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, 2005
	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 Exchange Act). Yes          No    X    

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes          No    X    

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of October 31, 2005: 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	33
	Item 3.  Quantitative and Qualitative Disclosures
	About Market Risk	67
	Item 4. Controls and Procedures	70
PART II. Other Information
	Item 1. Legal Proceedings	71
	Item 6. Exhibits	73
	Signatures	74

Definitions

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 reorganized debtor pursuant to its Supplemental Modified Fifth Amended Joint Plan of Affiliated Debtors Pursuant to Chapter 11 of the Bankruptcy Code, confirmed by the United States Bankruptcy Court For The Southern District of New York (Case No. 01-16034) on July 15, 2004 and effective November 17, 2004
EPA	Environmental Protection Agency
ERISA	Employee Retirement Income Security Act of 1974, as amended
ESS	Electricity Service Supplier
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Financial Statements	Consolidated Financial Statements of Portland General Electric Company included in Part I, Item 1 of this report
IRS	Internal Revenue Service
kWh	Kilowatt-Hour
Mill	One tenth of one cent
MW	Megawatt
MWa	Average megawatts
MWh	Megawatt-hour
NRC	Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange
OPUC or the Commission	Public Utility Commission of Oregon
PBGC	Pension Benefit Guaranty Corporation
PGC	Portland General Corporation
PGE or the Company	Portland General Electric Company
Port Westward	Port Westward Generating Plant
PRP	Potentially Responsible Party
PUHCA 1935	Public Utility Holding Company Act of 1935
PUHCA 2005	Public Utility Holding Company Act of 2005
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board
Trojan	Trojan Nuclear Plant
URP	Utility Reform Project

