI was found to be at both ends of the transaction chain (revised from 17 days, as initially reported). The trading transactions identified during the 15-day period moved about 2,300 (revised from 2,500, as initially reported) megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a step in one of the enumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.

On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. Such order states that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. PGE believes that it has fully

cooperated with the FERC's inquiry. On June 14, 2002, PGE filed a response with the FERC, indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE.

On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket EL02-114-000), the FERC ordered investigation of PGE and Enron Power Marketing, Inc. (EPMI) related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 22, 2002 data request and June 4 Show Cause Order. In the second order (Docket EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI are included as parties to the investigation. In the event that violations are determined to have occurred, the investigations will address remedies, including possible revocation of the companies' market-based rate authority and potential refunds for future wholesale activity.

In the orders, the FERC established October 15, 2002 as the refund effective date. Purchasers of electric energy from PGE at market-based rates after this date could be entitled to a refund of the difference between the market-based rate and rates deemed just and reasonable by the FERC if PGE were to lose its market-based rate authority.

Certain posting transactions were discovered by PGE and self reported to the FERC in April 2002. The transactions involving Avista were reported to the FERC by PGE in the Company's May 22, 2002 response to a data request issued by the FERC on May 8, 2002.

Pre-hearing conferences have been held in both dockets. The hearing in Docket No. EL02-114-000 is scheduled to begin on April 1, 2003; the hearing in the EL02-115-000 docket is currently scheduled to begin on April 28, 2003, although the administrative law judge has indicated preference for a more accelerated schedule.

PGE will continue to cooperate to the fullest extent with the investigations. PGE continues to believe that it has fully complied with the FERC investigation initiated on February 13, 2002, and that it has not engaged in deception or market manipulation.

Wash Sales - Electricity

On May 21, 2002, the FERC issued a data request and request for admissions to all sellers of wholesale electricity and/or ancillary services in the U.S. portion of the WSCC during the years 2000-2001. Such request ordered sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. Although PGE was not listed in the data request, PGE conducted an investigation and submitted the results in a response to the FERC on May 31, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request to the extent that such activities artificially inflated trading volumes, revenues or market prices. PGE's response also noted that it had no reason or incentive to artificially inflate trading volumes or revenues, as the primary purpose of its wholesale trading operations is to manage risk and reduce costs for its retail customers by balancing load requirements and maximizing the value of owned ~~generation~~generat ion and purchase contracts to the extent that available supply ~~is excess to~~exceeds the needs of the Company's firm customers.

Wash Sales - Natural Gas

On May 22, 2002, the FERC issued a data request and request for admissions to all sellers of natural gas in the U.S. portion of the WSCC and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request.

Other

On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC), which regulates futures contracts traded on U.S. exchanges, subpoenaed documents from PGE regarding the Company's electricity and natural gas trading, including any "wash" trading used to inflate revenue and trading volume. PGE forwarded documents previously prepared for the FERC investigation (described above). In addition, PGE has been requested to provide information and documents with respect to various federal and state actions and investigations of Enron.

PGE is cooperating and will continue to cooperate to the fullest extent with these investigations.

Antitrust Litigation

In late 2001, the State of California and numerous individuals, businesses and California cities, counties and other governmental entities filed class action law suits ~~(Wholesale~~("Wholesale Electricity Antitrust ~~Cases)~~Cases") against various individuals, utilities, generators, traders and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties) and Reliant Energy Services, Inc.; Reliant Ormond Beach, Inc.; Reliant Energy Etiwanda, Inc.; Reliant Energy Ellwood, Inc.; Reliant Energy Mandalay, Inc.; Reliant Energy Coolwater, Inc. (Reliant Parties), alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and ~~penalties.~~penaltie s. The plaintiffs have sought to have the case dismissed on jurisdictional grounds.

~~In late April 2002, the~~The Duke ~~parties~~Parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. An open extension of time for PGE and the other utilities to respond to the cross complaint has been agreed to by the parties until 30 days after a ruling on jurisdiction is made in the original case.

The Reliant Parties also have filed a cross complaint against PGE and the other utilities, generators, traders and other entities similar to the cross complaint filed by the Duke Parties. The parties have stipulated to place this case in abeyance until 30 days after a ruling on jurisdiction is made.

In September 2002, the Court heard arguments on Motions to Sever and Remand by plaintiffs and Motions to Dismiss by cross-defendants.

At this time, management is unable to make any assessment of, or determination with respect to, ~~this complaint.~~these complaints.

California Attorney General Complaint

In May 2002, the Attorney General of California filed a complaint in state court alleging failure of PGE to comply with FERC approval requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped ~~price;"~~price"; no specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to ~~federal court~~U.S. District Court and a Motion to Dismiss on preemptive ~~grounds,~~grounds. The Attorney General moved to remand to state court, which was denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and moved to stay action in the District Court pending the outcome of the appeal. The District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss the case were argued on September 26, 2002 and are currently under advisement by the District Court.At this time, management is unable to make any assessment of, or determination with ~~a hearing currently scheduled for late August 2002.~~respect to, this complaint.

Trojan Investment Recovery

Due to the closure of the Trojan nuclear plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant. (For further information, see Note 4,3, Legal and Environmental Matters, in the Notes to Financial Statements).

Union Grievances

Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enron, not PGE. The IBEW f iled an answer and counterclaim that the issue is arbitrable, and PGE filed a reply ~~which~~that denied the counterclaim and raised four affirmative defenses. ~~It is not likely that~~The Circuit Court has set a ~~hearing on~~trial date of May 22, 2003. Management cannot predict the ultimate outcome of these ~~motions and counterclaim will take place before the fall of 2002. No reserves have been established by PGE for any amounts related to this issue.~~grievances.

Environmental Matter

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Subsequently, the EPA included Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund").

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" ~~(Voluntary Agreement)~~("Voluntary Agreement") with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement. ~~Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.~~

In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. Such notice included a "Portland Harbor Initial General Notice List" containing sixty-eight other companies that the EPA believes may be Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

In accordance with the Voluntary Agreement, in March 2001, PGE submitted a final ~~study~~investigation plan to the DEQ for ~~approval, with testing initiating~~approval. DEQ approved the plan and in June ~~2001.~~2001, PGE ~~has~~ performed initial investigations and remedial activities based upon the approved ~~study~~investigation plan. Such investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the ~~potential~~ liability of ~~responsible companies,~~Potentially Responsible Parties, including PGE. (For further information, see Note 4,3, Legal and Environmental Matters, in the Notes to Financial Statements).

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales decreased ~~by 4.3%~~2.2% for the ~~six~~nine months ended ~~June~~September 30, 2002, compared to the same period last year. Manufacturing sector sales declined ~~10.2%~~2.5%, with ~~all~~most segments of this sector down from last year. Excluding the effects of the Demand Buyback program, in which PGE paid large customers to reduce their load during peak demand periods in 2001, manufacturing sector sales declined about ~~14%~~9%. Commercial and residential energy sales were down ~~2.2%~~3.4% and ~~1.8%~~0.6%, respectively. PGE forecasts retail energy sales in 2002 will remain down somewhat from last year, as continued customer growth is offset by both a slow economy and increased conservation efforts.

Power Supply

Hydro conditions in the region have significantly improved from last ~~year, although they remain below normal levels.~~year. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, ~~currently project~~indicate the January-to-July runoff at ~~96%~~97% of normal, compared to 55% of normal last year.

