SEC Filing | Portland General Electric Company

View:

Download DOC

Download PDF

Download XLS

Portland General Electric Company Form 10-Q for quarter ended September 30, 2004

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2004
	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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes No X

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of October 31, 2004: 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	30

	Item 3. Quantitative and Qualitative Disclosures
	About Market Risk	64

	Item 4. Controls and Procedures	68

PART II. Other Information

	Item 1. Legal Proceedings	69
	Item 5. Other Information	70
	Item 6. Exhibits	71
	Signatures	73

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

ESS

Energy Service Supplier

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

Public Utility Commission of Oregon

Oregon Electric

Oregon Electric Utility Company, LLC

PBGC

Pension Benefit Guaranty Corporation

PGC

Portland General Corporation

PGE or the Company

Portland General Electric Company

Port Westward

Port Westward Power Plant

PUHCA

Public Utility Holding Company Act of 1935

SEC

Securities and Exchange Commission

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

WECC

Western Electricity Coordinating Council

PART I

Financial Information

Item 1. Financial Statements

Portland General Electric Company and Subsidiaries Consolidated Statements of Income (Unaudited)
			Three Months Ended September 30,						Nine Months Ended September 30,
			2004			2003			2004				2003
			(In Millions)

Operating Revenues			$	348		$	494		$		1,075		$			1,375

Operating Expenses
	Purchased power and fuel			180			337			491					856
	Production and distribution			31			28			96					86
	Administrative and other			35			37			105					109
	Depreciation and amortization			58			52			174					160
	Taxes other than income taxes			18			18			55					54
	Income taxes			6			3			48					29
				328			475			969					1,294

Net Operating Income				20			19			106					81

Other Income (Deductions)
	Miscellaneous			2			(7)			5					-
	Income taxes			5			4			6					6
				7			(3)			11					6

Interest Charges
	Interest on long-term debt and other			17			20			53					59

Net income (loss) before cumulative effect of a
		change in accounting principle		10			(4)			64					28
Cumulative effect of a change in accounting
	principle, net of related taxes of $(1)			-			-			-					2

Net Income (Loss)				10			(4)			64					30

Preferred Dividend Requirement				-			-			-					1

Income (Loss) Available for Common Stock			$	10		$	(4)	$		64		$			29

The accompanying notes are an integral part of these consolidated financial statements.
Portland General Electric Company and Subsidiaries Consolidated Statements of Retained Earnings (Unaudited)

			Three Months Ended September 30,					Nine Months Ended September 30,
			2004		2003			2004						2003
			(In Millions)

Balance at Beginning of Period			$	599		$	521	$		545		$			488
Net Income (Loss)				10			(4)			64					30
				609			517			609					518

Dividends Declared
	Preferred stock			-			-			-					1
Balance at End of Period			$	609		$	517	$		609		$			517

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 Ended									Nine Months Ended
			September 30,									September 30,
				2004			2003				2004					2003
				(In Millions)
Accumulated other comprehensive income (loss) - Beginning of Period
	Unrealized gain on derivatives classified as cash flow hedges			$	6		$		-		$			2			$		3
	Minimum pension liability adjustment				(4)			(3)					(4)						(3)
	Total			$	2		$	(3)			$		(2)		$				-

Net Income (Loss)				$	10		$	(4)			$			64	$				30

Other comprehensive income, net of tax:
	Unrealized gains (losses) on derivatives classified as cash flow hedges:
		Other unrealized holding net gains (losses) arising during the
		period, net of related taxes of $(3) and $2 for the three
		months ended September 30, 2004 and 2003 and $(10) and $(2)
		for the nine months ended September 30, 2004 and 2003		3			(2)				15				4
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $2 for the three months
		ended September 30, 2004 and $4 and $1 for the nine months ended September 30, 2004 and 2003		(2)			(1)				(6)				(3)
		Reclassification adjustment in net income due to discontinuance
		of cash flow hedges, net of related taxes of $2 for the nine months ended September 30, 2003		-			-				-				(4)
		Reclassification of unrealized gains (losses) to SFAS No. 71
		regulatory (liability) asset, net of related taxes of $3 and $(2)
		for the three months ended September 30, 2004 and 2003 and
		$6 for the nine months ended September 30, 2004		(5)			3				(9)				-
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		(4)			-				-				(3)

	Minimum pension liability adjustment			-			-				-				-
		Total Other comprehensive income (loss)		(4)			-				-				(3)

Comprehensive income (loss)				$	6		$			(4)	$			64	$			27

Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain on derivatives classified as cash flow hedges			$	2		$			-	$			2		$			-
	Minimum pension liability adjustment			(4)			(3)				(4)				(3)
Total				$		(2)	$			(3)	$			(2)	$			(3)

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

Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)
			September 30,		December 31,
			2004		2003
			(In Millions)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $108 and $89)		$	3,960		$		3,834
	Accumulated depreciation		(1,703)			(1,633)
			2,257			2,201
Other Property and Investments
	Receivable from parent (less allowance for uncollectible accounts of $73 and $73)		-			-
	Nuclear decommissioning trust, at market value		23				35
	Non-qualified benefit plan trust		63				67
	Miscellaneous		31				38
			117				140
Current Assets
	Cash and cash equivalents		199				109
	Accounts and notes receivable (less allowance for uncollectible accounts of $54 and $51)		211				223
	Unbilled revenues		46				72
	Assets from price risk management activities		123				66
	Inventories, at average cost		49				45
	Margin deposits		1				-
	Prepayments and other		112				97
			741				612
Deferred Charges
	Regulatory assets		321				387
	Miscellaneous		26				32
			347				419
			$	3,462			$		3,372
Capitalization and Liabilities
Capitalization
	Common stock equity:
		Common stock, $3.75 par value per share, 100,000,000
		shares authorized; 42,758,877 shares outstanding	$	160			$		160
		Other paid-in capital - net	481				481
	Retained earnings		609				545
	Accumulated other comprehensive income (loss):
		Unrealized gain on derivatives classified as cash flow hedges	2				2
		Minimum pension liability adjustment	(4)				(4)
	Limited voting junior preferred stock		-				-
	Long-term obligations		894				927
			2,142				2,111

Commitments and Contingencies (see Notes)

Current Liabilities
	Long-term debt due within one year		29				56
	Accounts payable and other accruals		195				230
	Liabilities from price risk management activities		62				44
	Customer deposits		21				5
	Accrued interest		15				20
	Accrued taxes		64				51
	Deferred income taxes		18				8
			404				414
Other
	Deferred income taxes		329				349
	Deferred investment tax credits		14				16
	Trojan asset retirement obligation		98				104
	Accumulated asset retirement obligation		17				17
	Regulatory liabilities:
		Accumulated asset retirement removal costs	278			230
		Other	73				27
	Non-qualified benefit plan liabilities		69				66
	Miscellaneous		38				38
			916				847
			$	3,462			$		3,372

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

Portland General Electric Company and Subsidiaries Consolidated Statements of Cash Flows (Unaudited)
			Nine Months Ended
			September 30,
			2004		2003
			(In Millions)

Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
	Net income		$	64	$	30
	Non-cash items included in net income:
		Cumulative effect of a change in accounting principle, net of tax	-		(2)
		Depreciation and amortization	174		160
		Deferred income taxes	(6)		(23)
		Net assets from price risk management activities	(24)		(16)
		Power cost adjustment	30		37
		Other non-cash income and expenses (net)	22		26
	Changes in working capital:
		Net margin deposit activity	15		(1)
		(Increase) Decrease in receivables	38		16
		Increase (Decrease) in payables	(24)		27
		Other working capital items - net	(22)		(18)
	Other - net		10		1
Net Cash Provided by Operating Activities			277		237

Cash Flows From Investing Activities:
	Capital expenditures		(131)		(99)
	Other - net		4		(33)
Net Cash Used in Investing Activities			(127)		(132)

Cash Flows From Financing Activities:
	Repayment of long-term debt		(60)		(339)
	Issuance of long-term debt		-		342
	Debt issue costs		-		(7)
	Preferred stock retired		-		(3)
	Dividends paid		-		(1)
Net Cash Used in Financing Activities			(60)		(8)

Increase in Cash and Cash Equivalents			90		97
Cash and Cash Equivalents, Beginning of Period			109		51
Cash and Cash Equivalents, End of Period			$	199	$	148

Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	50	$	53
		Income taxes	66		39

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 management's opinion that, when the interim statements are read in conjunction with the 2003 Annual Re port on Form 10-K and the other reports filed with the SEC since its 2003 Form 10-K was filed, the disclosures are adequate to make the information presented not misleading.

Note 2 - Employee Benefits

Pension and Other Post-Retirement Plans

PGE sponsors a non-contributory defined benefit pension plan in which Portland General Holdings, Inc. (PGH) and its subsidiaries have participated. Substantially all pension plan members are current or former PGE employees. The pension plan assets are held in a trust.

The Non-Qualified Benefit Plans in the accompanying table primarily represent obligations for a Supplemental Executive Retirement Plan. Investments in a non-qualified benefit plan trust (i.e. rabbi trust), consisting of trust owned life insurance policies and, beginning in 2003, marketable securities, are intended to be the primary source for financing these plans.

PGE further participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" in the table). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions made to a voluntary employees' beneficiary association trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers.

The measurement date for these plans is December 31. PGE has not made contributions to the plans during 2004.

The following tables indicate components of net periodic benefit cost for the periods indicated (in millions):

Three Months Ended September 30:	Defined Benefit				Non-Qualified
	Pension Plan				Benefit Plans				Other Benefits
	2004		2003		2004		2003		2004		2003
Components of net periodic benefit cost:
Service cost	$	3	$	3	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	6		6		-		-		-		-
Expected return on plan assets	(10)		(10)		(1)		(2)		(1)		-
Amortization of transition asset	-		(1)		-		-		-		-
Amortization of prior service cost	-		-		1		-		1		-
Recognized (gain) loss		-		-		-		-		-		-
Net periodic benefit cost (income)	$	(1)	$	(2)	$	-	$	(2)	$	-	$	-

Nine Months Ended September 30:	Defined Benefit				Non-Qualified
	Pension Plan				Benefit Plans				Other Benefits
	2004		2003		2004		2003		2004		2003
Components of net periodic benefit cost:
Service cost	$	9	$	8	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	18		17		1		1		2		1
Expected return on plan assets	(30)		(29)		(1)		(1)		(1)		-
Amortization of transition asset	(1)		(2)		-		-		-		-
Amortization of prior service cost	1		1		1		-		1		-
Recognized (gain) loss		-		-		-		-		-		-
Net periodic benefit cost (income)	$	(3)	$	(5)	$	1	$	-	$	2	$	1

Note 3 - Price Risk Management

PGE utilizes derivative instruments, including electricity forward, swap, and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and endeavor to minimize net power costs for its retail customers, and in its trading activities to participate in electricity, natural gas, and crude oil markets. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), 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, unless specific hedge accounting criteria are met.

For retail (non-trading) activities, changes in fair value of derivative instruments prior to settlement are recorded on a net basis in Purchased Power and Fuel expense. As these derivative instruments are settled, physical electricity activities are recorded on a gross basis, with sales recorded in Operating Revenues and purchases, natural gas swaps and futures recorded in Purchased Power and Fuel expense. In accordance with Emerging Issues Task Force Issue No. 03-11 (EITF 03-11), Reporting Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, on October 1, 2003, PGE began recording, on a prospective basis, the non-physical settlements (i.e. book outs) of non-trading electricity derivative activities on a net basis in Purchased Power and Fuel expense. Prior period amounts for non-physical settlements that were recorded on a gross basis in both Operating Re venues and Purchased Power and Fuel expense have not been reclassified.

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

For energy trading activities, PGE reports all unrealized and realized gains and losses on a net basis, in accordance with EITF 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, with such activities recorded as a component of Operating Revenues.

Non-Trading Activities

As PGE's primary business is to serve its retail customers, it uses derivative instruments, including electricity forward and option, and natural gas forward, swap, option and futures contracts to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers. Most of the Company's non-trading wholesale sales have been to utilities and power marketers and have been predominantly short-term. PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such participation includes power purchases and sales resulting from daily economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions ar e also referred to as "book outs." Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations are physically settled.

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. Rates approved by the OPUC for 2004 were based on a valuation of all the Company's energy resources, including derivative instruments existing on October 30, 2003 that would settle during the 12-month period from January 1, 2004 to December 31, 2004. Such valuation was based on forward price curves in effect on November 11, 2003 for electricity and natural gas. The timing difference between the recognition of gains and losses on certain 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 these contracts are settled, the regulatory asset or regulatory liability is reversed. However, as there is currently no power cost adjustment mechanism in effect for 2004, unrealized gains and losses on new derivatives that will settle in 2004 are not included in rates, and changes in fair value of derivatives used to set rates, are not deferred as regulatory assets or regulatory liabilities.

In the first nine months of 2004, PGE recorded $23 million in net unrealized gains in earnings in its retail portfolio, including $3 million in net unrealized gains in the third quarter. The net unrealized gain in the first nine months of 2004 was more than offset by recording a $27 million SFAS No. 71 regulatory liability, calculated on the basis indicated above. In the first nine months of 2003, PGE recorded $14 million in net unrealized gains in earnings in its retail portfolio, including $9 million in net unrealized losses in the third quarter. The net unrealized gain in the first nine months of 2003 was partially offset by recording a $9 million SFAS No. 71 regulatory liability.