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,
		2005			2004			2005				2004
		(In Millions)
Operating Revenues		$	355		$	348		$			1,059	$		1,075
Operating Expenses
	Purchased power and fuel		166			180			439					491
	Production and distribution		30			31			92					96
	Administrative and other		42			35			127					105
	Depreciation and amortization		57			58			175					174
	Taxes other than income taxes		18			18			56					55
	Income taxes		6			6			49					48
			319			328			938					969
Net Operating Income			36			20			121					106
Other Income (Deductions)
	Miscellaneous		(2)			2			1					5
	Income taxes		2			5			3					6
			-			7			4					11
Interest Charges
	Interest on long-term debt and other		17			17			52					53
Net Income		$	19		$	10	$		73			$		64
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,
		2005		2004			2005						2004
		(In Millions)
Balance at Beginning of Period		$	691		$	599	$		637			$		545
Net Income			19			10					73			64
			710			609					710			609
Dividends Declared - Common stock		150			-		150					-
Balance at End of Period		$	560		$	609	$			560		$		609
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,
				2005			2004					2005					2004
				(In Millions)
Accumulated other comprehensive income (loss) - Beginning of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$	1		$		6			$			(2)			$		2
	Minimum pension liability adjustment				(4)			(4)						(4)						(4)
	Total			$	(3)		$	2			$			(6)		$				(2)
Net Income				$	19		$	10			$				73	$				64
Other comprehensive income, net of tax:
	Unrealized gains on derivatives classified as cash flow hedges:
		Other unrealized holding net gains arising during the
		period, net of related taxes of $(47) and $(3) for the three
		months ended September 30, 2005 and 2004 and $(72) and $(10) for the nine months ended September 30, 2005 and 2004		71			3				109					15
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $3 and $2 for the three months ended September 30, 2005 and September 30, 2004 and $11 and $4 for the nine months ended September 30, 2005 and 2004		(5)			(2)				(17)					(6)
		Reclassification adjustment in net income due to discontinuance
		of cash flow hedges, net of related taxes of $1		-			-				(1)					-
		Reclassification of unrealized gains to SFAS No. 71
		regulatory liability, net of related taxes of $39 and $3
		for the three months ended September 30, 2005 and 2004 and $54 and $6 for the nine months ended September 30, 2005 and 2004		(60)			(5)				(82)					(9)
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		6			(4)				9					-
	Minimum pension liability adjustment			1			-				1					-
		Total Other comprehensive income (loss)		7			(4)				10					-
Comprehensive income				$	26		$			6	$				83	$			64
Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain on derivatives classified as cash flow hedges			$	7		$			2	$				7		$			2
	Minimum pension liability adjustment			(3)			(4)				(3)					(4)
Total				$		4	$			(2)	$				4	$			(2)
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,
					2005		2004
				(In millions, except per share amounts)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $165 and $114)				$	4,167		$	3,992
	Accumulated depreciation				(1,774)			(1,717)
					2,393			2,275
Other Property and Investments
	Nuclear decommissioning trust, at market value				27			22
	Non-qualified benefit plan trust				70			64
	Miscellaneous				33			30
					130			116
Current Assets
	Cash and cash equivalents				225			204
	Accounts and notes receivable (less allowance for uncollectible accounts
		of $51 and $50)			204			170
	Unbilled revenues				51			80
	Assets from price risk management activities				449			77
	Inventories, at average cost				49			48
	Prepayments and other				116			113
					1,094			692
Deferred Charges
	Regulatory assets				238			295
	Miscellaneous				23			25
					261			320
					$	3,878		$	3,403
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		482			481
	Retained earnings				560			637
	Accumulated other comprehensive income (loss):
			Unrealized gain (loss) on derivatives classified as cash flow hedges		7			(2)
			Minimum pension liability adjustment		(3)			(4)
	Limited voting junior preferred stock				-			-
	Long-term obligations				881			892
					2,087			2,164
Commitments and Contingencies (see Notes)
Current Liabilities
	Long-term debt due within one year				12			30
	Accounts payable and other accruals				203			182
	Liabilities from price risk management activities				182			38
	Customer deposits				150			18
	Accrued interest				14			19
	Accrued taxes				45			37
	Deferred income taxes				106			15
					712			339
Other
	Deferred income taxes				205			308
	Deferred investment tax credits				11			13
	Trojan asset retirement obligation				106			96
	Accumulated asset retirement obligation				17			16
	Regulatory liabilities:
			Accumulated asset retirement removal costs		340			286
			Other		279			74
	Non-qualified benefit plan liabilities				79			70
	Miscellaneous				42			37
					1,079			900
					$	3,878		$	3,403
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,
			2005		2004
			(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
	Net income		$	73	$	64
	Non-cash items included in net income:
		Depreciation and amortization	175		174
		Deferred income taxes	(15)		(6)
		Net assets from price risk management activities	(76)		(24)
		Power cost adjustment	13		30
		Other non-cash income and expenses (net)	62		22
	Changes in working capital:
		Net deposit activity	132		15
		(Increase) Decrease in receivables	(1)		38
		Increase (Decrease) in payables	5		(17)
		Other working capital items - net	15		(22)
	Other - net		19		10
Net Cash Provided by Operating Activities			402		284
Cash Flows From Investing Activities:
	Capital expenditures		(188)		(138)
	Other - net		(14)		4
Net Cash Used in Investing Activities			(202)		(134)
Cash Flows From Financing Activities:
	Repayment of long-term debt		(29)		(60)
	Dividends paid		(150)		-
Net Cash Used in Financing Activities			(179)		(60)
Increase in Cash and Cash Equivalents			21		90
Cash and Cash Equivalents, Beginning of Period			204		109
Cash and Cash Equivalents, End of Period			$	225	$	199
Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	45	$	50
		Income taxes	88		66
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 interim reporting requirements of the Securities and Exchange Commission (SEC), 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. Interim financial results do not necessarily represent those to be expected for the year. It is management's opinion that, when the interim statements are read in conjunction with the Company's 2004 Annual Report on Form 10-K and the other reports filed with the SEC since its 2004 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.

On August 2, 2005, PGE transferred $2.7 million in pension assets from PGE's Pension Plan to Enron Corp.'s Cash Balance Plan to reflect a net exchange of assets and benefit obligations. These exchanges consolidated benefits for certain individuals who had changed employers and as a result had ceased earning benefits under one plan and began earning benefits under the other plan.

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

PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" in the table). The health insurance plan (a defined dollar medical benefit plan) includes an established maximum PGE contribution for each covered employee. Costs of the post-retirement health and life insurance plans, based upon actuarial studies, are included in rates charged to customers and are funded by PGE contributions to a Voluntary Employees' Beneficiary Association (VEBA) trust. In 2004, PGE established Health Retirement Accounts (HRAs) for its employees under which the Company will make contributions to a trust to provide for claims by retirees for qualified medical costs. PGE made a contribution of $1 million to an HRA trust in 2005 and continues to evaluate the need to make contributions to any of the other above described plans this year.