PGE generated 37% of its retail load requirement in the first ~~half~~nine months of 2002, with hydro generation comprising about ~~11%~~9% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. Due to increased customer use of air conditioning, PGE's summer load has become increasingly sensitive to high temperatures. On August 13, 2002, a new summer record for electricity consumption (3,408 megawatts) was set; this exceeded the Company's previous summer peak consumption of 3,341 in July 1998. The Pacific Northwest peak season continues to be in winter months, when home and business heating and lighting cause the highest demand. PGE's all-time peak of 4,073 megawatts occurred in December 1998.

PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers. Although surplus generation has diminished in recent years due to economic and population growth in the western United States, recent construction of new generating plants has increased the region's capacity to meet its power needs. In addition, a reduction in demand from a slowing economy and increased conservation efforts, along with increased natural gas supplies and federal price mitigation, have together resulted in significantly lower market prices for both electricity and ~~na tural~~natural gas than in the first ~~half~~nine months of 2001.

Hydroelectric Project Removal

On October 24, 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others that provides for the removal of the Company's 22-MW Bull Run hydroelectric project on the Sandy River, including the Marmot and Little Sandy Dams. In addition, the agreement provides for the protection of threatened fish species and the transfer of 1,500 acres of PGE-owned land to a nonprofit organization toward the creation of a 5,000-acre wildlife and public recreation area. The agreement provides for the removal of the Marmot Dam in 2007 and the Little Sandy Dam in 2008.

PGE's license on the Bull Run project, issued by the FERC, expires in November 2004 and will not be renewed. Under the terms of the agreement, the project will operate until the removal of Little Sandy Dam. PGE's current rates include recovery of its remaining plant investment through the end of the project's existing license period. Such rates also include recovery, over a ten-year period beginning October 2001, of about $16 million in estimated decommissioning costs.

New Accounting Standards

See Note ~~10,~~8, New Accounting Standards, in the Notes to Financial Statements for information regarding new SFAS No. 143, Accounting for Asset Retirement Obligations, and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities.

Statement Regarding Forward-Looking Statements

This report contains statements that are forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," or similar expressions identify forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE, as applicable, to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGE's expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

matters related to Enron and certain of its subsidiaries' filings to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);

events related to Enron's bankruptcy proceedings;

effects of electric industry restructuring in Oregon and in the United States, including wholesale competition;

governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;

changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;

wholesale energy prices (including the effect of FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;

the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;

operational factors affecting PGE's power generation facilities;

changes in, and compliance with, environmental and endangered species laws and policies;

financial or regulatory accounting principles or policies imposed by governing bodies;

residential, commercial, and industrial growth and demographic patterns in PGE's service territory;

the loss of any significant customer, or changes in the business of a major customer, that may result in changes in demand for PGE services;

the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;

capital market conditions, including interest rate fluctuations and capital availability;

changes in PGE's credit ratings, which ~~may~~could have an impact on the availability and cost of capital;

legal and regulatory proceedings and issues;

employee workforce factors, including strikes, work stoppages, and the loss of key executives; and,

general political, economic, and financial market conditions.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

PGE is exposed to various forms of market risk which include changes in commodity prices, foreign exchange rates and interest rates. These changes may affect the Company's future financial results.

Commodity Price Risk

PGE's primary business is to provide electricity to its retail customers. The Company uses both long-term and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to seasonal fluctuations in the retail demand for electricity and variability in generating plant operations. In meeting these needs, PGE is exposed to market risk arising from the need to purchase power and to purchase fuel for its natural gas and coal fired generating units. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options, and futures contracts to mitigate risk that arises from market fluctuations of commodity prices.

Gains and losses from non-trading instruments that reduce commodity price risk are recognized when settled in purchased power and fuel expense, or in wholesale revenue. In addition, PGE policy allows the use of these instruments for trading purposes, which may expose the Company to market risks resulting from adverse changes in commodity prices. ~~Unrealized~~Under EITF 02-3, gains and losses on such instruments are recognized on a net basis within ~~"Purchased power and fuel" expense~~Operating revenues on PGE's Income Statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments.

The Company actively manages its risk to ensure compliance with its risk management policies. PGE monitors open commodity positions in its energy portfolios using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 ~~months, including~~monthsincluding estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the trading portfolio in the first ~~half~~nine months of 2002 was ~~$0.2~~$0.1 million, $0.4 million, and zero, respectively, and in the first ~~half~~nine months of 2001 was ~~$1.3~~$1.0 million, $3.6 ~~milli on,~~million, and ~~$0.2 million,~~zero, respectively. The value at risk on the non-trading portfolio is not meaningful since the majority of the portfolio is effectively accounted for on an accrual or settlement basis.

Additionally, in its non-trading activities, the Company has a power cost mechanism in place that allows PGE to defer, for future ratemaking treatment, actual net variable power costs that differ from certain baseline amounts approved by the ~~OPUC.~~OPUC in its non-trading activities. (For additional information, see "Power Cost Mechanisms" in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations).

Foreign Currency Risk

PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars, primarily in its non-trading portfolio. 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. PGE monitors its exposure to fluctuations in the Canadian exchange rate and determines an appropriate hedging strategy.

At ~~June~~September 30, 2002, a 10% change in the value of the Canadian dollar would result in a change in pre-tax income of approximately $4$3 million at the time the transactions settle over the next ~~21 months.~~18 months, including approximately $1 million applicable to transactions that settle during the remainder of 2002. However, effects of such value changes would be reflected in the calculation of net variable power costs under PGE's power cost mechanism, which would mitigate their financial effect upon the Company. Foreign currency risk in PGE's trading portfolio is immaterial to the Company's consolidated financial statements and is not expected to change materially in the near future.

Interest Rate Risk

PGE is exposed to risk resulting from changes in interest rates on variable rate commercial paper, short-term borrowings, and long-term debt outstanding. The Company's exposure to interest rate risk has decreased since December 31, 2001, as variable rate debt was retired with proceeds from new fixed rate First Mortgage Bonds. Although ~~the Company~~PGE currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

Credit Risk

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews and setting limits and monitoring exposures, requiring collateral when needed, and using standardized enabling agreements which allow for the netting of positive and negative exposures associated with a counterparty. Despite such mitigation efforts, defaults by counterparties may periodically occur. Valuation allowances are provided for credit risk. Due to the settlement of power contracts since December 31, 2001, the Company's exposure to credit risk has decreased significantly.

Risk Management Committee

PGE has a Risk Management Committee, which is responsible for the oversight of commodity position and price risk, foreign currency risk and credit risk related to wholesale energy marketing activities. PGE's Risk Management Committee consists of officers with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, wholesale marketing, and generation operations. The Risk Management Committee approves trading and credit policies and procedures, establishes limits subject to Enron approval, and monitors compliance and risk exposure on a regular basis through reports and meetings.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures. The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's reports filed or submitted under the Exchange Act.

(b) Changes in Internal Controls. Since the Evaluation Date, there have not been any significant changes in the Company's internal controls or in other factors that could significantly affect such controls.