Derivative activities recorded in OCI for the three- and nine-month periods ended September 30, 2004 from cash flow hedges consist of unrealized gains of $6 million and $25 million, respectively, from new contracts and changes in fair value, partially offset by $4 million and $10 million, respectively, in net gains reclassified in earnings for contracts that settled during the three- and nine-month periods. SFAS No. 71 regulatory liabilities of $8 million and $15 million, respectively, were recorded during the three- and nine-month periods ended September 30, 2004.

Derivative activities recorded in OCI for the three- and nine-month periods ended September 30, 2003 from cash flow hedges consisted of unrealized losses of $4 million and unrealized gains of $6 million, respectively, from new contracts and changes in fair value. Also recorded in OCI for the three- and nine-month periods ended September 30, 2003 were $1 million and $4 million, respectively, in net gains reclassified in earnings for contracts that settled during the period. For the nine-month period of 2003, $6 million in net gains were reclassified for the discontinuance of cash flow hedges due to the probability that the original forecasted transaction will not occur. A $5 million SFAS No. 71 regulatory asset was recorded for the three-month period ended September 30, 2003.

Hedge ineffectiveness from cash flow hedges was not material in the first nine months of 2004 and 2003. As of September 30, 2004, the maximum length of time over which PGE is hedging its exposure is approximately 27 months. The Company estimates that of the $19 million of net unrealized gains included in accumulated OCI at September 30, 2004, $13 million will be reclassified into earnings within the next twelve months.

Trading Activities

PGE utilizes electricity forward, swap, and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts to participate in electricity, natural gas, and crude oil markets. Such activities are not reflected in PGE's retail prices. As indicated above, all unrealized and realized gains and losses associated with "energy trading activities" are reported on a net basis for all periods presented.

The following tables indicate unrealized and realized gains and losses on electricity and fuel trading activities and transaction volumes for electricity trading contracts that settled in the three- and nine-month periods ended September 30, 2004 and 2003:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
Trading Activities (in millions)

Unrealized Gain (Loss)	$	2	$	-	$	1	$	2
Realized Gain (Loss)		(2)		-		-		-
Net Gain (Loss) in Operating Revenues	$	-	$	-	$	1	$	2

Electricity Trading - MWhs (thousands)

Sales	3,098		4,140		8,660		10,370
Purchases	3,098		4,140		8,660		10,370

Note 4 - Legal and Environmental Matters

Legal Matters

Trojan Investment Recovery - In 1993, following the closure of Trojan, 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 (1995 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 were subsequently filed in the Marion County, Oregon Circuit Court, the Oregon Court of Appeals, and 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 were the CUB and the URP. The Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. 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 investment issue. PGE requested the Oregon Supreme Court to suspend its review of the 1998 Court of Appeals opini on pending resolution of URP's complaint with the OPUC challenging the accounting and ratemaking elements of the settlement agreements approved by the OPUC in September 2000 (discussed below). On November 19, 2002, the Oregon Supreme Court dismissed PGE's and URP's petitions for review of the 1998 Oregon Court of Appeals decision. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

While the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, in 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of, and return on, its investment in the Trojan plant. URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, 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 the approximately $80 million remaining credit due customers under terms of PGC's 1997 merger with Enron. The settlement also allows PGE recovery of 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 being recovered from PGE customers, with no return on the unamortized balance, over an approximate five-year period, beginning in October 2000. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. 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. Authorized collection of decommissioning costs of Trojan is unaffected by the settlement agreements or the OPUC orders.

The URP filed a complaint challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, after a full contested case hearing, the OPUC issued an order (2002 Order) denying all of URP's challenges, and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 Order to the Marion County, Oregon Circuit Court. On November 7, 2003, the Marion County Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have filed appeals to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Plaintiff's claims. Hearings on both the motion for Summary Judgment and class certification are pending.

On March 3, 2004, the OPUC re-opened three dockets in which it had addressed the issue of a return on PGE's investment in Trojan, including the 1995 Order and 2002 Order related to the settlement of 2000, and issued a notice of a consolidated procedural conference before an administrative law judge to determine what proceedings are necessary to comply with the court orders remanding this matter to the OPUC.

On August 31, 2004, the administrative law judge issued an Order defining the scope of the proceedings necessary to comply with the Marion County Circuit Court orders remanding this matter to the OPUC. On October 18, 2004, the OPUC affirmed the August 31, 2004 Order.

Management cannot predict the ultimate outcome of the above matters. However, it believes these matters 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 - In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which do not specify an amount of claim, seek binding arbitration. PGE filed for relief in Multnomah County, Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Environmental Matters

Harborton - A 1997 investigation by the Environmental Protection Agency (EPA) of a 5.5 mile segment of the Willamette River known as the Portland Harbor 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). In December 2000, PGE received a "Notice of Potential Liability" regarding its Harborton Substation facility and was included, along with sixty-eight other companies, on a list of Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

Also in 2000, PGE agreed with the Oregon Department of Environmental Quality (DEQ) to perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In February 2002, PGE submitted its final investigative report to the DEQ, indicating that the voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. DEQ submitted the final investigative report to EPA and in a May 18, 2004 letter EPA stated "Based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river." Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

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 themselves to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on its financial statements.

Other - In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site. Management cannot predict the ultimate outcome of this matter. However, PGE believes this matter will not have a material adverse impact on its financial statements.

Note 5 - Related Party Transactions

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

			September 30, 2004	December 31, 2003

Receivables from affiliated companies
	Enron Corp and other Enron Subsidiaries in Bankruptcy:
		Merger Receivable	$ 73	$ 73
		Allowance for Uncollectible - Merger Receivable	(73)	(73)
		Accounts Receivable^(a)	3	3
		Other Allowance for Uncollectible Accounts^(a)	(3)	(3)
	Other Enron Subsidiaries:
		Portland General Holdings, Inc. - in Bankruptcy
		Accounts Receivable^(a)	5	5
		Other Allowance for Uncollectible Accounts ^(a)	(1)	(2)
		PGH II and its subsidiaries - not in Bankruptcy
		Accounts Receivable^(a)	1	2
		Other Allowance for Uncollectible Accounts ^(a)	(1)	-
		Note Receivable^(a)	-	1

Payables to affiliated companies
	Enron Corp:
		Accounts Payable^(b)	6	6
		Income Taxes Payable^(c)	18	36

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

For the Nine Months Ended September 30					2004	2003

Expenses billed to affiliated companies
	PGH II and its subsidiaries - not in Bankruptcy
			Intercompany services^(a)		$ 1	$ 1

Expenses billed from affiliated companies
		Enron Corp:
				Intercompany services^(a)	19	25

Interest, net from affiliated companies
		Enron Corp:
				Interest income^(b)	-	5

^{(a) Included in Administrative and other on the Consolidated Statements of Income}
^{(b) Included in Other Income (Deductions) on the Consolidated Statements of Income}

Merger Receivable - In 1997, Enron acquired PGE through a merger between Enron and PGC, the former parent corporation of PGE. Under terms of the 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 in May 2002. PGE accrued interest on the Merger Receivable and recorded an offsetting reserve from the December 2001 Enron bankruptcy filing until December 2003. Both the interest and the related reserve accrued in Enron's post-petition bankruptcy period were reversed in December 2003 to reflect PGE's proofs of claim filing. At September 30, 2004, Enron owed PGE approximately $73 million, including interest accrued prior to Enron's bankruptcy filing. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE established a reserve for the full amount of this receivable in December 2001. On October 15, 2002, PGE submitted proofs of claim to th e Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, 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 7, Enron Bankruptcy.

Income Taxes Receivable and Payable - As a member of Enron's consolidated income tax return, PGE made income tax payments to Enron for PGE's income tax liabilities. PGE and its subsidiaries ceased to be a member of Enron's consolidated tax group on May 7, 2001. On December 24, 2002, PGE and its subsidiaries again became a member of Enron's consolidated tax group. The $18 million income taxes payable to Enron at September 30, 2004 represents a net current income taxes payable of $11 million for the third quarter of 2004 and $7 million for income taxes owed up to May 7, 2001 (pre-petition liability included as an offset in PGE's proofs of claim filing). During the first nine months of 2004, PGE paid $66 million to Enron for income taxes payable, of which $21 million was for the period from December 24, 2002 to December 31, 2003, primarily for the third and fourth quarters of 2003. Income tax payments for those periods were withheld u ntil PGE's December 24, 2002 reconsolidation with Enron was agreed to by the IRS on February 2, 2004. The remaining $45 million tax payment to Enron was for the first half of 2004. For further information, see Note 7, Enron Bankruptcy.

Intercompany Receivables and Payable - As part of its continuing operations, PGE bills affiliates for various services provided by the Company. These include those provided by PGE employees, as well as other corporate services. In addition, Enron passes through PGE's share of costs related to employee benefits and certain insurance coverage. Transactions with affiliates are subject either to approval of, or confirmation filing requirements with, the OPUC and, as long as PGE is a subsidiary of a registered holding company under PUHCA, the SEC. Under OPUC regulations, services provided to affiliates by PGE are charged at the higher of cost or market, while affiliated services received by PGE are charged at the lower of cost or market. Under SEC regulations, both services provided to, and received from, affiliates are charged at cost. Services will be provided at cost unless there is a conflict between OPUC and SEC regulations, in which case PGE and Enron have agreed not to provide the services until the matter can be resolved.

Enron - Beginning in 2004, Enron no longer bills PGE for corporate overhead costs. In the first nine months of 2004, Enron passed through to PGE approximately $17 million for medical/dental benefits and retirement savings plan matching and $2 million for insurance coverage. For the same period in 2003, Enron passed through to PGE approximately $15 million for medical/dental benefits and retirement savings plan matching and insurance coverage and billed $10 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001, except for payments for employee benefit plans. In reaching an agreement with Enron regarding the allocation of corporate overheads in the post-bankruptcy period, PGE resumed payments for corporate overhead costs from March 2003 through December 2003. During the first nine months of 2004, PGE paid $19 million to Enron, consisting of $17 million for employee benefits and $2 million for insurance premiums. At September 30, 2004, PGE had a $6 million payable to Enron, consisting of $2 million for employee benefit costs and $4 million for pre-petition period corporate overheads and restricted stock costs (included as an offset in PGE's proofs of claim).

At September 30, 2004, Enron owed PGE $1 million related to taxes on employee benefits (pre-petition), which has been fully reserved and is included in PGE's proofs of claim filing.

Other Enron Subsidiaries in Bankruptcy - PGE purchased electricity from, and sold electricity to, Enron Power Marketing, Inc. (EPMI) during 2001. PGE also provided transmission services to EPMI under a transmission contract that was guaranteed by Enron. PGE has not purchased electricity from, or sold electricity to, EPMI since December 2001, and EPMI has not paid for transmission services since September 2002.

At December 31, 2003, PGE was owed a net $2 million by EPMI for power sales and transmission services, which remained outstanding at September 30, 2004. EPMI is part of Enron's bankruptcy proceedings. Due to uncertainties associated with the realization of this receivable from EPMI, a $2 million reserve has been established. PGE included amounts owed by EPMI for power sales and transmission services in the proofs of claim filed with the Bankruptcy Court.

In April 2003, PGE entered into a settlement agreement with EPMI and Enron to terminate the transmission contract. The settlement agreement was approved by the Bankruptcy Court and accepted by the FERC. Under the settlement, PGE retained a $200,000 deposit from EPMI related to the transmission contract and Enron's guaranty was terminated. PGE amended its proofs of claim in the Enron bankruptcy to include a pre-petition unsecured claim against EPMI and a pre-petition guaranty claim against Enron for $1 million owed PGE for transmission services. For further information, see Note 7, Enron Bankruptcy.

Portland General Holdings, Inc. - in Bankruptcy - On June 27, 2003, PGH, a wholly owned subsidiary of Enron located in Portland, filed to initiate bankruptcy proceedings under the federal Bankruptcy Code. The PGH filing has been procedurally consolidated with the Enron bankruptcy proceeding. No PGH subsidiaries are included in the bankruptcy filing. At September 30, 2004, PGE had outstanding accounts receivable from PGH of $5 million, comprised of $4 million related to employee benefit plans and $1 million for employee and other corporate governance services. During 2003, PGE submitted proofs of claim to the Bankruptcy Court for approximately $5 million for employee benefit and corporate governance services. Based on management's assessment of the realizability of the receivable from PGH, a reserve of $2 million was established in December 2002. In June 2004, PGE reduced the reserve by $1 million based on management's current assessment. PGE will continue to assess the collectibility of this receivable.

PGH II, Inc. and its Subsidiaries - not in Bankruptcy - PGH II, Inc. (PGH II), a wholly owned subsidiary of PGH, is the parent company of various subsidiaries that receive services from PGE. PGH II and its subsidiaries are not part of Enron's or PGH's bankruptcy proceedings. PGH II subsidiaries include Portland General Distribution, LLC (PGDC), a telecommunications company, Microclimates, Inc., a project management company, and Portland Energy Solutions Company, LLC (PES), which provided cooling services to buildings in downtown Portland, Oregon. In April 2004, PES sold substantially all of its assets to an unrelated third party. The proceeds from the sale were used to repay all amounts PES owed to PGE. For the first nine months of 2004, PGE billed PGH II and its subsidiaries $1 million for employee and other corporate governance services.

As of September 30, 2004, PGE had outstanding accounts receivable from PGDC of $1.2 million for employee and other corporate governance services, offset by an approximate $0.9 million uncollectible reserve. In September 2004, PGDC sold substantially all of its assets to an unrelated third party. The proceeds from the sale are expected to repay the unreserved amounts that PGDC owes to PGE.