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
	2005		2004		2005		2004		2005		2004
Components of net periodic benefit cost:
Service cost	$	3	$	3	$	-	$	-	$	1	$	-
Interest cost on benefit obligation	6		6		1		-		1		-
Expected return on plan assets	(10)		(10)		(1)		(1)		(1)		(1)
Amortization of transition asset	-		-		-		-		-		-
Amortization of prior service cost	1		-		-		1		1		1
Recognized (gain) loss		-		-		-		-		1		-
Net periodic benefit cost (income)	$	-	$	(1)	$	-	$	-	$	3	$	-
Nine Months Ended September 30:	Defined Benefit				Non-Qualified
	Pension Plan				Benefit Plans				Other Benefits
	2005		2004		2005		2004		2005		2004
Components of net periodic benefit cost:
Service cost	$	9	$	9	$	-	$	-	$	1	$	-
Interest cost on benefit obligation	20		18		2		1		3		2
Expected return on plan assets	(30)		(30)		(1)		(1)		(1)		(1)
Amortization of transition asset	-		(1)		-		-		-		-
Amortization of prior service cost	1		1		-		1		1		1
Recognized (gain) loss		-		-		-		-		1		-
Net periodic benefit cost (income)	$	-	$	(3)	$	1	$	1	$	5	$	2

Note 3 - Price Risk Management

PGE utilizes derivative instruments, including electricity forward, swap, and option contracts and natural gas forward, swap, option, and futures contracts in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and to minimize net power costs for service to its retail customers. Under Statement of Financial Accounting Standards (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.

Changes in the fair value of retail (non-trading) derivative instruments prior to settlement that do not qualify for either the normal purchase and normal sale exception or for hedge accounting are recorded on a net basis in Purchased Power and Fuel expense. As derivative instruments are settled, sales are recorded in Operating Revenues, with purchases, natural gas swaps and futures recorded in Purchased Power and Fuel expense. PGE records the non-physical settlement of non-trading electricity derivative activities on a net basis in Purchased Power and Fuel expense, in accordance with Emerging Issues Task Force Issue (EITF) No. 03-11, Reporting Realized 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'.

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.

PGE discontinued its electricity and natural gas trading (non-retail) activities in early 2005. Until the settlement of all derivative instruments related to such activities, PGE reports all unrealized and realized gains on a net basis, as required by EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, with such activities recorded as a component of Operating Revenues.

Non-Trading Activities

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 activities include power purchases and sales resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. Most of PGE's non-trading wholesale sales have been to utilities and power marketers and have been predominantly short-term. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions are 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 Public Utility Commission of Oregon (OPUC) are based on a valuation of all the Company's energy resources, including derivative instruments existing on October 28, 2004 that would settle during the 12-month period from January 1, 2005 to December 31, 2005. Such valuation was based on forward price curves in effect on November 11, 2004 for electricity and natural gas. The timing difference between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery 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 2005, unrealized gains and losses related to new derivatives not included in rates that will settle in 2005, and changes in fair value of derivatives used to set rates, are not deferred as regulatory assets or regulatory liabilities.

The following table indicates unrealized gains and losses recorded in earnings for the three- and nine-month periods ended September 30, 2005 and 2004 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Non-Trading Activities
Net unrealized gains	$	66	$	3	$	77	$	23
SFAS No. 71 regulatory (liability) asset		(59)		(8)		(58)		(27)
Net unrealized gains (losses)	$	7	$	(5)	$	19	$	(4)

The following table indicates derivative activities from cash flow hedges recorded in OCI for the three- and nine-month periods ended September 30, 2005 and 2004 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Derivative Activities Recorded in OCI
Other unrealized holding net gains arising during the period	$	118	$	6	$	181	$	25
Reclassification adjustment for contract settlements included in net income		(8)		(4)		(28)		(10)
Reclassification adjustment in net income due to discontinuance of cash flow hedges (*)		-		-		(2)		-
Reclassification of unrealized gains to SFAS No. 71 regulatory liability		(99)		(8)		(136)		(15)
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges	$	11	$	(6)	$	15	$	-

(*) Due to the probability that the original forecasted transactions will not occur.