PART II

Other Information

Item 1. Legal Proceedings

~~For further information, see PGE's report on Form 10-K for the year ended December 31, 2001.~~

Citizens' Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O'Neill v. Public Utility Commission of Oregon, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, the Oregon Supreme Court

The URP appealed to the Marion County Circuit Court the OPUC's order that approved PGE's application of the accounting and ratemaking elements of the September 2000 settlement agreements and denied all of URP's challenges to such application. The URP also filed a similar appeal in Multnomah County Circuit Court.

On ~~July 1,~~October 17, 2002, ~~PGE~~URP filed ~~with~~in Marion County a Motion for Continuance to allow defendants more time to appeal. In the ~~Oregon Supreme Court a Notice of Mootness~~Motion, they indicated that they planned to move forward in Marion County and ~~Motion to Dismiss and Vacate~~not in Multnomah County.

On October 30, 2002, the ~~case.~~OPUC filed its answer in this proceeding in Marion County.

For further information, see PGE's report on Form 10-K for the year ended December 31, 2001.

Gordon v. Reliant Energy, Inc./Duke Energy Trading and Marketing, et al v. Arizona Public Service Company, et al, Superior Court of the State of California for the County of San Diego, Proceeding Nos. 4204 and 4205

~~On December 24, 2001, the State of California~~Reliant Energy Services, Inc., Reliant Ormond Beach, Inc., Reliant Energy Etiwanda, Inc., Reliant Energy Ellwood, Inc., Reliant Energy Mandalay, Inc., and numerous individuals, businesses and California cities, counties and other governmental entities filed class action law suits (Wholesale Electricity Antitrust Cases) against various individuals, utilities, generators, traders and other entities, including DukeReliant Energy ~~Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke~~Coolwater, Inc. (Reliant Parties) alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and penalties.

~~On April 23, 2002, the Duke parties~~have filed a cross complaint against PGE and the other utilities, generators, traders and other entities ~~not named in~~similar to the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose oncross complaint filed by the Duke ~~Parties under~~Parties. PGE was served and the ~~Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. An open extension of time has been agreed~~parties stipulated to byplace the ~~parties~~case in abeyance until 30 days after a ruling on jurisdiction is ~~made in~~made.

On September 19, 2002, the ~~original case.~~Court heard arguments on Motions to Sever and Remand by plaintiffs and Motions to Dismiss by cross-defendants.

For further information, see PGE's report on Form 10-Q for the quarterly period ended March 31, 2002.

People of the State of California ex rel. Bill Lockyer, Attorney General v. Portland General Electric Company and Does 1 through 100. Superior Court of the State of California for County of San Francisco. Case No. CGC-02-408493

~~On May 30, 2002,~~Following PGE's filing to remove the case to the U.S. District Court, the Attorney General moved to remand to the state court. The motion was denied. The Attorney General filed an appeal to the Ninth Circuit Court of ~~California filed a complaint alleging failure~~Appeals of ~~PGE~~the denial of the motion to ~~comply with FERC approval requirements~~remand. The U.S. District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss were argued on September 26, 2002 and are currently under advisement by the District Court.

For further information, see PGE's report on Form 10-Q for ~~its market based sales of power in California. The complaint seeks fines and penalties under~~ the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price"; no specific damage claim is stated. On July 10, 2002, PGE filed a Notice of Removal to federal court. On July 17, 2002, PGE filed a Motion to Dismiss on preemptive grounds, with a hearing currently scheduled for late Augustquarterly period ended June 30, 2002.

Item 5. Other Information

~~New Directors~~Public Utility Holding Company Act of 1935

All of the common stock of PGE is owned, indirectly, by Enron. As the owner of PGE's common stock, Enron is a holding company for purposes of the Public Utility Holding Company Act of 1935 (the 1935 Act).

Prior to Enron's acquisition of PGE in 1997, PGE was the wholly owned utility subsidiary of Portland General Corporation, a holding company for purposes of the 1935 Act. Portland General Corporation annually filed an exemption statement on Form U-3A-2 to claim an exemption from all provisions of the 1935 Act (except Section 9(a)(2) thereof) under Section 3(a)(1) of the 1935 Act in accordance with Rule 2 promulgated thereunder. In connection with Enron's acquisition of PGE in 1997, Enron filed an exemption statement on Form U-3A-2 in accordance with Rule 2 and subsequently made annual filings of Form U-3A-2 until it filed an application on Form U-1 seeking an exemption by order under the 1935 Act. On October 7, 2002, the SEC issued an order scheduling a hearing on Enron's application. Under the current schedule, the hearing on the application is set to begin on December 5, 2002 and final briefs are due before the end of January 2003.

PGE has been informed by Enron that under Section 3(c) of the 1935 Act, Enron's exemption as a holding company from all provisions of the 1935 Act, except Section 9(a)(2), continues in effect based on its good faith filing on Form U-1 pending the conclusion of the hearing and the SEC's order therein.

Enron has filed papers with the SEC indicating that it believes it is entitled to exemption under the 1935 Act. However, it is possible that the SEC could deny Enron's application and require Enron to register as a holding company under the 1935 Act. If Enron registers under the 1935 Act, PGE will become subject to regulation under the 1935 Act as a subsidiary of a registered holding company.

The ~~following~~1935 Act imposes a number of restrictions on the operations of a registered holding company system. These restrictions include a requirement that the SEC approve, in advance, specified securities issuances (including issuances by utility subsidiaries that have not been ~~appointed~~authorized by the relevant state utility commissions), sales and acquisitions of utility assets or of securities of utility companies and acquisitions of interests in other businesses. The 1935 Act also limits the ability of companies in a registered holding company system to engage in non-utility ventures and regulates transactions between various affiliates within the holding company system, including the provision of services by holding company affiliates to the system's utilities, such as ~~Directors of PGE, effective July 2, 2002:~~

Raymond M. Bowen, Jr. - Has served as Executive Vice President, Chief Financial Officer and Treasurer of Enron since January 2002. Previously, he was Executive Vice President and Treasurer of Enron and, prior to that, was Chief Operating Officer of Enron Industrial Markets. Mr. Bowen joined Enron in 1996 as Vice President of Enron Energy Services and has also served as Vice President of Enron Capital Management, Vice President and Treasurer of Enron Capital & Trade Resources Corp., and Managing Director and Treasurer of Enron North America Corp.

Michael E. France - Has been a Partner with Zolfo Cooper, LLC, crisis management and corporate recovery specialists, since 1982, and is currently participating in corporate restructuring efforts at Enron. He has approximately thirty years of diversified business and professional experience, including approximately fifteen years working with troubled companies, their creditors, investors, and other interested parties. Previously, Mr. France was a financial consulting principal at Touche Ross & Co. (now Deloitte & Touche).

Robert H. Walls, Jr. - Has served as Executive Vice President and General Counsel for Enron since March 2002. Previously, he was Managing Director and Deputy General Counsel of Enron from August 2000 to March 2002 and, prior to that, was Managing Director and General Counsel of Enron International Inc. Mr. Walls joined Enron in 1992 as Vice President and General Counsel of Enron Power Corp. and became Senior Vice President and General Counsel of Enron Development Corp. in 1995.

~~The above individuals join the following as Directors of PGE:~~

~~Peggy Y. Fowler, Chief Executive Officer and President of PGE;~~

~~Stanley C. Horton, Chairman and Chief Executive Officer of Enron Global Services; and,~~

~~James J. Piro, Executive Vice President Finance, Chief Financial Officer & Treasurer of~~ PGE.