Other Subsidiaries - PGE also provides services to its consolidated subsidiaries, including cash management and the sublease of office space in the Company's headquarter complex. 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 on the Enron Merger Receivable balance and the related reserve accrued in Enron's post-petition bankruptcy period were reversed in December 2003, as previously discussed. Accounts receivable balances from PGH II and its subsidiaries accrue interest at 9.5%. Receivable balances from PGH also accrued interest at 9.5% until PGH filed bankruptcy and the interest accrual on pre-bankruptcy receivables was discontinued. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its other subsidiaries.

Note 6 - Receivables and Refunds on Wholesale Transactions

Receivables - California Wholesale Market

As of September 30, 2004, PGE has net accounts receivable balances totaling approximately $63 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. (As the result of a reconciliation process, completed in the third quarter of 2004, the balance was increased by $3 million). The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

Management continues to assess PGE's exposure relative to these receivables. Based upon FERC orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

Refunds on Wholesale Transactions

California

In a June 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 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 evidentiary hearings 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. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

Also in August 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 PGE's potential refund obligation.

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds, based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates its potential liability under the modified methodology at between $40 million and $50 million, of which $40 million has been established as a reserve, as discussed above.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order that denied further requests for rehearing of the October 16, 2003 order. On the same day, the FERC issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liabi lity. On September 24, 2004, the FERC issued an order that denied requests for rehearing of its May 12, 2004 fuel cost order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Under the new allocation methodology, PGE could be required to pay additional amounts in those hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect that this order will materially increase the Company's potential refund exposure.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). 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 may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates during the period October 2, 2000 - June 4, 2002 should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals. On September 8, 2004, the Court issued an opinion upholding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. PGE cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

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. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. 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 7 - Enron Bankruptcy

Commencing 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 bankruptcy, but the common stock of PGE held by Enron is part of the bankruptcy estate.

Enron and its debtor-in-possession subsidiaries (collectively the Debtors) filed their proposed joint Chapter 11 plan (the Chapter 11 Plan) and related disclosure statement (the Disclosure Statement) with the Bankruptcy Court. The Chapter 11 Plan and Disclosure Statement, as amended, provide information about the assets that are in the bankruptcy estate, including the common stock of PGE, and how those assets will be distributed to the creditors. The Chapter 11 Plan was confirmed by the Bankruptcy Court on July 15, 2004.

Although Enron is continuing the sale process for PGE, under the Chapter 11 Plan, if PGE is not sold, the shares of PGE's common stock will be distributed over time to the Debtors' creditors. It is anticipated that once a sufficient amount of the common stock is distributed to creditors, the shares would be publicly traded.

Management cannot predict with certainty what impact Enron's bankruptcy, including the Chapter 11 Plan, 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 PGC in 1997 (Merger Conditions), Enron's access to PGE cash or assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's common equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OP UC approval. The 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 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.

Notwithstanding the 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 in Bankruptcy - As described in Note 5, Related Party Transactions, PGE is owed approximately $73 million by Enron at September 30, 2004 (Merger Receivable). Such amount was to have been paid to the Company for customer price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the full amount of this receivable, which was recorded in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, 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, at September 30, 2004, PGE has outstanding accounts receivable of $8 million from Enron and its subsidiary com panies which are part of the bankruptcy proceedings, consisting of $5 million due from PGH, $2 million from EPMI, and $1 million from Enron. Based on management's assessment of the realizability of these balances, a reserve of $4 million has been established.

2. Controlled 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 (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2003, the total fair value of PGE Plan assets was $15 million higher than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, the PGE Plan was over-funded on an accumulated benefit obligation basis by about $68 million as of December 31, 2003. Enron's management has informed PGE that, as of December 31, 2003, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $60 million on a SFAS No. 87 basis and approximately $162 million on a plan termination basis. The PBGC insures pension plans, including the PGE Plan and the Enron Plan and the pension plans of other Debtors. Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases with respect to the Enron Plan and the plans of the other De btors (Pension Plans). The claims are duplicative in nature because certain liability under ERISA is joint and several. Five of the PBGC's claims represent unliquidated claims for PBGC insurance premiums (the Premium Claims), five are unliquidated claims for due but unpaid minimum funding contributions (the Contribution Claims) under the Internal Revenue Code of 1986, as amended, and ERISA, 26 U.S.C. Section 412, and 29 U.S.C. Section 1082, and the remaining five claims are for unfunded benefit liabilities (the UBL Claims). PBGC has amended the UBL Claims several times, up to an aggregate high of $424.1 million. PBGC has informed the Debtors that it has reduced its aggregate estimate of the UBL Claims for the Pension Plans to an aggregate of $321.8 million, including $240.2 million for the Enron Plan and $64.6 million related to the PGE Plan, although it has not amended the UBL Claims to reflect those amounts. The Debtors are current on their PBGC premiums and their minimum funding contributions to the Pensi on Plans. Therefore, the Debtors' value the Premium Claims and the Contribution Claims at $0. Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has not provided support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

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, any 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 assets would be undiminished.

Because 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. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with the Employee Retirement Income Security Act of 1974, as amended (ERISA).

Upon termination of an underfunded pension plan, all of the members of the ERISA 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 arises against the members 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 arises against the assets of every member of the controlled group. In either case, the PBGC may file to perfect the lien and attempt to enforce it against the assets of plan sponsor and the members of its controlled group. PG E management believes that such a lien would be subordinate to prior perfected liens on the assets of the members 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. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien. In addition, the PBGC retains an interest in any sales proceeds generated by the Enron auction process for PGE. Based on discussions with Enron's management, PGE's management understands that Enron has made all required contributions to date.

On January 30, 2004, the Bankruptcy Court entered the order authorizing Enron and certain of its affiliated Debtors to contribute $200 million to the Pension Plans and terminate them in a manner that should eliminate the PBGC's claims. However, there can be no assurance that Enron will have the ability to obtain funding for accrued benefits on acceptable terms, that certain funding contingencies will be met, or that the required government agencies that review pension plan terminations will approve the termination of the Pension Plans. If the proposal to fund and terminate the Enron Plan, as stated in the Disclosure Statement and as set forth in Enron's motion, is approved and consummated, it should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the Enron Plan.

On June 2, 2004, the PBGC issued notices to Enron and Enron Facility Services, Inc. (EFS), an Enron affiliate, stating that the PBGC had determined that the Pension Plans should be terminated. On June 3, 2004, the PBGC filed a complaint (PBGC Complaint) in the District Court for the Southern District of Texas against Enron seeking an order (i) terminating the Pension Plans; (ii) appointing the PBGC the statutory trustee of the Pension Plans; (iii) requiring transfer to the PBGC of all records, assets or other property of the Pension Plans required to determine the benefits payable to the Pension Plans' participants; and (iv) establishing June 3, 2004 as the termination date of the Pension Plans.

The PGE Plan was not included in the above Complaint, nor was PGE issued a similar notice of determination regarding the PGE Plan. The PBGC has taken no action to terminate the PGE Plan.

On August 4, 2004, Enron, EFS and certain Debtors filed a complaint with the Bankruptcy Court (Enron Complaint) seeking (i) a declaration that the PBGC Complaint is void; and (ii) orders staying, restraining and enjoining the PBGC from continuing the prosecution of the PBGC Complaint and preliminarily and permanently enjoining the PBGC to cease prosecution of, and to dismiss with prejudice, the PBGC Complaint. On September 8, 2004, the Bankruptcy Court denied the Enron Complaint.

Enron management has informed PGE management that Enron will continue to work with the PBGC and other affected parties to resolve all disagreements and allow Enron to continue the process of seeking standard termination of the Pension Plans as previously authorized by the Bankruptcy Court on January 30, 2004. If the parties cannot reach agreement, and if the relief sought in the Enron Complaint is not obtained, Enron may be precluded from funding and terminating the Pension Plans as previously authorized by the Bankruptcy Court until, if at all, after resolution of the PBGC Complaint.

Until the District Court authorizes the PBGC to terminate the Pension Plans and the PBGC makes a demand on PGE to pay some or all of any unfunded benefit liabilities under the Pension Plans, PGE has no liability for the unfunded benefit liabilities and no termination liens arise against any PGE property.

PGE 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

PGE management understands, based on discussions with Enron management, that Enron maintains a group health plan for certain of its retirees. If retirees of Enron lose coverage under Enron's group health plan for retirees due to Enron's bankruptcy proceedings, the retirees must be provided the opportunity to purchase continuing coverage (known as COBRA Coverage) from an Enron group health plan, if any, or the appropriate group health plan of another member of Enron's controlled group. The liability for benefits under the Enron group health plan for retirees (other than potential liability to provide COBRA Coverage) is not a joint and several obligation of other members of the Enron controlled group, including PGE, so PGE would not be required to assume from Enron, or otherwise pay, any liabilities from the Enron group health plan. Neither PGE nor any other member of Enron's controlled group would be required to create new plans to provide COBRA Coverage for Enron's retirees, and the re tirees would not be entitled to choose the plan from which 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 purchase COBRA Coverage would be required to pay for the COBRA Coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire COBRA Coverage. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

PGE 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 discussions 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. PGE 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, PGE 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. PGE management believes that the additional cost to PGE to provide COBRA Coverage to a limited number of retirees that are unable to acquire other coverage because they are difficult to insure or have preexisting condi tions will not have a material adverse effect on the financial statements. No reserves have been established by PGE for any amounts related to this issue.

Income Taxes

Under regulations issued by the U.S. Department of the Treasury, 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 PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax allocation agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. Enron obtained an agreement from the IRS on February 2, 2004 stipulating that PGE did become a member of the Enron consolidat ed group on December 24, 2002. Due to the uncertainty with the reconsolidation during 2003, PGE held certain tax payments due Enron. PGE resumed tax payments due Enron in early 2004.

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

Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS has completed an audit of the consolidated tax returns for 1996-2001.

For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from negotiation of the IRS audit for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.

Enron's 2003 tax return was filed on September 14, 2004. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2003. Enron had 2003 NOLs sufficient to eliminate Enron's regular and alternative minimum income tax liabilities for 2003 and expects to have sufficient NOLs to offset its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.

On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million with respect to income tax, interest, and penalties for taxable years in which PGE was included in Enron's consolidated tax return. The IRS seeks to apply $63 million in tax refunds admittedly due Enron against these claims. IRS claims for taxes and pre-petition interest have a priority over claims of general unsecured creditors, but claims for pre-petition penalties have no priority and claims for post-petition interest are not allowable in bankruptcy. The Company, along with other corporations in Enron's consolidated tax returns that are not in bankruptcy, are severally liable for pre-petition penalties and post-petition interest, as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the debtors.

Enron's management has informed PGE management that Enron is negotiating with the IRS in an attempt to resolve issues raised by the IRS claims. If the parties do not reach a settlement, the Bankruptcy Court will decide the actual amount, if any, owed to the government with respect to tax, interest, and penalties.

To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceedings, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group. As a result, management believes the income tax, interest, and penalty exposure to PGE (related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated returns) would not have a material adverse effect on the financial statements. No reserves have been established by PGE for any amounts 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 credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002 and in May 2003 and extended in May 2004. PGE management had been advised by Enron management and its legal advisors that, under the amended and restated credit agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron had pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. PGE management has been advised by Enron management that the debtor in possession credit agreement was replaced by separate letters of credit issued by Wachovia Bank National Association and that the liens and pledge of the PGE stock in favor of the debtor in possessio n lenders were released on or about August 24, 2004. The replacement letters of credit issued by Wachovia Bank National Association are secured by cash collateral and do not involve a pledge of the stock of PGE or any other assets.

Proposed Sale of PGE

On November 18, 2003, Enron and Oregon Electric, a newly-formed Oregon limited liability company financially backed by investment funds managed by Texas Pacific Group, entered into a definitive agreement under which Enron will sell all of the issued and outstanding common stock of PGE to Oregon Electric. The transaction is valued at approximately $2.35 billion, including the assumption of debt. The final amount of consideration will be determined on the basis of PGE's financial performance between January 1, 2003 and closing. The transaction, previously approved by the Enron Board of Directors and supported by the Official Unsecured Creditors' Committee, was approved by the Bankruptcy Court on February 5, 2004. The transaction also requires approval of the OPUC, the SEC, the FERC, and certain other regulatory agencies. Applications for approval of the acquisition of PGE by Oregon Electric have been filed with the OPUC (on March 8, 2004), the FERC (on April 6, 2004), the Nucle ar Regulatory Commission (on June 14, 2004), and the SEC (on July 29, 2004). On July 30, 2004, a petition was filed with Oregon's Energy Facility Siting Council for a declaratory ruling that the proposed acquisition is not a transfer of ownership that would require a transfer of certain generating plant site certificates held by PGE.

As part of the OPUC process to consider the proposed sale, testimony, settlement conferences, and hearings are continuing, with final oral arguments scheduled for December. A decision by the Commission is expected in early 2005.

If PGE is not sold, under the Chapter 11 Plan the shares of PGE's common stock will be distributed over time to the Debtors' creditors. Until shares are distributed to creditors, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of the creditors. Until either the sale to Oregon Electric is approved, the Chapter 11 Plan becomes effective and PGE's common stock is distributed to the Debtors' creditors, or another filing related to the sale of PGE is approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to the Debtors' creditors.

Note 8 - New Accounting Standard

On January 12, 2004, the Financial Accounting Standards Board (FASB) released FASB Staff Position No. FAS 106-1 (FSP 106-1), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefit plans. Under FSP 106-1, plan sponsors were allowed to elect a one-time deferral of the accounting for the Medicare Act until the FASB issued specific authoritative accounting guidance regarding the federal subsidy. PGE elected this one-time deferral.