Hedge ineffectiveness from cash flow hedges was not material in the first nine months of 2005 and 2004. As of September 30, 2005, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 72 months. The Company estimates that of the $166 million of net unrealized gains in OCI at September 30, 2005, $127 million will be reclassified into earnings within the next twelve months (partially offset by a $113 million SFAS No. 71 regulatory liability), and $39 million will be reclassified over the remaining 60 months (fully offset by a SFAS No. 71 regulatory liability).

Trading Activities

Prior to 2005, PGE utilized forward, swap, option, and futures contracts to participate in electricity and natural gas markets for non-retail purposes. In early 2005, PGE discontinued its trading activities for non-retail purposes; however, existing trading transactions will continue to settle through December 31, 2005. 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 natural gas trading activities and transaction volumes for electricity trading contracts that settled in the three-and nine-month periods ended September 30, 2005 and 2004:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Trading Activities (In Millions)
Unrealized Gain (Loss)	$	-	$	2	$	(1)	$	1
Realized Gain (Loss)		-		(2)		1		-
Net Gain (Loss) in Operating Revenues	$	-	$	-	$	-	$	1
Electricity Trading - MWhs (thousands)
Sales	123		3,098		697		8,660
Purchases	123		3,098		697		8,660

Note 4 - Legal and Environmental Matters

Legal Matters

Trojan Investment Recovery - In 1993, following the closure of the Trojan Nuclear Plant, 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 Citizens' Utility Board (CUB) and the Utility Reform Project (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 opinion 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 the 1997 merger of Portland General Corporation (PGC) 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 that began in October 2000. At September 30, 2005, the remaining balance to be collected was approximately $3 million. 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 Trojan decommissioning costs is unaffected by the settlement agreements or the OPUC orders.

The URP filed a complaint with the OPUC challenging the settlement agreements and the Commission'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, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, 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. On December 14, 2004, the Judge granted the Plaintiff's motion for Class Certification and Partial Summary Judgment and denied PGE's motion for Summary Judgment. PGE filed a proposed order certifying the issue for an interlocutory appeal. An order rejecting the proposed order was entered on February 1, 2005. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed and seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions and oral arguments were subsequently held. A decision is 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.

On August 31, 2004, the administrative law judge issued an Order (Scoping 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 Scoping Order. On December 20, 2004, the URP and Class Action Plaintiffs filed an application with the OPUC for reconsideration of the Scoping Order. On February 11, 2005, the OPUC denied reconsideration. On April 18, 2005, URP and Linda K. Williams filed a complaint against the OPUC in Marion County Circuit Court challenging the OPUC's affirmation of the Scoping Order. The OPUC filed a motion to dismiss the complaint, and on September 21, 2005, the Marion County Circuit Court granted the OPUC's motion. Hearings in the first phase of the OPUC proceeding have been held, with a decision expected in early 2006.

On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs) stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, the Company's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million. No action has been filed to date.

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. No reserves have been established by PGE for any amounts related to this issue.

Multnomah County Business Income Taxes - In January 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MCBIT) after 1996. The plaintiffs allege that during the period 1997 through the third quarter 2004, PGE collected in excess of $6 million from its customers for MCBIT that was never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As a member of Enron's consolidated income tax return, PGE paid the tax it collected to Enron. The plaintiffs seek a judgment against PGE for restitution of MCBIT collected from customers. Plaintiffs also seek interest, recoverable costs, and reasonable attorney fees. The plaintiffs filed an amended complaint on February 25, 2005, adding claims for fraud, unjust enrichment, conversion, statutory violations, and seeking punitive damages. On February 24, 2005, PGE requested a declaratory ruling from the OPUC as to whether the OPUC rules authorized PGE collections of the MCBIT and, if not, whether refunds are controlled by the OPUC three-year limitation for billing adjustments. On May 23, 2005, the Circuit Court granted PGE's March 24, 2005 motion for a stay for all purposes until October 15, 2005, with the opportunity to renew if the OPUC had not issued its declaratory ruling by that date. On October 5, 2005, the OPUC issued an order in the declaratory ruling docket. The OPUC determined that the rules in question required only that PGE allocate this tax to Multnomah County customers and did not require that PGE calculate it in any particular way. Because the OPUC did not find that PGE had violated its rule, the OPUC did not answer whether its three-year limitation on billing adjustments applied. Proceedings will continue in Multnomah County Circuit Court. PGE has notified the Court of the Company's intent to voluntarily refund MCBIT (plus interest) to customers and has filed motions requesting the Court's guidance regarding the number of years for which refunds should be made. Based on management's assessment of these matters, PGE established a reserve in September 2005 and believes that any additional loss will not have a material adverse impact on the Company's financial statements.