~~U.S. Nuclear Regulatory Commission (NRC) - Notice of Violation~~

~~On August 6, 2002, a NRC Notice of Violation was issued~~Although the actions that the SEC might take with respect to PGE asif it were to become a ~~result~~subsidiary of ~~an investigation conducted during the period from December 2, 1999 to July 3, 2001, relating to the loading~~a registered holding company cannot be predicted with certainty, PGE does not believe that becoming a subsidiary of ~~spent nuclear fuel into~~ a ~~multi-assembly sealed basket (MSB)~~registered holding company would have a material adverse affect on July 11, 1999. The NRC investigation, in part, was to review the circumstances surrounding the coatings qualification testing conducted by the MSB vendor for PGE. The coating was used to coat the surfacesits financial condition or results of the internal carbon steel components of the MSBs to be stored within spent fuel concrete storage casks at the Trojan Nuclear Plant, which was permanently shut down in 1993. The NRC's investigation did not substantiate that employees of PGE were aware that the coatings qualifications testing was inadequate.

As a result of the investigation, the NRC determined that two violations occurred. The first violation involved the submittal of information in support of an application for a dry fuel storage license under 10 CFR Part 72. The NRC determined that the submittal was not complete and accurate in all material respects because the report stated that the quality assurance program for the coating was performed under the control of PGE's vendor. The NRC found that PGE failed to verify that its vendor implemented its quality assurance program in certain respects. The NRC also identified a second violation involving a failure to establish measures to ensure that the coating applied to the surfaces of the internal components of the MSB complied with design basis requirements. This was found to have resulted in the MSB generating volatile organic compounds and flammable gases during loading operations.

The NRC categorized these violations as a Severity Level III problem based on the potential for safety consequences. The NRC categorizes violations as Severity Levels I through IV, with Severity Level I being the most serious. The NRC found that PGE took prompt action to correct and to prevent recurrence of the violations to achieve full compliance with the NRC requirements. PGE's corrective actions included the replacement of the MSB vendor.

Under the NRC's enforcement policy, a base civil penalty of $60 thousand is considered for a Severity Level III problem. However, due to PGE's prompt and comprehensive correction of the violations, and in recognition of the absence of previous escalated enforcement actions within the last two inspections, the NRC did not propose a civil penalty.

Item 6. Exhibits and Reports on Form 8-K

Exhibits:

(3)(i) Articles of Incorporation

* Copy of Articles of Incorporation of Portland General Electric Company [Registration No. 2-85001, Exhibit (4)]

* Certificate of Amendment, dated July 2, 1987, to the Articles of Incorporation limiting the personal liability of directors of Portland General Electric Company [Form 10-K for the fiscal year ended December 31, 1987, Exhibit (3)]

* Articles of Amendment, dated July 8, 1992, for series of Preferred Stock ($7.75 Series) [Registration Statement No. 33-46357, Exhibit (4)(a)]

Articles of Amendment to PGE Articles of Incorporation, dated September 30, 2002, creating Limited Voting Junior Preferred Stock (filed herewith)

(99) Additional Exhibits

99.1 Certification of Chief Executive Officer of Portland General Electric Company Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, for report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2002 (filed herewith)

99.2 Certification of Chief Financial Officer of Portland General Electric Company Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, for report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2002 (filed herewith)

b. Reports on Form 8-K

~~May 16, 2002 - Item 5. Other Events: Proposed Acquisition of PGE by NW Natural, PGE Credit Ratings, and FERC Investigation.~~

~~June 12, 2002 - Item 5. Other Events: Financing Activities.~~

August 1, 2002 - Item 5. Other Event: Credit Ratings.

August 13, 2002 - Item 5. Other Events: FERC Investigation and Structural Separation (Bankruptcy Remote Structure).

August 27, 2002 - Item 5. Other Events: Enron Auction Process and City of Portland Resolution.

September 12, 2002 - Item 5. Other Event: Structural Separation Criteria (Bankruptcy Remote Structure).

October 10, 2002 - Item 5. Other Event: Financing Activities.

October 28, 2002 - Item 5. Other Event: Financing Activities.

* Incorporated by reference as indicated.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned ~~hereunto~~thereunto duly authorized.

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

~~August 13,~~November 8, 2002

By:

/s/ James J. Piro

James J. Piro

Executive Vice President, Finance

Chief Financial Officer and Treasurer

~~August 13,~~November 8, 2002

By:

/s/ Kirk M. Stevens

Kirk M. Stevens

Controller and Assistant Treasurer

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, Peggy Y. Fowler, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Portland General 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:

a) 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;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) 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 the registrant's board of directors (or persons performing the equivalent function):

a) 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

b) 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 8, 2002

/s/ Peggy Y. Fowler
Peggy Y. Fowler
Chief Executive Officer and President

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, James J. Piro, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Portland General Electric Company;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) 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;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: November 8, 2002

/s/ James J. Piro
James J. Piro
Executive Vice President, Finance
Chief Financial Officer and Treasurer

EXHIBIT (3)(i)

The Articles of Incorporation of Portland General Electric Company shall be amended by deleting in its entirety Article VI and substituting therefor a new Article VI as follows:

ARTICLE VI.

The amount of the capital stock of the Corporation is:

COMMON STOCK. Three hundred seventy-five million dollars ($375,000,000) divided into one hundred million shares (100,000,000) of Common Stock and the par value of each share of such Common Stock is three and seventy-five one hundredths dollars ($3.75).

PREFERRED STOCK. Preferred Stock of this Corporation shall consist of (i) a class having a total par value of $250,000,000 divided into 2,500,000 shares having a par value of $100 per share issuable in series as hereinafter provided, (ii) a class having a total par value of $150,000,000 divided into 6,000,000 shares having the par value of $25 per share issuable in series as hereinafter provided and (iii) a class without par value consisting of 30,000,000 shares issuable in series as hereinafter provided.

LIMITED VOTING JUNIOR PREFERRED STOCK. Limited Voting Junior Preferred Stock of this Corporation shall consist of a class of one share having a par value of $1.00.

A statement of the preferences, limitations, and relative rights of each class of the capital stock of the Corporation, namely, the Preferred Stock of the par value of $100 per share, the Preferred Stock of the par value of $25 per share, the Preferred Stock without par value, the Limited Voting Junior Preferred Stock and the Common Stock of the par value of $3.75 per share, of the variations and relative rights and preferences as between series of the Preferred Stock of every class insofar as the same are fixed by these Supplementary and Amended Articles of Incorporation and of the authority vested in the Board of Directors of the Corporation to establish series of Preferred Stock of every class and to fix and determine the variations in the relative rights and preferences as between series insofar as the same are not fixed by these Articles of Amendment to the Amended Articles of Incorporation is as follows:

PREFERRED STOCK

(a) As used in these Articles, the term "Preferred Stock" shall include every class of Preferred Stock, but shall not include the Limited Voting Junior Preferred Stock. All shares of the Preferred Stock shall be of equal rank and identical except as to par value and except as permitted in this subdivision (a). Each class of Preferred Stock may be divided into and issued in series. Each series shall be so designated as to distinguish the shares thereof from the shares of all other series of the Preferred Stock of its class and all other classes of capital stock of the Corporation. To the extent that these Supplementary and Amended Articles of Incorporation shall not have established series of the Preferred Stock of a class and fixed and determined the variations in the relative rights and preferences as between series, the Board of Directors shall have authority, and is hereby expressly vested with authority, to divide the Preferred Stock of every class into series and, with the lim itations set forth in these Supplementary and Amended Articles of Incorporation and such limitations as may be provided by law, to fix and determine the relative rights and preferences of any series of a class of the Preferred Stock so established. Such action by the Board of Directors shall be expressed in a resolution or resolutions adopted by it prior to the issuance of shares of each series, which resolution or resolutions shall also set forth the distinguishing designation of the particular series of a class of the Preferred Stock established thereby. Without limiting the generality of the foregoing, authority is hereby expressly vested in the Board of Directors to fix and determine with respect to any series of a class of the Preferred Stock:

(1) The rate of dividend;

(2) The price at which and the terms and conditions on which shares may be sold or redeemed;

(3) The amount payable upon shares in the event of voluntary liquidation, and in the case of shares without par value also the amount payable in the event of involuntary liquidation, but such involuntary liquidation amount shall not exceed the price at which the shares may be sold as fixed in the resolution or resolutions creating the series;

(4) Sinking fund provisions for the redemption or purchase of shares; and

(5) The terms and conditions on which shares maybe converted.

All shares of the Preferred Stock of the same series shall be identical except that shares of the same series issued at different times may vary as to the dates from which dividends thereon shall be cumulative; and all shares of a class of the Preferred Stock, irrespective of series, shall constitute one and the same class of stock, shall be of equal rank, and shall be identical except as to the designation thereof, the date or dates from which dividends on shares thereof shall be cumulative, and the relative rights and preferences set forth above in clauses (1) through (5) of this subdivision (a), as to which there may be variations between different series. Except as may be otherwise provided by law, by subdivision (g) of this Article VI, or by the resolutions establishing any series of Preferred Stock in accordance with the foregoing provisions of this subdivision (a), whenever the presence, written consent, affirmative vote, or other action on the part of the holders of the Pre ferred Stock may be required for any purpose, such consent, vote or other action shall be taken by the holders of the Preferred Stock as a single body irrespective of class (unless these Articles or the law of the State of Oregon specifically require voting by class) or series and shall be determined by weighing the vote cast for each share so as to reflect its relative par value, or in the case of each share without par value the involuntary liquidation amount fixed in the resolution or resolutions creating the series, such that each share with par value shall have one vote per $100 of par value and each share without par value shall have one vote per $100 of involuntary liquidation value.

(b) The holders of shares of the Preferred Stock of each series shall be entitled to receive dividends, when and as declared by the Board of Directors, out of any funds legally available for the payment of dividends, at the annual rate fixed and determined with respect to each series in accordance with subdivision (a) of this Article VI, and no more, payable quarterly on the first days of January, April, July and October in each year or on such other date or dates as the Board of Directors shall determine. Such dividends shall be cumulative in the case of shares of each series either from the date of issuance of shares of such series or from the first day of the current dividend period within which shares of such series shall be issued, as the Board of Directors shall determine, so that if dividends on all outstanding shares of each particular series of the Preferred Stock, at the annual dividend rates fixed and determined by the Board of Directors for the respective series, shall not have been paid or declared and set apart for payment for all past dividend periods and for the then current dividend periods, the deficiency shall be fully paid or dividends equal thereto declared and set apart for payment at said rates before any dividends on the Common Stock shall be paid or declared and set apart for payment. In the event more than one series of the Preferred Stock shall be outstanding, the Corporation, in making any dividend payment on the Preferred Stock, shall make payments ratably upon all outstanding shares of the Preferred Stock in proportion to the amount of dividends accumulated thereon to the date of such dividend payment. No interest, or sum of money in lieu of interest, shall be payable in respect of any dividend payment or payments which may be in arrears.

(c) In the event of any dissolution, liquidation or winding up of the Corporation, before any distribution or payment shall be made to the holders of the Common Stock or the Limited Voting Junior Preferred Stock, the holders of the Preferred Stock of each series then outstanding shall be entitled to be paid out of the net assets of the Corporation available for distribution to its shareholders the par value of each share, in the case of shares with par value, or in the case of shares without par value the respective involuntary liquidation amount for each share as fixed and determined with respect to each series in accordance with Subdivision (a) of this Article VI, plus in all cases unpaid accumulated dividends thereon, if any, to the date of payment, and no more, unless such dissolution, liquidation or winding up shall be voluntary, in which event the amount which such holders, whether holders of shares with par value or shares without par value, shall be entitled so to be paid shall be the respective voluntary liquidation amounts per share fixed and determined with respect to each series in accordance with subdivision (a) of this Article VI, and no more. If upon any dissolution, liquidation or winding up of the Corporation, whether voluntary or involuntary, the net assets of the Corporation available for distribution to its shareholders shall be insufficient to pay the holders of all outstanding shares of Preferred Stock of all series the full amounts to which they shall be respectively entitled as aforesaid, the entire net assets of the Corporation available for distribution shall be distributed ratably to the holders of all outstanding shares of Preferred Stock of all series in proportion to the amounts to which they shall be respectively so entitled. For the purposes of this subdivision (c), any dissolution, liquidation or winding up which may arise out of or result from the condemnation or purchase of all or a major portion of the properties of the Corporation by (1) the United Sta tes Government or any authority, agency or instrumentality thereof, (2) a State of the United States or any political subdivision, authority, agency or instrumentality thereof, or (3) a district, cooperative or other association or entity not organized for profit, shall be deemed to be an involuntary dissolution, liquidation or winding up; and a consolidation, merger or amalgamation of the Corporation with or into any other corporation or corporations shall not be deemed to be a dissolution, liquidation or winding up of the Corporation, whether voluntary or involuntary.

(d) The Preferred Stock of all series, or of any series thereof, or any part of any series thereof, at any time outstanding, may be redeemed by the Corporation, at its election expressed by resolution of the Board of Directors, at any time or from time to time, at the then applicable redemption price fixed and determined with respect to each series in accordance with subdivision (a) of this Article VI. If less than all of the shares of any series are to be redeemed, the redemption shall be made either pro rata or by lot in such manner as the Board of Directors shall determine.

In the event the Corporation shall so elect to redeem shares of the Preferred Stock, notice of the intention of the Corporation to do so and of the date and place fixed for redemption shall be mailed not less than thirty days before the date fixed for redemption to each holder of shares of the Preferred Stock to be redeemed at his address as it shall appear on the books of the Corporation, and on and after the date fixed for redemption and specified in such notice (unless the Corporation shall default in making payment of the redemption price), such holders shall cease to be shareholders of the Corporation with respect to such shares and shall have no interest in or claim against the Corporation with respect to such shares, excepting only the right to receive the redemption price therefor from the corporation on the date fixed for redemption, without interest, upon endorsement, if required, and surrender of their certificates for such shares.