On May 19, 2004, the FASB issued Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for the first interim period beginning after June 15, 2004 and superseded FSP 106-1. FSP 106-2 provides authoritative guidance on the accounting for the federal subsidy and specifies the disclosure requirements for employers who have adopted FSP 106-2. PGE has determined that its retiree health care plans are not actuarially equivalent to the benefits provided under Medicare Part D and, therefore, is not eligible for the subsidy. The adoption of FSP 106-2 did not have a material effect on the financial statements of the Company.

Note 9 - Commitments

Purchase Commitments

PGE has entered into contracts related to the construction of Port Westward, a 400-megawatt natural gas-fired combined cycle combustion turbine plant. It is anticipated that Port Westward will be operational by mid-2007 and require payments of approximately $250 million to $270 million (excluding Allowance for Funds Used During Construction). PGE has also entered into a contract for gas transportation capacity for Port Westward for payments of approximately $1 million in both 2005 and 2006 and approximately $2 million in 2007.

Purchased Power

Under PGE's Integrated Resource Plan, which was acknowledged by the OPUC, PGE entered into long-term power purchase contracts totaling 138 average MW and capacity contracts totaling 400 MW. These contracts were a result of requests for proposal (RFP) issued by PGE to prospective suppliers in 2003 to acquire resources to meet the electricity needs of its customers. The power purchase contracts require payments of approximately $18 million in 2005, $45 million in 2006, $42 million in both 2007 and 2008, and a total of $304 million over the period 2009 through 2016. The capacity contracts require payments of approximately $4 million in 2005, $5 million in 2006, 2007 and 2008, and a total of $9 million over the period 2009 through 2011.

PGE has long-term power purchase contracts with certain public utility districts in the State of Washington, including Douglas County PUD (Douglas), owner of the Wells Hydroelectric Project (Project). In 2003, the Confederated Tribes of the Colville Indian Reservation (Tribes) presented a claim to Douglas based upon alleged annual charges for the Project for the use of Colville tribal lands. On November 1, 2004, Douglas and the Tribes entered into a settlement under which Douglas will pay the Tribes $13.5 million. In addition, the Tribes would receive 4.5% of the Project's output (5.5% after 2018) and some non-Project lands owned by Douglas. PGE and the other purchasers of power from the Project will reimburse Douglas for the payment over 13 years, based on their respective share of the Project, and will have their share of the Project's output reduced. PGE will pay approximately $335,000 annually and its 20.3% share of the Project's output will be reduced by approximately 1%. The settleme nt is subject to approval by the FERC. Costs related to the settlement are included in projected power costs in PGE's 2005 Resource Valuation Mechanism (RVM) filings submitted to the OPUC in November 2004.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Overview

Operations - PGE continues to serve its customers effectively and operate well, with earnings for the first nine months of 2004 more typical of historical levels than in the same period of 2003. Although poor regional hydro conditions continue to impact PGE's financial performance, it is expected that the effects of a suppressed economy and recent years' financial reserves related to Enron's bankruptcy and the 2000-2001 West Coast energy crisis will have a reduced impact on the Company's future earnings. PGE continues to maintain investment-grade ratings on its secured debt, has adequate liquidity, and stable operating cash flow. Plans are moving forward to return control of employee benefit and retirement savings plans from Enron to PGE by the end of this year.

Retail loads during the first nine months of 2004 continue to run somewhat below both current year projections and last year's first nine months due to both the loss of two large industrial customers since the first half of 2003 and to warmer-than-normal weather early in 2004. On a weather-adjusted basis, however, retail energy sales have increased from last year's first nine months. Growth in both average energy usage and in the number of customers within PGE's service territory continues to partially offset the loss of industrial load.

PGE continues to oppose recent efforts by public power proponents to acquire Company service territory and is pleased with the continued support of its communities demonstrated by the rejection of PUD initiatives in Multnomah, Yamhill, Clackamas, and Washington Counties in the last twelve months.

Economy - Oregon's economy has continued to improve over the last year, adding about 46,000 seasonally-adjusted non-farm jobs (including 6,000 in manufacturing) between June 2003 and August 2004, an approximate 3% increase. Amid a national economy slowed by rising interest rates and oil prices, the state ranked second in July, and ninth in August, in year-over-year job growth. Although Oregon's unemployment rate remains among the highest in the nation, it dropped from a high of 8.7% in July 2003 to 7.3% in September 2004. PGE continues to experience customer growth, adding nearly 12,000 retail customers in the first nine months of this year.

PGE continues to work proactively to promote economic growth and business development in the region. Recently, the Company has been working closely with a public/private partnership, led by Oregon's governor, the state's two Senators, and key business leaders. Termed the "Oregon Plan", this partnership is intended to serve as the foundation of the state's economic development initiatives, with recent focus on identification of new project-ready industrial sites. These efforts have resulted in an increase in the number of businesses planning to expand or locate operations within PGE's service territory.

Power Supply - Despite heavy snowfall early in the year, regional hydro conditions have deteriorated significantly from initial forecasts due to reduced precipitation and generally dry conditions since February. Regional conditions are expected to remain significantly below normal for 2004, with both the Clackamas and Deschutes river systems, where PGE's hydro generation facilities are located, also below previously projected levels. To the extent that hydro conditions utilized in power cost projections for setting customer rates are not realized, power costs will increase, as greater output from PGE's thermal generating plants, as well as higher purchased power costs, will be necessary to meet the Company's load requirements. During the first nine months of 2004, PGE effectively utilized its generating assets and position in the wholesale marketplace to meet load requirements and partially offset the adverse financial effects of poor regional hydro conditions.

PGE's hydro plants continue to serve as a reliable low-cost resource, providing economical power for customers. In conjunction with a 50-year relicensing application for the Pelton Round Butte hydro project, a settlement agreement, providing for fish passage over the project's dams, was completed and signed by all participants in July and submitted to the FERC for approval. Recently completed efficiency upgrades to the Boardman coal plant, accomplished during an extended maintenance outage, increased PGE's share of the plant's generation by 21 MW, enough electricity to serve about 13,000 homes with no additional fuel requirements.

Under the Resource Valuation Mechanism (RVM) process, by which retail rates are adjusted annually with changes in projected power costs, PGE has submitted preliminary and updated RVM filings to the OPUC containing estimates of 2005 power costs. Recent updates to such estimates indicate an approximate rate increase of less than 1% for residential customers, with an approximate 5% increase for large non-residential customers. Rates for small non-residential customers are expected to decrease by less than 1%. Such rates, which will be finalized later in November, will become effective on January 1, 2005.

PGE has withdrawn its two hydro cost deferral applications covering the current year, previously filed with the OPUC, and has asked that the Commission instead consider a proposed Hydro Generation Adjustment mechanism and tariff that would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions. A procedural schedule has been adopted by the OPUC, with a decision expected in the first half of 2005. Any deferral of costs, for future recovery or refund, would begin only upon approval of the proposed tariff.

PGE's Integrated Resource Final Action Plan received formal acknowledgement of the OPUC in July 2004. The plan contains specific resource actions to meet the future electricity needs of customers, including construction of a natural gas-fired plant at Port Westward in Columbia County, Oregon and increased use of renewable energy resources. As part of the plan, PGE has entered into a ten-year power purchase agreement for 85 average MW, beginning in late 2006, and also into two five-year agreements, for 14 average MW and 25 average MW, beginning in early 2005 and late 2006, respectively. Agreements providing for 400 MW of peaking capacity, beginning in early 2005 and extending into 2011, were entered into in October 2004. These agreements, the first results from last year's request for proposals issued as part of the Integrated Resource Plan, provide competitive and reliable sources of supply for PGE customers.

Proposed Sale of PGE - The proposed sale of PGE by Enron to Oregon Electric continues to move through the formal legal and regulatory hearing and approval process. In September, the staff of the OPUC recommended approval of the sale subject to certain conditions, including customer rate credits and limitations on distributions from PGE to Oregon Electric. PGE management believes the proposed transaction represents the best possible outcome for the Company and is working to support its full regulatory approval. A decision is currently expected in early 2005.

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the consolidated financial 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 2004.

2004 Compared to 2003 for the Three Months Ended September 30

PGE's net income in the third quarter of 2004 was $10 million, compared to a net loss of $4 million in the third quarter of 2003. Results for last year's third quarter included after tax provisions totaling approximately $12 million related to investigations into wholesale power market activities during 2000 and 2001, consisting of $7 million related to amounts due the Company for wholesale electricity sales made in California and $5 million related to a settlement agreement between PGE, the FERC, and other parties. The effect of lower interest charges and administrative expenses in this year's third quarter was partially offset by reduced margins on lower energy sales.

The following table summarizes Operating Revenues and Energy Sales for the third quarter of 2004 and 2003:

	Three Months Ended September 30,
Operating Revenues	2004	2003	Increase/ (Decrease)
(In Millions)

Retail ^(a)	$ 316	$ 318	$ (2)
Wholesale (Non-Trading) ^(b)	26	171	(145)
Other Operating Revenues:
Trading Activities - net	-	-	-
Other	6	5	1
Total Operating Revenues	$ 348	$ 494	$(146)

Energy Sales
(In Thousands of MWhs)

Retail ^(a)	4,337	4,474	(137)
Wholesale (Non-Trading)^(b)	574	3,955	(3,381)
Trading Activities	3,098	4,140	(1,042)
Total Energy Sales	8,009	12,569	(4,560)

Retail revenues for 2004 includes $2 million for distribution services related to delivery of 206 thousand MWhs (not included in Energy Sales) to customers of Energy Service Suppliers (ESS). Under Oregon's electricity restructuring law, certain commercial and industrial customers have chosen to be served by an ESS for their energy needs, beginning in 2004. Although the energy is purchased from an ESS, PGE delivers the energy to these customers and bills them a distribution service charge.

Wholesale (Non-Trading) revenues and energy sales for 2004 exclude $101 million and 2,207 thousand MWhs of sales, respectively, reflecting the net basis presentation required by EITF 03-11, which became effective on October 1, 2003. Prior period amounts have not been reclassified.

Retail revenues decreased by approximately 1% from the third quarter of last year due primarily to lower energy sales. Retail energy sales decreased about 3.2% due largely to a 15% decline in industrial sales, most of which was attributable to a single large customer which in 2004 began purchasing its energy requirements from an ESS, resulting in an approximate $5 million revenue decrease. An additional $3 million decrease in retail revenues resulted from the loss of other non-residential customers now served by ESS's. Total residential and commercial energy sales increased slightly from last year's third quarter, with a 3% increase in residential sales largely offset by a 1% decrease in commercial sales. An approximate 0.4% average rate increase for 2004 also partially offset the decrease in industrial energy sales and revenues during the quarter. (See "Retail Rate Changes" in the Financial and Operating Outlook section for further information).

Wholesale revenues and energy sales for the third quarter of 2004 exclude $101 million and 2,207 thousand MWhs of sales due to the adoption of EITF 03-11 in the fourth quarter of 2003. Beginning October 1, 2003, revenues and expenses related to non-trading energy activities that are not physically settled, formerly included on a "gross" basis within both Operating Revenues and Purchased Power and Fuel expense, are recorded on a "net" basis in Purchased Power and Fuel expense. This change results in a decrease in reported non-trading wholesale energy sales and purchases and related amounts in comparative financial statements. Although determination of the effect of the change on prior year reported revenues and expenses is not practicable, the change has no impact on reported net income. The remaining $44 million decrease in wholesale revenues was attributable to a 30% reduction in energy sales. The decrease was partially offset by a 5% increase in average prices, due primarily to high er natural gas prices and a reduction in regional hydro availability.

Other Operating Revenues approximated that of last year's third quarter, with increased revenues from the sale of transmission capacity partially offset by decreased gains on the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense for the third quarter of 2004 exclude $101 million related to the adoption of EITF 03-11 (described above). In addition, third quarter 2003 expense included an $11 million provision for uncollectible accounts receivable for wholesale electricity sales in the California market during 2000 and 2001. The remaining $45 million decrease from last year's third quarter is attributable to a reduction in power purchased to meet a lower total system load requirement. Partially offsetting the effect of a decrease in system load was an approximate 1% increase in PGE's average variable power cost for the quarter, with a higher average cost of Company generation partially offset by a lower average cost of purchased power. The average price of purchased power decreased approximately 1%, with a 5% decrease in the average price of term power purchases partially offset by higher spot market prices. Company generation decreased 4% from that of last year's third quar ter, as a 24% decrease in coal-fired generation (due primarily to the Boardman plant's extended maintenance outage) was largely offset by an increase in combustion turbine generation. PGE hydro production approximated that of last year's third quarter. Total generation met approximately 44% of PGE's retail load during the third quarter of 2004, compared to 45% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the third quarter of 2004 and 2003. Average variable power costs exclude the effect of provisions for uncollectible wholesale accounts receivable.

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

	2004		2003	2004	2003
Generation	2,073		2,166	19.4	15.4
Term Purchases	2,662		6,002	37.4	39.1
Spot Purchases	513		566	45.8	41.6
Total Send-Out	5,248		8,734	35.4*	35.1*

(*includes wheeling costs)

Note: Megawatt-Hours indicated above for 2004 exclude Term Purchases and Spot Purchases of 1,708 thousand MWhs and 499 thousand MWhs, respectively, to reflect the net basis presentation required by EITF 03-11, which became effective on October 1, 2003. Average Variable Power Cost amounts exclude the effect of the reductions.