Union Grievances - In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers Local 125 (IBEW), 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 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 to the Oregon Court of Appeals. A decision is pending. Both the U.S. District Court and the Bankruptcy Court approved the settlement of the class action litigation styled In re Enron Corp. Securities Derivative & "ERISA" Litigation, Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action). On September 13, 2005, the U.S. District Court entered a Bar Order in the Tittle Action, which specifically bars all claims arising out of this case, including the IBEW grievance proceeding. On October 18, 2005, at the request of the Oregon Court of Appeals, PGE filed a response memorandum in which PGE argued that the Bar Order makes the grievance moot. 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 (PRPs) 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. 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 the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis PRP.

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 PRPs, 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 PRPs, including PGE. Management cannot predict the ultimate outcome of this matter or estimate any potential loss. However, it believes this matter will not have a material adverse impact on the Company's financial statements.

Harbor Oil - Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company's power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyl's (PCBs), have been detected at the site. On September 29, 2003, following investigation and site assessment by the EPA, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter starts a period for PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site. Discussions among the EPA and the PRPs, including PGE, have commenced.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Harbor Oil site or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company's 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. The site investigation has been completed and a report was submitted to the DEQ in August 2005. The report concludes that fuel and related contaminants have not migrated to the Willamette River from the site. Although the DEQ has stated that it is satisfied with the report, it has asked PGE to provide additional information about the Site. 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, 2005	December 31, 2004
Receivables from affiliated companies
	Enron Corp:
		Income Taxes Receivable(a)	$  10	$  -
	Enron Subsidiaries:
		Portland General Holdings, Inc.
		Accounts Receivable(a)	5	5
		Other Allowance for Uncollectible Accounts (a)	(1)	(1)
		PGH II and its subsidiaries
		Accounts Receivable(a)	-	1
		Other Allowance for Uncollectible Accounts(a)	-	(1)
Payables to affiliated companies
	Enron Corp:
		Accounts Payable(b)	3	4
		Income Taxes Payable(c)	-	21
(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			2005	2004
Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services(a)	$ 3	$ 19
Expenses billed to affiliated companies
	PGH II and its subsidiaries
		Intercompany services(a)	-	1
(a) Included in Administrative and other on the Consolidated Statements of Income

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 $10 million income taxes receivable from Enron at September 30, 2005 represents a net current income taxes receivable for the third quarter of 2005. The $21 million income taxes payable to Enron at December 31, 2004 represents a net current income taxes payable for the fourth quarter of 2004 that was paid to Enron in January 2005.

Intercompany Receivables and Payable - As part of its continuing operations, PGE bills affiliates for various services provided by the Company. These include services provided by PGE employees, as well as other corporate services. In addition, Enron passes through PGE's share of costs related to certain insurance coverage. Transactions with affiliates are subject either to approval of, or confirmation filing requirements with, the OPUC. 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. Affiliate transactions are also regulated by the SEC until the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935) becomes effective on February 8, 2006. 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.

The Energy Policy Act of 2005 (EPAct 2005) enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005). Under PUHCA 2005, the FERC obtains access to holding company books and records and it may determine cost allocations in certain affiliate transactions. The FERC has issued proposed rules implementing PUHCA 2005, but final rules have not yet been adopted. Accordingly, the effect of PUHCA 2005 on PGE is not yet determinable.

Enron - Beginning January 1, 2005, administration of the medical/dental benefit and retirement savings plans was returned to PGE from Enron; as a result, Enron no longer passes through costs to PGE for these services. In the first nine months of 2005, Enron billed PGE approximately $3 million for insurance coverage and costs related to the resolution of certain employee benefit plan matters (see below). For the same period in 2004, Enron billed PGE approximately $19 million, consisting of $17 million for medical/dental benefits and retirement savings plan matching, and $2 million for insurance coverage.