Contemporaneously with the mailing of notice of redemption of any shares of the Preferred Stock as aforesaid or at any time thereafter on or before the date fixed for redemption, the Corporation may, if it so elects, deposit the aggregate redemption price of the shares to be redeemed with any bank or trust company doing business in the City of New York, N. Y., the City of Chicago, Illinois, the City of San Francisco, California, or Portland, Oregon, having a capital and surplus of at least $5,000,000, named in such notice, payable on the date fixed for redemption in the proper amounts to the respective holders of the shares to be redeemed, upon endorsement, if required, and surrender of their certificates for such shares, and on and after the making of such deposit such holders shall cease to be shareholders of the Corporation with respect to such shares and shall have no interest in or claim against the Corporation with respect to such shares, excepting only the right to exercise such redemption or exchange rights, if any, on or before the date fixed for redemption as may have been provided with respect to such shares or the right to receive the redemption price of their shares from such bank or trust company on the date fixed for redemption, without interest, upon endorsement, if required, and surrender of their certificates for such shares.

If the Corporation shall have elected to deposit the redemption moneys with a bank or trust company as permitted by this subdivision (d), any moneys so deposited which shall remain unclaimed at the end of six years after the redemption date shall be repaid to the Corporation, and upon such repayment holders of Preferred Stock who shall not have made claim against such moneys prior to such repayment shall be deemed to be unsecured creditors of the Corporation for an amount, without interest, equal to the amount they would theretofore have been entitled to receive from such bank or trust company. Any redemption moneys so deposited which shall not be required for such redemption because of the exercise, after the date of such deposit, of any right of conversion or exchange or otherwise, shall be returned to the Corporation forthwith. The Corporation shall be entitled to receive any interest allowed by any bank or trust company on any moneys deposited with such bank or trust company as herein provided, and the holders of any shares called for redemption shall have no claim against any such interest.

Nothing herein contained shall limit any legal right of the Corporation to purchase or otherwise acquire any shares of the Preferred Stock.

(e) The holders of shares of the Preferred Stock shall have no right to vote in the election of directors or for any other purpose except as may be otherwise provided by law, by subdivisions (f), (g) and (h) of this Article VI, or by resolutions establishing any series of Preferred Stock in accordance with subdivision (a) of this Article VI. Holders of Preferred Stock shall be entitled to notice of each meeting of stockholders at which they shall have any right to vote, but shall not be entitled to notice of any other meeting of stockholders.

(f) It at any time dividends payable on any share or shares of Preferred Stock shall be in arrears in an amount equal to four full quarterly dividends or more per share, a default in preferred dividends for the purpose of this subdivision (f) shall be deemed to have occurred, and, having so occurred, such default shall be deemed to exist thereafter until, but only until, all unpaid accumulated dividends on all shares of Preferred Stock shall have been paid to the last preceding dividend period. If and whenever a default in preferred dividends shall occur, a special meeting of stockholders of the Corporation shall be held for the purpose of electing directors upon the written request of the holders of at least 10% of the Preferred Stock then outstanding. Such meeting shall be called by the secretary of the Corporation upon such written request and shall be held at the earliest practicable date upon like notice as that required for the annual meeting of stockholders of the Corporatio n and at the place for the holding of such annual meeting. If notice of such special meeting shall not be mailed by the secretary within thirty days after personal service of such written request upon the secretary of the Corporation or within thirty days of mailing the same in the United States of America by registered mail addressed to the secretary at the principal office of the Corporation, then the holders of at least 10% of the Preferred Stock then outstanding may designate in writing one of their number to call such meeting and the person so designated may call such meeting upon like notice as that required for the annual meeting of stockholders and to be held at the place for the holding of such annual meeting. Any holder of Preferred Stock so designated shall have access to the stock books of the Corporation for the purpose of causing a meeting of stockholders to be called pursuant to the foregoing provisions of this paragraph.

At any such special meeting, or at the next annual meeting of stockholders of the Corporation for the election of directors and at each other meeting, annual or special, for the election of directors held thereafter (unless at the time of any such meeting such default in preferred dividends shall no longer exist), the holders of the outstanding Preferred Stock, voting separately as herein provided, shall have the right to elect the smallest number of directors which shall constitute at least one-fourth of the total number of directors of the Corporation, or two directors, whichever shall be the greater, and the holders of the outstanding shares of Common Stock, voting as a class, shall have the right to elect all other members of the Board of Directors, anything herein or in the Bylaws of the Corporation to the contrary notwithstanding. The terms of office, as directors, of all persons who may be directors of the Corporation at any time when such special right to elect directors sh all become vested in the holders of the Preferred Stock shall terminate upon the election of any new directors to succeed them as aforesaid.

At any meeting, annual or special, of the Corporation, at which the holders of Preferred Stock shall have the special right to elect directors as aforesaid, the presence in person or by proxy of the holders of a majority of the Preferred Stock then outstanding shall be required to constitute a quorum of such stock for the election of directors, and the presence in person or by proxy of the holders of a majority of the Common Stock then outstanding shall be required to constitute a quorum of such stock for the election of directors; provided, however, that the absence of a quorum of the holders of either stock shall not prevent the election at any such meeting or adjournment thereof of directors by the other stock if the necessary quorum of the holders of such other stock shall be present at such meeting or any adjournment thereof; and, provided further, that in the absence of a quorum of holders of either stock a majority of the holders of such stock who are present in person or by proxy shall have power to adjourn the election of the directors to be elected by such stock from time to time, without notice other than announcement at the meeting, until the requisite quorum of holders of such stock shall be present in person or by proxy, but no such adjournment shall be made to a date beyond the date for the mailing of the notice of the next annual meeting of stockholders of the Corporation or special meeting in lieu thereof.

So long as a default in preferred dividends shall exist, any vacancy in the office of a director elected by the holders of the Preferred Stock may be filled at any meeting of shareholders, annual or special, for the election of directors held thereafter, and a special meeting of stockholders, or of the holders of shares of the Preferred Stock, may be called for the purpose of filling any such vacancy. So long as a default in preferred dividends shall exist, any vacancy in the office of a director elected by the holders of the Common Stock may be filled by majority vote of the remaining directors elected by the holders of Common Stock.

If and when the default in preferred dividends which permitted the election of directors by the holders of the Preferred Stock shall cease to exist, the holders of the Preferred Stock shall be divested of any special right with respect to the election of directors, and the voting power of the holders of the Preferred Stock and of the holders of the Common Stock shall revert to the status existing before the first dividend payment date on which dividends on the Preferred Stock were not paid in full, subject to revesting in the event of each and every subsequent like default in preferred dividends. Upon the termination of any such special right, the terms of office of all persons who may have been elected directors by vote of the holders of the Preferred Stock pursuant to such special right shall forthwith terminate, and the resulting vacancies shall be filled by the majority vote of the remaining directors.

(g) So long as any shares of the Preferred Stock shall be outstanding, the Corporation shall not without the written consent or affirmative vote of the holders of at least two-thirds of the Preferred Stock then outstanding, (1) create or authorize any new stock ranking prior to the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, or (2) amend, alter or repeal any of the express terms of the Preferred Stock then outstanding in a manner substantially prejudicial to the holders thereof. Notwithstanding the foregoing provisions of this subdivision (g), if any proposed amendment, alteration or repeal of any of the express terms of any outstanding shares of the Preferred Stock would be substantially prejudicial to the holders of shares of one or more, but not all, of the series of the Preferred Stock, only the written consent or affirmative vote of the holders of at least two-thirds of the total number of outstanding shares of all series so affected shall b e required. Any affirmative vote of the holders of the Preferred Stock, or of any one or more series thereof, which may be required in accordance with the foregoing provisions of this subdivision (g), upon a proposal to create or authorize any stock ranking prior to the Preferred Stock or to amend, alter or repeal the express terms of outstanding shares of the Preferred Stock or of any one or more series thereof in a manner substantially prejudicial to the holders thereof may be taken at a special meeting of the holders of the Preferred Stock or of the holders of one or more series thereof called for the purpose, notice of the time, place and purposes of which shall have been given to the holders of the shares of the Preferred Stock entitled to vote upon any such proposal, or at any meeting, annual or special, of the stockholders of the Corporation, notice of the time, place and purposes of which shall have been given to holders of shares of the Preferred Stock entitled to vote on such a proposal.