Production, distribution, administrative and other expenses increased $1 million (2%) from the third quarter of 2003 primarily due to increased costs related to a major maintenance outage at the Boardman coal plant that extended into this year's third quarter and to higher distribution expenses, including increased tree trimming requirements. These increases were partially offset by reduced corporate overhead charges from Enron.

Depreciation and Amortization expense increased $6 million (12%) due partially to a $3 million increase in amortization of regulatory assets (including costs related to implementation of Oregon's electricity restructuring law), the effects of which are fully offset within Operating Revenues. The remaining increase resulted from a reduction from last year's third quarter deferral of certain regulatory assets and an increase in depreciation and amortization of utility plant due to normal property additions.

Income taxes increased $3 million primarily due to higher taxable income.

Other Income (Miscellaneous) increased $9 million due primarily to an $8.5 million charge recorded in last year's third quarter related to a September 2003 settlement agreement between PGE, the FERC, and other parties related to investigations into prior years' wholesale power market activities.

Interest Charges decreased $3 million (15%) due to both a lower level of outstanding long-term debt in this year's third quarter and to the replacement of higher rate debt in the second half of 2003.

2004 Compared to 2003 for the Nine Months Ended September 30

PGE's net income in the first nine months of 2004 was $64 million, compared to $30 million in the first nine months of 2003. Results for the first nine months of 2003 include after tax provisions totaling approximately $19 million related to investigations into wholesale power market activities during 2000 and 2001, consisting of $14 million related to amounts due the Company for wholesale electricity sales made in California and $5 million related to a settlement agreement between PGE, the FERC, and other parties. Results for the first nine months of 2003 also include a $2 million gain from a cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations.

The remaining increase in net income in this year's first nine months was due primarily to improved margins on energy sales resulting from economic decisions related to the utilization of the Company's thermal generating assets and activities in the wholesale marketplace. In addition, last year's margin for the first nine months reflects a disallowance by the OPUC of certain power purchase contracts in rates charged customers. These factors, along with lower interest charges and administrative expenses, more than offset the impact of a reduction in retail energy sales during the first nine months of this year.

The following table summarizes Operating Revenues and Energy Sales for the nine-month periods ending September 30, 2004 and 2003:

	Nine Months Ended September 30,
Operating Revenues	2004	2003	Increase/ (Decrease)
(In Millions)

Retail ^(a)	$ 970	$ 978	$ (8)
Wholesale (Non-Trading) ^(b)	82	371	(289)
Other Operating Revenues:
Trading Activities - net	1	2	(1)
Other	22	24	(2)
Total Operating Revenues	$1,075	$1,375	$ (300)

Energy Sales
(In Thousands of MWhs)

Retail ^(a)	13,099	13,649	(550)
Wholesale (Non-Trading)^(b)	1,999	9,450	(7,451)
Trading Activities	8,660	10,370	(1,710)
Total Energy Sales	23,758	33,469	(9,711)

(a) Retail revenues for 2004 includes $5 million for distribution services related to delivery of 578 thousand MWhs (not included in Energy Sales) to customers of Energy Service Suppliers (ESS). Under Oregon's electricity restructuring law, certain commercial and industrial customers have chosen to be served by an ESS for their energy needs, beginning in 2004. Although the energy is purchased from an ESS, PGE delivers the energy to these customers and bills them a distribution service charge.

(b) Wholesale (Non-Trading) revenues and energy sales for 2004 exclude $230 million and 5,419 thousand MWhs of sales, respectively, reflecting the net basis presentation required by EITF 03-11, which became effective on October 1, 2003. Prior period amounts have not been reclassified.

The decrease in Retail Revenues from the first nine months of 2003 was caused by lower energy sales. Retail energy sales decreased 4% due largely to a 23% decline in industrial sales, most of which was attributable to two large customers, with one now generating its own power requirements and the other now served by an ESS. The decrease in revenue from these two customers approximated $26 million, including about $13 million attributable to the customer now served by an ESS. An additional $15 million decrease in retail revenues resulted from the loss of other non-residential customers now served by ESS's. Reduced industrial energy sales were partially offset by higher residential and commercial sales, which increased by about 2.4% and 1%, respectively, in the first nine months of the year. An approximate 11,500 average increase in customers served, combined with significantly colder January weather, more than offset the effects of warmer temperatures during the remainder of the year 's first half. Also partially offsetting the effect of reduced industrial energy sales was an approximate 0.4% average rate increase for 2004. (See "Retail Rate Changes" in the Financial and Operating Outlook section for further information).

Wholesale revenues and energy sales for the first nine months of 2004 exclude $230 million and 5,419 thousand MWhs related to the adoption of EITF 03-11 in the fourth quarter of 2003. The remaining $59 million decrease was attributable to a 22% reduction in wholesale energy sales. The decrease was partially offset by a 4% increase in average prices, due primarily to higher natural gas prices and a reduction in regional hydro availability.

The decrease in Other Operating Revenues was primarily related to reduced sales of natural gas in excess of generating plant requirements, as power purchases in the wholesale market economically displaced more expensive gas-fired thermal generation. Such sales in the first nine months of 2004 resulted in a $7 million gain, compared to an $11 million gain in the first nine months of 2003. This decrease was partially offset by increased revenue from the sale of transmission capacity in excess of the Company's needs.

Purchased Power and Fuel expense for the first nine months of 2004 exclude $230 million related to the adoption of EITF 03-11. In addition, expense for the first nine months of 2003 included a $22.5 million ($14 million after taxes) provision for uncollectible accounts receivable for wholesale electricity sales in the California market. (For further information, see "Receivables and Refunds on Wholesale Market Transactions" in the Financial and Operating Outlook section). The remaining $113 million decrease from last year's first nine months is largely attributable to a reduction in power purchased to meet a lower total system load requirement as well as a lower average variable power cost. A decrease in the average price of both term power purchases and Company generation resulted in a 3% reduction in PGE's average variable power cost from the first nine months of 2003. Company generation increased 1% from last year's first nine months, with higher combustion turbine generation parti ally offset by decreased coal-fired generation, due primarily to the Boardman plant's extended maintenance outage. PGE hydro production approximated that of last year's first nine months. Total generation met approximately 42% of PGE's retail load in the first nine months of 2004, compared to 40% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the first nine months of 2004 and 2003. Average variable power costs exclude the effect of provisions for uncollectible wholesale accounts receivable.

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

	2004	2003	2004	2003
Generation	5,850	5,819	15.8	16.3
Term Purchases	9,135	16,395	33.9	35.1
Spot Purchases	989	1,884	41.9	40.4
Total System Load	15,974	24,098	31.9*	32.9*
(*includes wheeling costs)

Note: Megawatt-Hours indicated above for 2004 exclude Term Purchases and Spot Purchases of 3,952 thousand MWhs and 1,467 thousand MWhs, respectively, to reflect the net basis presentation required by EITF 03-11, which became effective on October 1, 2003. Average Variable Power Cost amounts exclude the effect of the reductions.

Production, distribution, administrative and other expenses increased $6 million (3%) from the first nine months of 2003 due primarily to costs related to an extended maintenance outage at the Boardman coal plant, increased service restoration costs (net of insurance recovery) related to a five-day snow and ice storm in January 2004, and higher distribution expenses, including increased tree trimming requirements. Increases in both employee benefit expenses (including medical and pension costs) and customer service and support expenses were offset by a decrease in corporate overhead charges from Enron.

Depreciation and Amortization expense increased $14 million (9%) due primarily to an $8 million increase in amortization of regulatory assets (including costs related to implementation of Oregon's electricity restructuring law), the effects of which are fully offset within Operating Revenues. The remaining increase resulted from a reduction in the deferral of certain regulatory assets from the first nine months of last year, as well as an increase in depreciation and amortization of utility plant due to normal property additions.

Income taxes increased $19 million primarily due to higher taxable income.

Other Income (Miscellaneous) increased $5 million. Results for the first nine months of last year included an $8.5 million charge related to a September 2003 settlement agreement between PGE, the FERC, and other parties related to investigations into prior years' wholesale power market activities. Partially offsetting the effect of this charge was a reduction in interest income in this year's first nine months, related primarily to lower remaining balances to be collected under the Company's 2000-2001 power cost adjustment mechanisms.

Interest Charges decreased $6 million (10%) due to both a lower level of outstanding long-term debt in this year's first nine months and to the replacement of higher rate debt in the second half of 2003.

Capital Resources and Liquidity

Review of Statements of Cash Flows

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 consists of charges that are recovered in customer revenues for depreciation and amortization of utility plant that require no current period cash outlay. The recovery from customers of prior capital expenditures through depreciation and amortization provides a source of funding for current and future cash requirements. Cash flows from operations can also be affected by weather conditions, as temperatures outside the normal range can affect electricity usage and resultant operating cash flow, as well as the need for short-term borrowings to meet current cash requirements.

Cash provided by operating activities totaled $277 million in this year's first nine months compared to $237 million in the same period last year. The increase is due to cash collateral deposits received from certain wholesale customers and cash from other operating activities. Cash from operations and remaining proceeds from long-term debt issued in 2003 were invested primarily in government money market funds at September 30, 2004. Such investments are consistent with PGE's investment objectives to preserve principal, maintain liquidity, and diversify risk. Company investments are limited to investment grade securities (primarily short term), as approved by PGE's board of directors.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. The $32 million increase in capital expenditures in the first nine months of 2004 is primarily attributable to improvements and expansion of PGE's distribution system to support both new and existing customers within the Company's service territory as well as to efficiency upgrades to the Boardman coal plant, relicensing expenditures, and initial costs of Port Westward. The $37 million change in "Other - net" is due primarily to the early repayment by BPA of certain residential exchange benefits, originally deferred until later years, pursuant to a 2003 agreement. Also contributing to the change were decreased funding requirements of the Trojan Decommissioning Trust in 2004.

Financing Activities provide supplemental cash for both day-to-day operations and capital requirements as needed. PGE relies on cash from operations, borrowings under its revolving credit facilities, commercial paper borrowings, and long-term financing activities to support such requirements.

During the first nine months of 2004, PGE paid $45 million in matured First Mortgage Bonds and $7 million of conservation bonds and also retired $3 million of preferred stock which had been reflected in long-term obligations on the financial statements. In addition, the Company redeemed the remaining $5 million of 8 1/4% Junior Subordinated Deferrable Interest Debentures, Series A, due in 2035. Pursuant to the redemption, PGE filed in June 2004 to terminate registration of these securities under the Securities Exchange Act of 1934. The Company has de-listed from the New York Stock Exchange and is no longer listed on any stock exchange.

PGE paid $1 million of preferred stock dividends during the first nine months of 2004. In accordance with requirements of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which became effective July 1, 2003, preferred stock dividends are now classified as interest expense on the income statement. No cash dividends on common stock were declared or paid in the first nine months of 2004 or 2003.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Company's Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. As of September 30, 2004, PGE has the capability to issue additional preferred stock and First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.

PGE has two revolving credit facilities with a group of commercial banks totaling $150 million, consisting of a $50 million 364-day facility and a $100 million three-year facility. The facilities, both of which are unsecured, each contain material adverse effect clauses and financial covenants that limit consolidated indebtedness, as defined in the facilities, to 60% of total capitalization. In addition, the three-year facility requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.00:1. At September 30, 2004, the Company's indebtedness to total capitalization and interest coverage ratios, as calculated under the facilities, were 41.5% and 6.34:1, respectively. The 364-day facility contains a "term out" option that would allow the Company to extend the final maturity of amounts outstanding at the date the facility expires for up to one additional year. Under the three-year credit facility, PGE has the option to issue up to $100 million in letters of credit. At September 30, 2004, the Company had utilized approximately $1 million in letters of credit, all of which were related to wholesale trading activities. The agreements provide for borrowings at a variable interest rate and require annual facility fees based on the Company's unsecured credit rating. In addition, the agreements provide for termination of the banks' obligation, and the full repayment of any outstanding balances, in the event of the sale of the Company's common stock to Oregon Electric or other changes in control (as defined in the agreements). The new facilities allow PGE to pay cash dividends on common stock, subject to certain restrictions.

Cash Requirements

Access to short-term debt markets provides necessary liquidity to support PGE's current operating activities, including the purchase of electricity and fuel. Long-term capital requirements are driven largely by debt refinancing activities and capital expenditures for distribution, transmission, and generation facilities supporting both new and existing customers.

PGE's liquidity and capital requirements can be significantly affected by operating, capital expenditure, debt service, and working capital needs, including margin deposits related to wholesale trading activity. PGE's revolving credit facilities supplement operating cash flow and provide a primary source of liquidity. PGE's ability to secure sufficient long-term capital at reasonable cost is determined by its financial performance and outlook, capital expenditure requirements (including the effects of these factors on the Company's credit ratings), and alternatives available to investors. The Company's ability to obtain and renew such financing depends on its credit ratings as well as on bank credit markets, both generally and for electric utilities in particular.

PGE's financial objectives have been established by the Company's management and approved by its board of directors. Such objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company's financial obligations. PGE's objective is to maintain a common equity ratio (common equity to

total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow are necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 57.6% and 54.7% at September 30, 2004 and December 31, 2003, respectively.

As previously indicated, a significant portion of cash provided by operations consists of depreciation and amortization of utility plant which is recovered in rates. PGE estimates recovery of such charges to approximate $160 million to $190 million annually over the period 2004-2006. Combined with all other sources, total cash provided by operations is estimated to range from $265 million to $335 million annually during the 2004-2006 period.