Enron has continued to incur costs related to the resolution of issues associated with the bankruptcy and litigation with regards to certain employee benefit plans in which PGE employees previously participated. Enron billed PGE for a portion of these costs in 2004 and 2005 as work continues toward resolution of the issues. At September 30, 2005, PGE had $3 million payable to Enron related to these costs, including approximately $1 million incurred in 2005. At December 31, 2004, PGE had $4 million payable to Enron related to employee benefits.

Portland General Holdings, Inc. - 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 was procedurally consolidated with the Enron bankruptcy proceeding; however, the Chapter 11 Plan expressly did not pertain to PGH. No PGH subsidiaries are included in the bankruptcy filing. Substantially all assets of PGH have been distributed or placed in segregated accounts. Accordingly, PGH moved the Bankruptcy Court to dismiss its Chapter 11 case. On October 20, 2005, the Bankruptcy Court granted PGH's motion and entered an order dismissing PGH's Chapter 11 case.

At September 30, 2005 and December 31, 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 administrative services provided by PGE to PGH in 2002. During 2003, PGE submitted proofs of claim to the Bankruptcy Court for approximately $5 million for employee benefit and administrative 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 then current assessment. In October 2005, PGE received $4 million, representing the unreserved amount owed by PGH.

PGH II and its Subsidiary - PGH II, Inc. (PGH II), a wholly owned subsidiary of PGH, is the parent company of Portland General Distribution, LLC (PGDC), a telecommunications company which received services from PGE. PGH II and PGDC were not part of Enron's or PGH's bankruptcy proceedings. At December 31, 2004, PGE had outstanding accounts receivable from PGDC of $1 million for employee and other administrative services, offset by a $0.9 million uncollectible reserve. In June 2005, PGDC used the proceeds from an asset sale to pay the unreserved amounts that it owed to PGE.

Beginning January 1, 2005, PGE no longer provides or bills PGH II for employee and administrative services. For the first nine months of 2004, PGE billed PGH II and its subsidiaries $1 million for employee and other administrative services.

Other Subsidiaries - PGE also provides services to its consolidated subsidiaries, including funding under a cash management agreement and the sublease of office space in the Company's headquarters complex. Intercompany balances and transactions have been eliminated in consolidation.

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

Note 6 - Receivables and Refunds on Wholesale Market Transactions

Receivables - California Wholesale Market

As of September 30, 2005, 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. 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

On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and PX. The order established 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.

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. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court of Appeals has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first considered arguments regarding jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. Briefing and oral argument have been completed on this first phase. As to the jurisdictional issues, on September 6, 2005, the Court ruled that FERC did not have jurisdiction to order municipal utilities and other governmental entities to make refunds for the sales they had made to the ISO and PX that are the subject of the refund proceeding. The Court has not yet issued a decision on the other issues pending in the first phase, and the Court agreed to defer the rehearing deadline on the jurisdictional issue decision until the remainder of the first phase is decided. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before FERC become final and are appealed.

Also on May 12, 2004, 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 liability. 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. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology of the September 24, 2004 order, 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. Partly as a means of limiting its exposure to additional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In August 2005, PGE joined in a settlement agreement resolving issues relating to the allocation of the wind-up costs of the PX for both past and future periods. The settlement has been approved by the FERC. Although under the agreement PGE will bear certain additional costs associated with PX obligations to conduct and finalize refund calculations, PGE does not expect those costs to be material to its financial statements.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. By order issued August 8, 2005, FERC provided guidelines regarding the manner in which these studies should be conducted and the principles that should govern their preparation. PGE filed for rehearing of certain aspects of the August 8 order, and, on September 14, it filed its cost recovery study with FERC. The study showed that, pursuant to the principles set forth in the August 8 order and subject to rehearing, PGE's costs to serve the ISO and PX markets exceeded the revenues PGE will receive from those mitigated sales by over $27 million. The study showed that PGE's refund liability should be reduced by that amount. Reply comments were filed by California parties that contested aspects of PGE's filing and proposed certain revisions that would reduce the refund offset amount to zero. The FERC has indicated that it intends to make decisions on marketers' cost recovery filings by mid- November 2005. Due to the continuing uncertainty related to these matters, PGE has made no adjustment to the $40 million reserve previously established for the Company's potential liability, as described above.