(h) So long as any shares of the Preferred Stock shall be outstanding, the Corporation shall not, without the written consent or affirmative vote of the holders of at least a majority of the Preferred Stock then outstanding:

(1) issue any shares of Preferred Stock, or of any other class of stock ranking prior to or on a parity with the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, unless (a) the net income of the Corporation available for the payment of dividends for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the issuance of such shares (including, in any case in which such shares are to be issued in connection with the acquisition of new property, the net income of the property so to be acquired, computed on the same basis as the net income of the Corporation) is at least equal to two times the annual dividend requirements on all shares of the Preferred Stock, and on all shares of all other classes of stock ranking prior to or on a parity with the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, which will be outstanding immediately after the issuance of such shares, including the shares proposed to be issued, and (b) the gross income (defined as the sum of net income and interest charges, to securities evidencing indebtedness deducted in arriving at such net income) of the Corporation available for the payment of interest for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the issuance of such shares (including, in any case in which such shares are to be issued in connection with the acquisition of new property, the gross income, as heretofore defined, of the property so to be acquired, computed on the same basis as the gross income, as heretofore defined, of the Corporation) is at least equal to one and one-half times the aggregate of the annual interest requirements on all securities evidencing indebtedness of the Corporation, and the annual dividend requirements on all shares of the Preferred Stock and on all shares of all other classes of stock ranking prior to or on a parity with the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, which will be outstanding immediately after the issuance of such shares, including the shares proposed to be issued; or

(2) issue any shares of the Preferred Stock, or of any other class of stock ranking prior to or on a parity with the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, unless the aggregate of the capital of the Corporation applicable to the Common Stock and the surplus of the Corporation (paid-in, earned or other, if any) shall be not less than the aggregate amount payable on the involuntary dissolution, liquidation, or winding up of the Corporation on all shares of the Preferred Stock, and on all shares of all other classes of stock ranking prior to or on a parity with the Preferred Stock as to dividends or upon dissolution, liquidation or winding up, which will be outstanding immediately after the issuance of such shares, including the shares proposed to be issued; provided, however, that if, for the purposes of meeting the requirements of this subparagraph (2), it shall become necessary to take into consideration any surplus of the Corporation, the Corpo ration shall not thereafter pay any dividends on shares of the Common Stock which would result in reducing the aggregate of the capital of the Corporation applicable to the Common Stock and the surplus of the Corporation to an amount less than the aggregate amount payable, on involuntary dissolution, liquidation or winding up of the Corporation, on all shares of the Preferred Stock and of any stock ranking prior to or on a parity with the Preferred Stock, as to dividends or upon dissolution, liquidation or winding up, at the time outstanding.

In any case where it would be appropriate, under generally accepted accounting principles, to combine or consolidate the financial statements of any predecessor or subsidiary of the Corporation with those of the Corporation, the foregoing computations may be made on the basis of such combined or consolidated financial statements. Any affirmative vote of the holders of the Preferred Stock which may be required in accordance with the foregoing provisions of this subdivision (h) may be taken at a special meeting of the holders of the Preferred Stock called for the purpose, notice of the time, place and purposes of which shall have been given to the holders of the outstanding shares of the Preferred Stock, or at any meeting, regular or special, of the stockholders of the Corporation, notice of the time, place and purposes of which shall have been given to the holders of the outstanding shares of the Preferred Stock.

LIMITED VOTING JUNIOR PREFERRED STOCK

(i) The Limited Voting Junior Preferred Stock shall not be entitled to receipt of any dividends, and no dividends shall be paid thereon. .

(j) Subject to the limitations set forth in subdivision (c) of this Article VI (and subject to the rights of any other class of stock hereafter authorized), in the event of any dissolution, liquidation or winding up of the Corporation, whether voluntary or involuntary, before any distribution or payment shall be made to the holders of the Common Stock, the holder of the Limited Voting Junior Preferred Stock shall be entitled to be paid out of the net assets of the Corporation available for distribution to its shareholders the par value of the Limited Voting Junior Preferred Stock and no more. For the purposes of this subdivision, a consolidation, merger or amalgamation of the Corporation with or into any other corporation or corporations shall not be deemed to be a dissolution, liquidation or winding up of the Corporation, whether voluntary or involuntary.

(k) Subject to the final sentence of this subdivision (k) of this Article VI, so long as the share of Limited Voting Junior Preferred Stock shall be outstanding, the Corporation shall not, without the written consent or affirmative vote of the holder of the Limited Voting Junior Preferred Stock: (i) make an assignment for the benefit of creditors; (ii) file a petition for relief under the United States Bankruptcy Code; (iii) petition or apply to any tribunal for the appointment of a custodian, receiver or any trustee for a substantial part of its property; (iv) commence any proceeding under any bankruptcy, reorganization, arrangement, readjustment of debt, dissolution or liquidation law or statute of any jurisdiction, whether now or hereafter in effect; (v) accept or acquiesce in the filing of any such petition, application, proceeding or appointment of or taking possession by the custodian, receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Co rporation or any substantial part of its property; or (vi) admit the Corporation's inability to pay its debts generally as they become due, on behalf of the Corporation; provided, however, that notwithstanding the foregoing, the affirmative vote of the holder of the Limited Voting Junior Preferred Stock shall not be required to file a petition for relief under the United States Bankruptcy Code if (a) the Corporation or any person or entity in Control (as defined in subdivision l of this Article IV) of the Corporation hasentered into a contract to sell (whether by direct sale, merger or otherwise) the Corporation or its assets and the buyer conditions its obligations to consummate such transaction on obtaining the entry of an order pursuant to section 363 or section 1129 of the United States Bankruptcy Code approving such transaction and (b) if, but only if, such transaction involves the sale of assets by the Corporation in a case where ownership of the Corporation is not being transferred, following consummation of such sale, all of the indebtedness for borrowed money of the Corporation shall have been paid in full (or adequate provision for the payment thereof shall have been made) or assumed by the buyer. In exercising discretion under this subdivision (k) of this Article VI, the holder of Limited Voting Junior Preferred Stock shall be entitled to, and shall, consider and have due regard for, the interests of the shareholders of the Corporation and its creditors in addition to such other considerations as such holder shall consider relevant and in the best interests of the Corporation; provided that nothing in this sentence is intended to create any contractual rights in any person other than the Corporation and such holder. Except as provided by applicable law, the holder of the Limited Voting Junior Preferred Stock shall be entitled to notice of each meeting of stockholders at which such holder shall have any right to vote, but shall not be entitled to notice of any other meeting of stockholders. No twithstanding the foregoing provisions, the holder of the Limited Voting Junior Preferred Stock shall not have any voting rights under this subdivision (k) of this Article VI at any time when the Corporation has the right to redeem the Limited Voting Junior Preferred Stock pursuant to subdivision (l) of this Article VI (and regardless of whether there may then exist any restriction not set forth in such subdivision (l) on the Corporation's ability to redeem the Limited Voting Junior Preferred Stock). Except as provide in this subdivision (k) of this Article VI or as otherwise provided by law, the holder of the Limited Voting Junior Preferred Stock shall have no right to vote in the election of directors or for any other purpose.