The following table indicates PGE's projected primary cash requirements for the years indicated (in millions):

	2004	2005	2006

Capital expenditures (a)	$200 - $220	$245 - $265	$360 - $380
Long-term debt maturities	$56	$30	$11

(a) Includes expenditures related to the construction of Port Westward (approximately $8 for 2004, $64 for 2005, and $159 for 2006).

Projected cash flow from operations in excess of cash requirements may be used to fund costs associated with securing new energy resources. If the proposed sale of PGE to Oregon Electric closes, PGE anticipates it will declare and pay a common stock dividend to Oregon Electric in the range of $240 million to $255 million in early 2005. To the extent necessary, long-term debt may be considered to fund any potential cash shortfall. Additional liquidity is available under the Company's revolving credit facilities. PGE anticipates long-term financing activity of approximately $100 million to $150 million in 2005.

Credit Ratings

PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's Investors Service (Moody's) and Standard and Poor's (S&P). Fitch Ratings (Fitch) rates PGE's secured debt at investment grade and unsecured debt at below investment grade.

PGE 's current credit ratings are as follows:

	Moody's	S&P	Fitch

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

Outlook:	Developing	CreditWatch Negative	Positive

S&P's outlook on the Company's credit ratings is based upon their view of the consolidated leverage resulting from Oregon Electric's proposed acquisition of PGE from Enron. 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. On September 30, 2004, PGE had posted approximately $2 million of collateral, consisting of $1 million in letters of credit and $1 million in cash. Based on the Company's non-trading and trading portfolios, estimates of current energy market prices, and the current level of collateral outstanding, as of September 30, 2004, the approximate amount of additional collateral that could be requested upon such a downgrade event is $38 million and decreases to approximately $15 million by year-end 2004. Furthermore, upon a downgrade event, collateral could be required for the Company 's transmission contracts in the amount of $25 million. In addition to collateral calls, such a credit rating reduction could impact the terms and conditions of long-term debt issued in the future. Any rating reductions could also increase interest rates and fees on PGE's revolving credit facility, increasing the cost of funding the Company's day-to-day working capital requirements. As discussed in "Cash Requirements" above, management believes that the Company's existing lines of credit, access to the commercial paper market, and cash from operations provide it with sufficient liquidity to meet its day-to-day cash requirements.

In order to increase the degree of insulation between PGE and its insolvent parent company, PGE, in September 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 voting rights which limit PGE's right to commence a voluntary bankruptcy proceeding without the consent of the holder of the share.

Although measures of PGE's financial performance, including financial ratios, remain strong, due to continuing uncertainty regarding the impact of Enron's bankruptcy on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, PGE management believes there are sufficient structural and regulatory mechanisms to protect the Company's assets from Enron and its creditors and there are no economic incentives for Enron to cause PGE to file for bankruptcy protection. 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. 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 and there are no loans between them. Under Oregon law and specific conditions imposed on Enron and PGE by t he OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997, Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. PGE is a solvent enterprise whose greatest value is as a going concern. In a bankruptcy, Enron would lose most, if not all, control over PGE. It would merely continue to be 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. Any plan of reorganization would be devised by PGE management and approved by PGE's creditors, not Enron or its 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 PGE creditors and the Bankruptcy Court. PGE believes that the OPUC would challenge any attempt in the bankruptcy proceedings 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 without OPUC approval.

Financial and Operating Outlook

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales for the first nine months of 2004 increased approximately 1% from that of last year's first nine months, with a 4% increase in weather adjusted residential and commercial energy sales partially offset by decreased industrial sales. The decrease in industrial energy sales was largely attributable to two large customers, one of which elected to obtain its electricity requirements through co-generation. These two customers represented 3.4% of weather adjusted retail energy sales in the first nine months of 2003. The increase in residential and commercial energy sales is attributable to increases in both the number of customers served and in average energy use. PGE forecasts retail energy sales growth of approximately 1% in 2004 and 2% in 2005.

Power Supply

Hydro conditions in the region continued to remain below normal levels in the first nine months of 2004. 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, indicate the January-to-September runoff at 78% of normal, down from 87% of normal projected earlier in 2004. Actual January-to-September runoff in 2003 was 83% of normal. Hydro conditions in the Clackamas and Deschutes river systems, where PGE's facilities are located, are currently projected at 82% and 87% of normal for 2004, both down from projections made earlier in the year.

PGE generated 42% of its retail load requirement in the first nine months of 2004, with 33% met with thermal generation and the remaining 9% with hydro generation; short- and long-term purchases were utilized to meet the remaining load. 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.

The amount of surplus electric generating capability in the western United States, the amount of annual snow pack and its impact on hydro generation, the number and credit quality of wholesale marketers and brokers participating in the energy trading markets, the availability and price of natural gas as well as other fuels, and the availability and pricing of electric and gas transmission all continue to have an impact on the wholesale price and availability of electricity. PGE will continue its participation in the wholesale energy marketplace in order to manage its power supply risks and acquire the necessary electricity and fuel to meet the needs of its retail customers and administer its current long-term wholesale contracts. In addition, the Company will continue its trading activities to participate in electricity, natural gas, and crude oil markets.

Price Risk Management - As PGE's primary business is to serve its retail customers, it uses derivative instruments to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, PGE records unrealized gains and losses in earnings in the current period for derivative instruments that do not qualify for either the normal purchases and normal sales exception or cash flow hedge accounting. Derivative instruments that qualify for the normal purchases and normal sales exception are recorded in earnings on a settlement basis, and cash flow hedges are recorded in Other Comprehensive Income until they can offset the related results on the hedged item in the income statement.

From the time rates are set in the RVM process until the end of the RVM period, any changes to electricity and natural gas prices used in the RVM will result in unrealized gains and losses to be recorded in earnings in the current period on existing and new derivative instruments that do not qualify for the normal purchases and normal sales exception or cash flow hedges. Price movements in electricity and natural gas markets cause PGE to make power and natural gas purchases and sales decisions around the economic dispatch of its own generation. Derivative instruments that qualify for the normal purchases and normal sales exception or cash flow hedges, and forecasted transactions related to these decisions are not recorded in earnings in the current period, but are recognized in earnings when the contracts are settled in future periods. As a result, this timing difference may create earnings volatility between reporting periods.

Enron Bankruptcy

Bankruptcy Proceedings and Chapter 11 Plan

Commencing in December 2001, Enron and certain of its subsidiaries (Debtors) filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the bankruptcy, but the common stock of PGE held by Enron is part of the bankruptcy estate.

The Debtors have filed their proposed joint Chapter 11 plan (the Chapter 11 Plan) and related disclosure statement (the Disclosure Statement) with the Bankruptcy Court. The Chapter 11 Plan and Disclosure Statement, as amended, provide information about the assets that are in the bankruptcy estate, including the common stock of PGE, and how those assets will be distributed to the creditors. The Chapter 11 Plan and the Disclosure Statement are available at Enron's website located at www.enron.com/corp/por and the Bankruptcy Court's website located at www.nysb.uscourts.gov and at the website maintained at the direction of the Bankruptcy Court at www.elaw4enron.com. The Chapter 11 Plan has been approved by the creditors and was confirmed by the Bankruptcy Court on July 15, 2004.

Enron has entered into an agreement to sell PGE, which has been approved by the Bankruptcy Court and is included in the Chapter 11 Plan. The sale requires certain regulatory approvals. If the sale does not close, shares of PGE's common stock will be distributed over time to the Debtors' creditors. It is anticipated that once a sufficient amount of the common stock is distributed to creditors, the shares would be publicly traded.

Proposed Sale of PGE

On November 18, 2003, Enron and Oregon Electric, a newly-formed Oregon limited liability company financially backed by investment funds managed by Texas Pacific Group, entered into an agreement under which Enron will sell all of the issued and outstanding common stock of PGE to Oregon Electric. The transaction is valued at approximately $2.35 billion, including the assumption of debt. The final amount of consideration will be determined on the basis of PGE's financial performance between January 1, 2003 and closing. The transaction, previously approved by the Enron Board of Directors and supported by the Official Unsecured Creditors' Committee, was approved by the Bankruptcy Court on February 5, 2004. The transaction also requires approval of the OPUC, the SEC, the FERC, and certain other regulatory agencies. Applications for approval of the acquisition of PGE by Oregon Electric have been filed with the OPUC (on March 8, 2004), the FERC (on April 6, 2004), the Nuclear Regulat ory Commission (on June 14, 2004), and the SEC (on July 29, 2004). On July 30, 2004, a petition was filed with Oregon's Energy Facility Siting Council for a declaratory ruling that the proposed acquisition is not a transfer of ownership that would require a transfer of certain generating plant site certificates held by PGE.

In July 2004, the OPUC Staff and other intervenors filed their initial testimony that the sale of PGE to Oregon Electric not be approved unless greater net benefits for customers of PGE can be demonstrated. In September, OPUC Staff recommended approval of the sale subject to certain conditions, including customer rate credits and limitations on distributions from PGE to Oregon Electric. Oregon Electric has responded to concerns raised by the staff and other intervenors in subsequent rebuttal testimony and settlement meetings. Hearings were held in October and final oral arguments are scheduled for December. A decision by the Commission is expected in early 2005.

Liabilities and Impairments

Although PGE is not included in the Enron bankruptcy, it has been affected. 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 de-listed from 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. PGE has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating.

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 in Bankruptcy - PGE is owed approximately $73 million by Enron at September 30, 2004 (Merger Receivable). Such amount was to have been paid by Enron to PGE for price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE established a reserve for the entire amount of this receivable in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, at September 30, 2004, PGE has outstanding accounts receivable of $8 million from Enron and its subsidiary companies which are part of the bankruptcy proceedings, consisting of $5 million due from PGH, $2 million from EPMI , and $1 million from Enron. Based on management's assessment of the realizability of these balances, a reserve of $4 million has been established.

2. Controlled 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 (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2003, the total fair value of PGE Plan assets was $15 million higher than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, the PGE Plan was over-funded on an accumulated benefit obligation basis by about $68 million as of December 31, 2003. Enron's management has informed PGE that, as of December 31, 2003, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $60 million on a SFAS No. 87 basis and approximately $162 million on a plan termination basis. The PBGC insures pension plans, including the PGE Plan and the Enron Plan and the pension plans of other Debtors. Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases with respect to the Enron Plan and the plans of the other Debtors ( Pension Plans). The claims are duplicative in nature because certain liability under ERISA is joint and several. Five of the PBGC's claims represent unliquidated claims for PBGC insurance premiums (the Premium Claims), five are unliquidated claims for due but unpaid minimum funding contributions (the Contribution Claims) under the Internal Revenue Code of 1986, as amended, and ERISA, 26 U.S.C. Section 412, and 29 U.S.C. Section 1082, and the remaining five claims are for unfunded benefit liabilities (the UBL Claims). PBGC has amended the UBL Claims several times, up to an aggregate high of $424.1 million. PBGC has informed the Debtors that it has reduced its aggregate estimate of the UBL Claims for the Pension Plans to an aggregate of $321.8 million, including $240.2 million for the Enron Plan and $64.6 million related to the PGE Plan, although it has not amended the UBL Claims to reflect those amounts. The Debtors are current on their PBGC premiums and their minimum funding contributions to the Pension Plans. Therefore, the Debtors' value the Premium Claims and the Contribution Claims at $0. Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has not provided support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

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, any 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, 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. PGE's management believes that it is unlikely that either Enron or Enron's creditors would agree to support merging the two plans.

Enron cannot itself terminate the Enron Plan while it is underfunded 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 PGE management, PGE is a solvent entity that does not meet the financial distress test. Consequently, PGE management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan while it is underfunded. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.

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 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 an underfunded 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 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. PGE management believes that any lien asserted by the PBGC would be subordinate to that lien. In addition, the PBGC retains an interest in any sales proceeds generated by the Enron auction process for PGE (see "Proposed Sale of PGE" in this section for additional information).

On January 30, 2004, the Bankruptcy Court entered an order authorizing Enron and its affiliated debtors to contribute $200 million to the Pension Plans to fund and terminate them in a manner that should eliminate the PBGC's claims. However, there can be no assurance that Enron will have the ability to obtain funding for accrued benefits on acceptable terms, that certain funding contingencies will be met, or that the required government agencies that review pension plan terminations will approve the termination of the Pension Plans. If the proposal to fund and terminate the Enron Plan, as stated in the Disclosure Statement and as set forth in Enron's motion, is approved and consummated, it should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the Enron Plan.

The PGE Plan was not included in the above Complaint, nor was PGE issued a similar notice of determination regarding the PGE Plan. The PBGC has taken no action to terminate the PGE Plan.

PGE management cannot predict the outcome of the above matters or estimate any potential loss. In the event that 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 Enron's controlled group. 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 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 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 arise against the assets of PGE and all other members of the Enron controlled group. The PBGC would be entitled to 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 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's management understands that Enron has made all required contributions to date. PGE does not know if Enron will make contributions as they become due. PGE 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 misses contributions exceeding $1 million, PGE has no liability and no liens will 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

PGE management understands, based on discussions with Enron management, that Enron maintains a group health plan for certain of its retirees. If retirees of Enron lose coverage under Enron's group health plan for retirees due to Enron's bankruptcy proceedings, the retirees must be provided the opportunity to purchase continuing coverage (known as COBRA Coverage) from an Enron group health plan, if any, or the appropriate group health plan of another member of the Enron controlled group. The liability for benefits under the Enron group health plan for retirees (other than the potential liability to provide COBRA Coverage) is not a joint and several obligation of other members of the Enron controlled group, including PGE, so PGE would not be required to assume from Enron, or otherwise pay, any liabilities from the Enron group health plan. Neither PGE nor any other member of Enron's controlled group would be required to create new plans to provide COBRA Coverage for Enron's retirees, and the retirees would not be entitled to choose the plan from which 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 purchase COBRA Coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire COBRA Coverage. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

PGE 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 discussions 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. PGE 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, PGE 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. PGE management believes that the additional cost to PGE to provide COBRA Coverage to a limited number of retirees that are unable to acquire other coverage because they are difficult to insure or have preexisting condi tions will not have a material adverse effect on the financial statements. 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 PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax allocation agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. Due to the uncertainty with the reconsolidation during 2003, PGE held certain tax payments due Enron. Enron obtained an agreement from the IRS on February 2, 2004 stipulating that PGE did become a member of the Enron consolidated group on December 24, 2002. PGE resumed tax payments due Enron in early 2004.