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. Management 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.

Anomalous Bidding Allegations

By order issued on June 25, 2003, the FERC instituted an investigation into allegations of anomalous bidding activities and practices ("economic withholding") on the part of numerous parties, including PGE. The FERC determined that bids above $250 per MW in the period from May 1, 2000 through October 2, 2000 may have violated tariff provisions of the ISO and the PX. The FERC required companies that bid in excess of $250 per MW to provide information on their bids to the FERC investigation staff. PGE responded to the FERC's inquiries and, on May 12, 2004, the FERC investigation staff issued to PGE a letter terminating the investigation as to the Company without further action. On March 10, 2005, certain California parties filed appeals with the Ninth Circuit Court of Appeals, contesting the FERC's conduct of the investigation of the anomalous bidding allegations and the issuance of the dismissal letters.

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, and from time to time thereafter, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. Although PGE was not included in the bankruptcy, the common stock of PGE held by Enron is one of the assets of the bankruptcy estate.

Enron's Chapter 11 plan (Chapter 11 Plan) became effective on November 17, 2004. The Chapter 11 Plan and the related disclosure statement provide information about the assets that were in the bankruptcy estate, including the common stock of PGE, and how those assets or their proceeds will be distributed to the creditors.

Future Ownership of PGE

Enron has announced that it intends to move forward to distribute PGE common stock to its creditors in accordance with the Chapter 11 Plan. As part of this process, current PGE common stock would be cancelled and shares of new PGE common stock would be issued. Initially, at least 30 percent of the new PGE common stock would be issued to the creditors of Enron and its reorganized debtor subsidiaries (collectively the Debtors) that hold allowed claims, with the remainder issued to a Disputed Claims Reserve (DCR) where it will be held to be released over time to the Debtors' creditors holding allowed claims in accordance with the Chapter 11 Plan. Following issuance of the new PGE common stock to the Debtors' creditors and the DCR, PGE will no longer be a subsidiary of Enron.

The registered owner of the new PGE common stock held in the DCR will be the Disbursing Agent associated with the DCR. The Disbursing Agent will oversee the release of new PGE common stock from the DCR to the Debtors' creditors that hold allowed claims. All shares of new PGE common stock held in the DCR will be voted by the Disputed Claims Reserve Overseers (DCRO). The DCRO is currently comprised of the same individuals who serve on Enron's Board of Directors.

Issuance of new PGE common stock is subject to certain conditions and requires approval of the OPUC, the FERC, the NRC, and certain other regulatory agencies. Applications for approval have been filed with the OPUC (on June 17, 2005), the NRC (on July 12, 2005), and the FERC (on September 21, 2005). An application was filed with the SEC on July 19, 2005 seeking authorization under PUHCA 1935 for Enron to divest PGE. PUHCA 1935 is repealed effective February 8, 2006 and, as a result, on September 8, 2005, the application previously filed with the SEC was withdrawn. On October 31, 2005, PGE was informed that the NRC Staff has determined that the issuance of PGE common stock is not a transfer of control and does not require NRC approval.

On September 1, 2005, Enron, PGE, OPUC Staff and major customer groups reached a stipulation (Stipulation) in PGE's application seeking OPUC approval to issue new PGE stock. The Stipulation sets forth a series of 17 conditions that will apply if the OPUC approves the application. The conditions relate to, among other things: maintaining PGE's financial strength during the conclusion of the Enron bankruptcy process, certain indemnifications for PGE from Enron related to Enron employee benefit plans and taxes (as described below), certain service quality measures, and additional direct access options for commercial and industrial customers. A ruling from the OPUC and the other regulatory agencies is expected by the end of 2005.

Enron has indicated that if all regulatory approvals are received and if sufficient claims have been resolved in a timely manner to allow at least 30% of the new PGE common stock to be issued, then the issuance of new PGE common stock is expected to occur in April 2006. PGE intends to apply for the listing of the new PGE common stock on a national securities exchange or national securities association.