(l) The Limited Voting Junior Preferred Stock may be redeemed by the Corporation, at its election expressed by resolution of the Board of Directors, at any time by payment of an amount equal to the par value of such share;provided,thatthe Corporation shall not be empowered to call the Limited Voting Junior Preferred Stock for redemption at any time in which Control of the Corporation shall be held or exercised by any person or entity, or by any Affiliate of such person or entity, which person or entity shall be subject to an order for relief under the United States Bankruptcy Code or any successor statute. For purposes of this subdivision (l), "Control" shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a person or entity, whether through the ownership of voting securities or general partnership or managing member interests, by contract or otherwise, and "Affiliate" shall mean wit h respect to any person or entity, any other person or entity directly or indirectly Controlling or Controlled by, or under direct or indirect common Control with such person or entity.

(m) The Limited Voting Junior Preferred Stock shall be issued and held, and may be transferred on the shareholder records of the Corporation, only upon approval of the Oregon Public Utility Commission, and only to persons or entities which are during the period of such ownership, and shall have been for the five-year period prior to such ownership, Independent. For purposes of this subdivision (m), "Independent" shall mean a person or entity which is not (i) an Affiliate (as defined in subdivision (l) above), employee, director, equity security holder, partner, member or officer of the Corporation or any of its Affiliates; (ii) employed by, or an Affiliate of, a supplier of goods or services to the Corporation or any of its Affiliates that derives more than ten percent of its revenues from the Corporation or any of its Affiliates; or (iii) a member of the immediate family of a person or entity that is an Affiliate of or that Controls (as defined in subdivision (l) above) the Corpor ation. Certificates or other evidence of ownership of the Limited Voting Junior Preferred Stock shall bear a legend or other prominent notice of the restriction contained in this subdivision (m).

(n) The Limited Voting Junior Preferred Stock shall not be convertible into Common Stock, Preferred Stock or any other class or series of securities issued by the Corporation.

(o) If the share of the Limited Voting Junior Preferred Stock is redeemed, purchased or otherwise acquired by the Corporation, it shall be cancelled and shall not be reissued.

COMMON STOCK

(p) Subject to the limitations set forth in subdivision (b) of this Article VI (and subject to the rights of any class of stock hereafter authorized) dividends may be paid upon the Common Stock when and as declared by the Board of Directors of the Corporation out of any funds legally available for the payment of dividends.

(q) Subject to the limitations set forth in subdivision (c) and (j) of this Article VI (and subject to the rights of any other class of stock hereafter authorized), upon any dissolution, liquidation or winding up of the Corporation, whether voluntary or involuntary, the net assets of the Corporation shall be distributed ratably to the holders of the Common Stock.

(r) Subject to the limitations set forth in subdivisions (f), (g), (h) and (k) of this Article VI (and subject to the rights of any class of stock hereafter created), and except as may be otherwise provided by law, the holders of the Common Stock shall have the exclusive right to vote for the election of directors and for all other purposes.

(s) Upon the issuance for money or other consideration of any shares of capital stock of the Corporation, or of any security convertible into capital stock of the Corporation, no holder of shares of the capital stock, irrespective of the class or kind thereof, shall have any preemptive or other right to subscribe for, purchase, or receive any proportionate or other amount of such shares of capital stock, or such security convertible into capital stock, proposed to be issued; and the Board of Directors may cause the Corporation to dispose of all or any of such shares of capital stock, or of any such security convertible into capital stock, as and" when said Board may determine, free of any such right, either by offering the same to the Corporation's then stockholders or by otherwise selling or disposing of such shares or other securities, as the Board of Directors may deem advisable.

(t) The Corporation from time to time, with the approving vote of the holders of at least a majority of its then outstanding shares of Common Stock, may authorize additional shares of its capital stock, with or without nominal or par value, including shares of such other class or classes, and having such designations, preferences, rights, and voting powers, or restrictions or qualifications thereof, as may be approved by such vote and be stated in supplementary or amended Articles of Incorporation executed and filed in the manner provided by law.

(u) The provisions of subdivision (o) and of this subdivision (q) of this Article VI shall not be changed unless the holders of at least a majority of the outstanding shares of Common Stock shall consent thereto in writing, or by vote at a meeting in the notice of which action on the proposed change shall have been set forth.

Stockholders shall have no preemptive rights for the purchase of any stock, either Common, Limited Voting Junior Preferred Stock or Preferred, except as may be authorized by the Board of Directors of this Corporation.

EXHIBIT 99.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

I, Peggy Y. Fowler, Chief Executive Officer and President of Portland General Electric Company (the "Company"), hereby certify ~~to the best of my knowledge and belief,~~ that the accompanying report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2002, and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.

I further certify ~~to the best of my knowledge and belief,~~ that the information contained in such report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2002, fairly presents, in all material aspects, the financial condition and results of operations of the Company.

/s/ Peggy Y. Fowler
Peggy Y. Fowler

Date:	~~August 13,~~November 8, 2002

EXHIBIT 99.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

I, James J. Piro, Chief Financial Officer of Portland General Electric Company (the "Company"), hereby certify ~~to the best of my knowledge and belief,~~ that the accompanying report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2002, and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.

/s/ James J. Piro
James J. Piro

Date:	~~August 13,~~November 8, 2002

				June 30, 2002		December 31, 2001

Receivables from affiliated companies
	Enron Corp and other Enron Subsidiaries:
		Merger Receivable	$	77	$	74
		Allowance for Uncollectible - Merger Receivable		(77)		(74)
		Income Taxes Receivable^(a)		4		4
		Accounts Receivable^(b)		1		2
		Other Allowance for Uncollectible Accounts^(b)		(5)		(5)
	Portland General Holdings and its subsidiaries:
		Accounts Receivable^(b)		35		33

Payables to affiliated companies
	Enron Corp:
		Accounts Payable^(a)		11		11

(a)Included in Accounts payable and other accruals on the Consolidated Balance Sheets
(b)Included in Accounts and notes receivable on the Consolidated Balance Sheets

For the Six Months Ended June 30				2002		2001

Revenues from affiliated companies
	Other Enron subsidiaries:
		Sales of electricity and transmission^(a)	$	1	$	125

Expenses billed to affiliated companies
	Enron Corp:
		Intercompany services^(b)		-		3
	Portland General Holdings and its subsidiaries:
		Intercompany services^(b)		1		1

Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services^(b)		11		14
	Other Enron subsidiaries:
		Purchases of electricity^(c)		-		124

Interest (net) from affiliated companies
	Enron Corp:
		Interest income^(d)		3		4
	Portland General Holdings and its subsidiaries:
		Interest income^(d)		2		2

(a)Included in Operating Revenues on the Consolidated Statements of Income
(b)Included in Administrative and other on the Consolidated Statements of Income
(c) Included in Purchased power and fuel on the Consolidated Statements of Income
(d)Included in Other Income (Deductions) on the Consolidated Statements of Income

/s/ Peggy Y. Fowler
Peggy Y. Fowler
Chief Executive Officer and President