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

Enron's consolidated tax returns through 1995 have been audited and are closed. Management understands that the IRS has completed an audit of the consolidated tax returns for 1996-2001.

For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from negotiation of the IRS audit for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.

Enron's 2003 tax return was filed on September 14, 2004. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2003. Enron had 2003 NOLs sufficient to eliminate Enron's regular and alternative minimum income tax liabilities for 2003 and expects to have sufficient NOLs to offset its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.

To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that 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. As a result, management believes the income tax, interest, and penalty exposure to PGE (related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated returns) would not have a material adverse effect on the financial statements. No reserves have been established by PGE for any amounts related to this issue.

PGE management cannot predict with certainty what impact Enron's bankruptcy, including the Chapter 11 Plan, 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. 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 PGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's common equity capital to fa ll below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The 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 separately from Enron, on both a short- and long-term basis.

PGE management does not 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. As a solvent enterprise in bankruptcy, PGE would owe fiduciary obligations to its shareholders and creditors. If a bankruptcy were commenced, the United States Trustee would form a creditors' committee comprised of PGE's largest creditors, and any plan of reorganization would be subject to confirmation by the Bankruptcy Court. Prior to the effectiveness of such plan, no dividends could be paid to Enron, and no assets could be sold, or transfer of funds could be made, outside the ordinary course of business except with the approval of the Bankruptcy Court. 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 sta te 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 litigation. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. 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.

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 credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002 and in May 2003 and extended in May 2004. PGE management had been advised by Enron management and its legal advisors that, under the amended and restated credit agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron had pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. PGE management has been advised by Enron management that the debtor in possession credit agreement was replaced by separate letters of credit issued by Wachovia Bank National Association and that the liens and pledge of the PGE stock in favor of the debtor in possession lenders were released in August 2004. The replacement letters of credit issued by Wachovia Bank National Association are secured by cash collateral and do not involve a pledge of the stock of PGE.

Public Ownership Initiatives

Proponents of the formation of Peoples' Utility Districts (PUDs) to acquire PGE's facilities and equipment in the Company's allocated service territory obtained sufficient certified signatures on initiative petitions to place measures on election ballots in Multnomah, Yamhill, Clackamas, and Washington Counties. Formation initiatives in these counties were rejected by voters in November 2003, March 2004, May 2004, and November 2004, respectively.

Sufficient signatures were certified to place a measure on an election ballot to form a PUD in eight Portland voting precincts within Multnomah County. On July 16, 2004, the Multnomah County Circuit Court ruled that the proposed PUD violates the Oregon constitution, which does not allow a PUD to be formed from only a part of a city, and issued a permanent injunction against placing the measure on the ballot. On August 13, 2004, the Multnomah County Circuit Court denied a motion by proponents of the proposed PUD to intervene in the case. The deadline for the proponents to appeal has passed.

Public Utility Holding Company Act of 1935

As the owner of all of PGE's common stock, Enron is a holding company under PUHCA. Enron filed for exemption under Section 3(a)(1) of PUHCA. To be eligible for such exemption, it is necessary, among other things, that PGE's utility activities be predominantly intrastate in character. In December 2003, the SEC denied Enron's PUHCA exemption application under Section 3(a)(1), holding that PGE's utility activities were not predominantly and substantially intrastate in character. On March 9, 2004, Enron registered as a holding company under PUHCA. As a result, Enron and its subsidiaries are subject to PUHCA regulations.

If Oregon Electric becomes PGE's parent company, Oregon Electric will attempt to qualify for an exemption under Section 3(a)(1) of PUHCA. In order to qualify, PGE is proposing to restructure certain of its wholesale energy procurement activities. The restructuring involves the creation of a wholly-owned subsidiary of PGE that will separately engage in wholesale term trading on behalf of PGE, solely for PGE's regulated, retail electric service. Because a substantial amount of PGE's wholesale sales occur in the forward term markets, the intention of transferring this activity to a subsidiary is to allow PGE's wholesale energy activities to qualify as predominantly intrastate in character. The proposed restructuring has been presented and is being addressed by the OPUC, the FERC, and the SEC, although there can be no assurance that the regulatory approvals required for the proposed restructuring will be obtained. Qualifying for an exemption would reduce the level of required compliance with P UHCA regulations.

Retail Rate Changes

Resource Valuation Mechanism

A general rate order issued by the OPUC in 2001 approved a new Resource Valuation Mechanism (RVM) tariff that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines for Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, the RVM utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. It provides for an adjustment, filed annually in April and finalized in mid-November, which is effective January 1 of the following year.

Power Cost Price Decrease - 2003 PGE's first annual revision of its power supply costs under the RVM tariff forecasted a reduction in the cost of power from that included in the Company's 2001 general rate case. Accordingly, the OPUC authorized an approximate 7% average reduction in the Company's retail prices, effective January 1, 2003. Price decreases ranged from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers were affected more by wholesale energy market prices, which decreased in the 2003 forecast. The smaller decrease in residential rates reflected both PGE's cost of generation as well as the higher cost of electricity from BPA, which increased its rates in October 2002. These price decreases reduced PGE's 2003 revenues by approximately $90 million.

Power Cost Price Increase - 2004 In August 2003, PGE, OPUC staff, and intervenors entered into a stipulation, approved by the Commission, related to the Company's forecast of 2004 net variable power costs. Forecast adjustments were made to the price of certain wholesale power purchase contracts, reflecting recent electricity forward prices and certain other modifications and adjustments to estimated variable power and fuel costs. The 2004 RVM was finalized in November 2003, with new rates effective January 1, 2004. The average price for all customers increased by approximately 0.4%. Price adjustments ranged from a 2.3% decrease for industrial customers to increases of 2.8% and 1.9% for small commercial and residential customers, respectively. Price adjustments varied between customer classes primarily because of different collection periods for PGE's 2001-2002 power cost adjustment mechanism (see "Power Cost Adjustment Mechanisms" in this section for further information). Based upon projected energy sales, it is estimated that the price adjustments will increase PGE's 2004 revenues by approximately $4 million. The stipulation also provided that PGE withdraw a proposed power cost adjustment mechanism for 2004 and participate in a process to address the need for, and structure of, a cost recovery mechanism for variances in power costs from forecasted levels. Although PGE engaged in the process, no definitive outcome was reached. The Company is currently focusing its attention on the effect of hydro variations on power costs, as described below.

Preliminary Power Cost Filing - 2005 In April 2004, PGE submitted an RVM filing with the OPUC containing a preliminary estimate of 2005 variable power costs. In an updated filing made on November 3, 2004, PGE estimated its total 2005 variable power costs at $492 million, or $42 million higher than the forecast of 2004 power costs. Based upon this filing, average prices for residential customers are estimated to increase by less than 1%, with rates for small non-residential customers estimated to decrease by less than 1%. Rates for large non-residential customers are estimated to increase by approximately 5%. Final adjustments to individual rate schedules will be determined later in November, with new rates to become effective on January 1, 2005.

Power Cost Adjustment Mechanisms - 2001 and 2002

In order to protect both PGE and its customers from price volatility in the wholesale power and natural gas markets, the OPUC authorized the Company to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts approved by the Commission. Under the initial power cost adjustment 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 OPUC approval to recover the approximate $91 million balance (including interest) over a 3 1/2-year period (April 2002 - September 2005). At September 30, 2004, the remaining balance to be collected was approximately $27 million.

In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred approximately $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount is being collected over a two-year period (January 2003 - December 2004), with recovery from large industrial customers completed during 2003. As a result of a stipulation reached with the OPUC staff and an intervenor related to a prudence review, the deferred amount was reduced by $1 million in the first quarter of 2004 and reflected in earnings. At September 30, 2004, the remaining balance to be collected was approximately $1 million.

PGE did not have a power cost adjustment mechanism in place for 2003 and has none in place for 2004.

Hydro Replacement Power Costs - 2004

In July 2004, PGE withdrew from OPUC consideration its two hydro cost deferral applications, filed in December 2003 and May 2004, and requested Commission consideration of a Hydro Generation Adjustment mechanism that would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions. A procedural schedule has been adopted for further consideration of the mechanism by the Commission, with testimony, settlement conferences, and hearings currently scheduled from November 2004 through March 2005. Any deferral of costs, for future recovery or refund, would begin only upon approval of the proposed tariff. A decision by the OPUC is currently expected in the first half of 2005.

Integrated Resource Plan

PGE filed an Integrated Resource Plan (IRP) with the OPUC in 2002, with a supplement filed in February 2003. The IRP describes the Company's strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. It details resource actions over the next two to three years that provide for reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. The IRP also addresses future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, longer-term power purchases, the use of seasonal exchanges to meet peaking requirements, demand-side management, and capacity tolling contracts.

In June 2003, following approval by the OPUC, PGE issued a request for proposals (RFP) to prospective suppliers (including power generators, wholesalers, and developers) to acquire resources to meet the electricity needs of its customers. In January 2004, PGE filed a Proposed Action Plan with the Commission on how to best meet its customers' future power supply requirements, beginning as early as 2006, and in March 2004, PGE filed its Final Action Plan to update and refine its recommendations. These recommendations included the acquisition of approximately 790 average MW in short-term, mid-term, and long-term resources, consisting of six components: 1) construction of a natural gas-fired power plant at PGE's Port Westward site in Columbia County, Oregon, producing 350 average MW, beginning in mid-2007; 2) acquisition of 65 average MW (195 MW capacity) of wind generation from RFP proposals; 3) acquisition of 135 average MW in fixed price power purchase agreements with durations of 5 to 10 y ears from RFP proposals; 4) acquisition of 55 average MW in energy efficiency savings by the Energy Trust of Oregon; 5) upgrades and contract extensions to existing plants of 60 average MW; and, 6) short-term market acquisitions of 125 average MW. In addition to the increased capacity, the recommendations include approximately 955 MW of additional capacity from the extension of a current contract with the Confederated Tribes to 2012, new dispatchable standby generation, duct firing from Port Westward, and peak tolling agreements.

PGE's initial acquisitions under the RFP process include a ten-year power purchase agreement for 85 average MW, beginning in late 2006 and two five-year agreements, consisting of a power purchase option for 14 average MW, beginning in January 2005, and a power purchase agreement for 25 average MW, beginning in late 2006. In October 2004, the Company entered into capacity agreements totaling 400 MW, extending from early 2005 to 2011.

In a July 20, 2004 order, the OPUC acknowledged PGE's Integrated Resource Final Action Plan, including the construction or acquisition of a 350 average MW high efficiency gas-fired resource. The order includes requirements that PGE address constraints on competitive renewable development in the region, develop transmission capacity that provides for access to additional wind (and other) resources at a reasonable price, and demonstrate that the Company has taken measures to acquire, option, or retain cost effective transmission capacity before issuing it's next RFP. In a separate order, also issued on July 20, 2004, the OPUC waived certain Oregon administrative rules to allow cost-based treatment of capital, operation and maintenance costs of Port Westward.

Port Westward Project

On September 3, 2004, PGE entered into agreements with the general contractor and turbine manufacturer for construction of Port Westward. Groundbreaking took place on October 7th, with full construction scheduled to begin in January 2005. Port Westward is scheduled to be operational by mid-2007 and cost approximately $250 million to $270 million, excluding Allowance for Funds Used During Construction.

Hydro Relicensing

A Settlement Agreement was signed on July 13, 2004 by all parties to the Pelton Round Butte relicensing proceeding. The Settlement Agreement resolves all issues raised by the 2001 joint application that was submitted to the FERC by PGE and the Confederated Tribes of the Warm Springs Reservation of Oregon, the project's co-owners. It includes a recommendation that the FERC issue a 50-year license for the project and also includes provisions for fish passage over the project's dams. The Agreement was submitted to the FERC on July 30, 2004, with approval expected by mid-2005.

Mid-Columbia Hydro Matters

Receivables and Refunds on Wholesale Transactions

Receivables - California Wholesale Market

Refunds on Wholesale Transactions

California - In a June 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order that denied further requests for rehearing of the October 16, 2003 order. On the same day, the FERC issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liabi lity. On September 24, 2004, the FERC issued an order that denied requests for rehearing of its May 12, 2004 fuel cost order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Under the new allocation methodology, PGE could be required to pay additional amounts in hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect that this order will materially increase the Company's potential refund exposure.

Challenge of the California Attorney General to Market Based Rates - On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates during the period October 2, 2000 - June 4, 2002 should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of App eals. On September 8, 2004, the Court issued an opinion upholding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. PGE cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

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. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders.

Trojan Investment Recovery

In 1993, following the closure of Trojan, 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 (1995 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 were subsequently filed in the Marion County Circuit Court, the Oregon Court of Appeals, and 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 Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

In 2000, while the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into settlement agreements with respect to litigation over recovery of, and return on, the Trojan investment. The settlement agreements, approved by the OPUC in September 2000, 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 URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of URP's challenges and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 order to the Marion County Circuit Court and on November 7, 2003, the Court issued an opinion remanding the case to the OPUC for action to redu ce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appealed to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Plaintiff's claims. Hearings on both the motion for Summary Judgment and class certification are pending.

Management cannot predict the ultimate outcome of these challenges. However, it believes that the resolution 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.

Environmental Matters

Harborton

A 1997 EPA investigation of a 5.5-mile segment of the Willamette River known as the Portland Harbor 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).

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (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.

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 March 2001, in accordance with the Voluntary Agreement, PGE submitted a final investigation plan to the DEQ for approval. DEQ approved the plan and in June 2001 PGE performed initial investigations and remedial activities based upon the approved 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 its final investigative report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the final investigative report to the EPA and in a May 18, 2004 letter, the EPA stated that "Based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river." Management believes that the Company's contribution to t he sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

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.

Other

In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site. Management cannot predict the ultimate outcome of this matter. However, PGE believes this matter will not have a material adverse impact on its financial statements.

Colstrip Plant

In December 2003, PPL Montana, LLC (PPL Montana), the operator of the Colstrip coal-fired generating plants, received an Administrative Compliance Order (ACO) from the EPA pursuant to the Clean Air Act (Act). The EPA alleges that since 1980, Colstrip Units 3 and 4, in which PGE has a 20% ownership interest, have been in violation of the clean air permit issued under the Act. The permit required Colstrip Units 3 and 4 to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if and when EPA promulgated certain requirements for nitrogen oxides. The EPA is asserting that regulations it promulgated in 1980 triggered the requirement. The EPA does not expressly seek penalties nor indicate what, if any, additional control technology requirements that it may require to be considered. PPL Montana, which has reported that it believes that the ACO is unfounded, is discussing the matter with the EPA.

In addition to the ACO, the EPA regional office that regulates plants in Montana has issued an information request with respect to the Colstrip plants. The regional office is investigating whether older coal-fired plants have been modified over the years in a manner that would subject them to more stringent requirements under the Act. PPL Montana is in the process of responding to the information request.

A local Native American tribe has asserted that sulfur dioxide emissions from Colstrip 3 & 4 units are affecting local tribal areas more than previously estimated. PPL Montana is working with the Montana Department of Environmental Quality to provide additional information to address this issue.

PPL Montana and EPA are discussing possible emission control and monitoring requirements involving all Colstrip units to address the issues discussed above. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed into law the American Jobs Creation Act of 2004 (Act) in response to a trade dispute with the European Union regarding extraterritorial income tax provisions in the federal tax code that the World Trade Organization had ruled to be illegal. For companies that pay federal income taxes on manufacturing activities in the United States, the Act provides a deduction from taxable income equal to a stipulated percentage of qualified income from domestic production activities (qualified production income or "QPI"). The deduction, which cannot exceed fifty percent of annual wages paid, is phased in as follows: three percent of QPI in 2005-2006, six percent in 2007-2009, and nine percent in 2010 and thereafter. Eligible activity, as defined in the Act, includes oil and gas extraction and electricity and water production (excluding transmission and distribution).

Under existing tax accounting standards, it is unclear whether the deduction for domestic production activities should be accounted for as a tax rate reduction or as a special deduction. Until this is clarified by the U.S. Department of the Treasury and the FASB, PGE continues to evaluate the potential impacts of the change in tax law.

Information 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;

events related to Enron's proposed sale of PGE to Oregon Electric;

effects of electric industry restructuring in Oregon and in the United States, including retail and 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 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 currency exchange rates, interest rates, and credit risk. These changes may affect the Company's future financial results, as discussed below.

Commodity Price Risk

PGE's primary business is to provide electricity to its retail customers. The Company uses both long- and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to fluctuations in the 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 risks are recognized when settled in Purchased Power and Fuel expense, or in wholesale revenue. In addition, Company 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. Under EITF 02-3, gains and losses on such instruments are recognized on a net basis within 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 of money, and volatility factors underlying the commitments.

PGE actively manages its risk to ensure compliance with its risk management policies. The Company 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 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 nine months of 2004 were $0.1 million, $0.2 million, and zero, respectively, and in the first nine months of 2003 were $0. 2 million, $0.5 million, and zero, respectively. The average, high, and low value at risk on the non-trading portfolio in the first nine months of 2004 were $1.2 million, $2.3 million, and $0.6 million, respectively, and in the first nine months of 2003 were $1.9 million, $2.6 million, and $1.2 million, respectively. In 2004 and 2003, PGE did not reduce its non-trading value at risk by the amount of potential deferrals.

Foreign Currency Exchange Rate Risk

PGE faces exposure 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 with an appropriate hedging strategy. Beginning in 2003, PGE implemented a strategy that utilizes forward contracts to acquire Canadian dollars in order to mitigate its currency exposure.

At September 30, 2004, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 12 months. 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

Although PGE has no short-term debt outstanding at September 30, 2004, the Company is typically exposed to risk resulting from changes in interest rates on variable rate short-term borrowings. The Company has also had exposure to interest rate changes on variable rate commercial paper. Although 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. The Company also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under the agreements associated with a counterparty. Despite such mitigation efforts, defaults by counterparties may periodically occur. Valuation allowances are provided for credit risk.

Credit risk with respect to trade accounts receivable from retail electricity sales is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, significantly reduces credit risk. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for credit risk. At September 30, 2004, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following tables present PGE's credit exposure for commodity non-trading and trading activities and their subsequent maturity as of September 30, 2004. The tables reflect credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

Non-Trading Activities

(Dollars in millions)				Maturity of Credit Risk Exposure
Rating	Credit Risk Before Collateral	Percentage of Total Exposure	Credit Collateral	2004	2005	2006	2007	2008	After 2008
Investment Grade	$ 114	94%	$ 12	$ 18	$ 49	$ 16	$ 5	$ 3	$ 23
Non-Investment Grade	6	5%	6	1	3	2	-	-	-
Internally Rated - Investment Grade	1	1%	-	1	-	-	-	-	-
Total	$ 121	100%	$ 18	$ 20	$ 52	$ 18	$ 5	$ 3	$ 23

Trading Activities

(Dollars in millions)				Maturity of Credit Risk Exposure
Rating	Credit Risk Before Collateral	Percentage of Total Exposure	Credit Collateral	2004	2005	2006	2007	2008	After 2008
Investment Grade	$ 2	50%	$ -	$ 1	$ 1	$ -	$ -	$ -	$ -
Non-Investment Grade	2	50%	-	2	-	-	-	-	-
Total	$ 4	100%	$ -	$ 3	$ 1	$ -	$ -	$ -	$ -

Investment Grade includes those counterparties with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody's) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. Non-Investment Grade includes those counterparties with below investment grade credit ratings on senior unsecured debt. For non-rated counterparties, PGE performs credit analysis to determine an internal credit rating that approximates investment or non-investment grade. Included in this analysis is a review of counterparty financial statements, specific business environment, access to capital, and indicators from debt and capital markets. The credit exposure includes activity for electricity and natural gas forward, swap and option contracts. Posted collateral may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance.

Omitted from the non-trading market risk exposures above are long-term power purchase contracts with certain public utility districts in the State of Washington and with the City of Portland, Oregon. These contracts provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2018. Management believes that circumstances that could result in the nonperformance by these counterparties are remote.

Risk Management Committee

PGE has a Risk Management Committee (RMC), responsible for the oversight of commodity position and price risk, foreign currency risk and credit risk related to the Company's energy portfolio management activities. The RMC consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The RMC approves policies and procedures, establishes limits subject to Enron approval, and monitors compliance and risk exposure on a regular basis through reports and meetings. The RMC reports quarterly to the Audit Committee of the PGE Board of Directors.

For further information on price risk management activities, see Note 3, Price Risk Management, in the Notes to Consolidated Financial Statements.

Item 4. Controls and Procedures

Disclosure Controls and Procedures. Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company's disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, the information relating to the Company (including its consolidated subsidiaries) required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II

Other Information

Item 1. Legal Proceedings

For further information regarding the following proceedings, see PGE's 2003 Annual Report on Form 10-K and other reports filed with the SEC since its 2003 Form 10-K was filed.

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.

Portland General Electric Company v. Hardy Meyers, In His Official Capacity as Attorney General of the State of Oregon, United States District Court for the District of Oregon, Case No. 03-1641-HA, and State of Oregon, ex rel Hardy Meyers, Attorney General for the State of Oregon v. Portland General Electric Company, Multnomah County Oregon Circuit Court, Case No. 0312-13473

On November 26, 2003, PGE filed a complaint for Declaratory Relief in U.S. District Court for the District of Oregon seeking to end the Oregon Attorney General's investigation into the Company's participation in wholesale power trading markets related to the California energy crisis of 2000-2001 (PGE Case).

On December 16, 2003, the Oregon Attorney General filed in the Multnomah County Oregon Circuit Court a Motion for Order to Show Cause why the Company should not comply with the Oregon Attorney General's investigation (Attorney General Case).

PGE removed the Attorney General Case to the U.S. District Court for the District of Oregon, and the same U.S. District Court Judge was assigned to both cases.

On July 30, 2004 the U.S. District Court Judge dismissed the PGE Case without prejudice on the basis that the case is not ripe for review, and remanded the Attorney General Case to the Multnomah County Oregon Circuit Court on the basis that the state investigation is not a civil case over which the U.S. District Court has jurisdiction.

On August 18, 2004, PGE appealed the ruling on the PGE Case to the United States Ninth Circuit Court of Appeals.

On September 3, 2004, the Multnomah County Oregon Circuit Court ruled in favor of the Attorney General, but, on September 13, 2004, granted PGE's motion to stay enforcement of the decision for 90 days. On September 10, 2004, PGE appealed the Multnomah County Court decision in favor of the Attorney General to the Oregon Court of Appeals. On September 30, 2004, PGE filed a motion with the Oregon Court of Appeals for an expedited appeal and an extension of the stay. On October 19, 2004 the Oregon Court of Appeals granted PGE's motions.

Item 5. Other Information

New Audit Committee Member

Effective October 8, 2004, John W. Ballantine, a Director of PGE, was appointed to the Audit Committee of PGE's Board of Directors, replacing Raymond M. Bowen, Jr., who resigned from PGE's Board on October 1, 2004.

Item 6. Exhibits

(3) Articles of Incorporation and Bylaws

3.1 * Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit (4) to Registration Statement No. 2-78085).

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

3.3 * Articles of Amendment to the Articles of Incorporation of Portland General Electric Company, dated July 8, 1992, for series of Preferred Stock ($7.75 Series) (incorporated by reference to Exhibit (4)(a) to Registration Statement No. 33-46357).

3.4 * Articles of Amendment to the Articles of Incorporation of Portland General Electric Company, dated September 30, 2002, creating Limited Voting Junior Preferred Stock (incorporated by reference to Exhibit (3) to Form 10-Q for the quarterly period ended September 30, 2002).

3.5 * Amended and Restated Bylaws of Portland General Electric Company as amended on February 1, 2004 (incorporated by reference to Exhibit (3) to Form 10-K for the fiscal year ended December 31, 2003).

(4) Instruments defining the rights of security holders, including indentures

Certain instruments defining the rights of holders of other long-term debt of PGE are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount authorized under each such omitted instrument does not exceed 10 percent of the total assets of PGE and its subsidiaries on a consolidated basis. PGE hereby agrees to furnish a copy of any such instrument to the SEC upon request.

(31) Rule 13a-14(a)/15d-14(a) Certifications

31.1 Certification of Chief Executive Officer of Portland General Electric Company pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 (filed herewith).

31.2 Certification of Chief Financial Officer of Portland General Electric Company pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 (filed herewith).

(32) Section 1350 Certifications

Certifications of Chief Executive Officer and 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 (furnished herewith).

* 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 thereunto duly authorized.

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

Date:

November 5, 2004

By:

/s/ James J. Piro

James J. Piro

Executive Vice President, Finance

Chief Financial Officer and Treasurer

Date:

November 5, 2004

By:

/s/ Kirk M. Stevens

Kirk M. Stevens

Controller and Assistant Treasurer

PORTLAND GENERAL ELECTRIC COMPANY EXHIBIT 31.1 EXHIBIT 31.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, Peggy Y. Fowler, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

Based on my knowledge, this 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 report;

Based on my knowledge, the financial statements, and other financial information included in this 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 report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 5, 2004		/s/ Peggy Y. Fowler
		Peggy Y. Fowler
		Chief Executive Officer and President

PORTLAND GENERAL ELECTRIC COMPANY EXHIBIT 31.2 EXHIBIT 31.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, James J. Piro, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 5, 2004		/s/ James J. Piro
		James J. Piro
		Executive Vice President, Finance Chief Financial Officer and Treasurer

PORTLAND GENERAL ELECTRIC COMPANY EXHIBIT 32 EXHIBIT 32

CERTIFICATIONS OF

CHIEF EXECUTIVE OFFICER AND 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

We, Peggy Y. Fowler, Chief Executive Officer and President, and James J. Piro, Chief Financial Officer, of Portland General Electric Company (the "Company"), hereby certify that the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2004, as 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"), fully complies with the requirements of that section.

We further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Peggy Y. Fowler		/s/ James J. Piro
Peggy Y. Fowler		James J. Piro


Date:	November 5, 2004	Date:	November 5, 2004