Enron has also indicated that, in accordance with its ongoing efforts to maximize the value of the Enron bankruptcy estate, Enron will continue to consider credible offers to purchase PGE's common stock until the new PGE common stock is issued. Following issuance of the new PGE common stock, approval of any offer to purchase the new PGE common stock from the DCR will be the responsibility of the DCRO, in accordance with guidelines approved by the Bankruptcy Court.

Controlled Group Liability

Notwithstanding the above, Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plan 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). At December 31, 2004, the total fair value of PGE Plan assets was $2 million higher than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis. In addition, the PGE Plan was over-funded on an accumulated benefit obligation basis by approximately $58 million as of December 31, 2004.

Enron's management has informed PGE that, as of December 31, 2004, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $48 million on a SFAS No. 87 basis and approximately $166 million on a plan termination basis. The Pension Benefit Guaranty Corporation (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 the Employee Retirement Income Security Act of 1974, as amended (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). The PBGC has informed the Debtors that the PBGC has reduced its aggregate estimate of the UBL Claims for the Pension Plans to $321.8 million, including $240.2 million for the Enron Plan and $64.6 million related to the PGE Plan, although the PBGC has not amended the UBL Claims to reflect those amounts. Pursuant to an order of the Bankruptcy Court, Enron created a reserve fund equal to the amount of the maximum PBGC exposure, as delineated in the PBGC UBL Claims, of $321.8 million. This reserve provides security to the PBGC and PGE and other affiliates of Enron against the possibility of the PBGC seeking to assert its UBL Claims against Enron's affiliates as set forth below with respect to controlled group liability. As the Debtors are current on their PBGC premiums and their minimum funding contributions to the Pension Plans, the Debtors value the Premium Claims and the Contribution Claims at $0.

Enron has commenced a voluntary termination of the Enron Plan, in accordance with the Enron Plan terms, and is terminating it in a "standard" termination in accordance with ERISA.

As the Enron Plan is an underfunded pension plan, upon termination of the Enron Plan, all of the members of the ERISA controlled group of Enron 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 all of the assets of that member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all of the controlled group members. In addition, if the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in favor of the plan in the amount of the missed funding automatically 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 the plan sponsor and the members of its controlled group. PGE management believes that the 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. Based on discussions with Enron management, PGE's management understands that Enron has made all required contributions to date. In addition, the PBGC retains an interest in the proceeds of any sale by Enron of its ownership interest in PGE.

On June 2, 2004, the PBGC issued notices to Enron and Enron Facility Services, Inc., an Enron affiliate, stating that the PBGC had determined that the Pension Plans should be terminated and, 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. Such litigation has been stayed and is expected to be dismissed with prejudice pursuant to terms of the settlement described below that has been approved by the District Court and the Bankruptcy Court.

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.

Settlement of Claims Related to the Enron Plan

On September 12, 2005, in a joint hearing, the U.S. District Court for the Southern District of Texas, Houston Division (District Court) and the Bankruptcy Court approved the motions previously filed seeking final approval of a settlement (Settlement) with the PBGC and the plaintiffs in the class action litigation styled Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action) and the United States Department of Labor (DOL) in the litigation styled Elaine L. Chao v. Enron Corp., et al. (DOL Action). Under the Settlement, the Tittle Action plaintiffs and the DOL will have a shared general unsecured claim of $356.25 million and receive distributions pursuant to Enron's Chapter 11 Plan. Further, Enron is proceeding with the standard termination of the Pension Plans, as discussed above, and any need for the PBGC to attempt to collect from PGE any liability related to the Enron Plan should be eliminated. As a result of the Settlement, all litigation in the District Court on the involuntary termination of the Pension Plans and in the Bankruptcy Court on the PBGC claims against the Debtors with respect to the Pension Plans (including the portion related to the PGE Plan) and Enron's objection to such PBGC claims has been stayed and should, by the terms of the Settlement, be dismissed with prejudice.

OPUC Stipulation

One of the conditions in the Stipulation described above is that, upon the issuance of the new PGE common stock, Enron agrees to provide indemnification to PGE for, among other things, any liabilities related to Enron-sponsored employee benefit plans, including the Enron Plan. The indemnification is expected to be included in a Separation Agreement between Enron and PGE, which is expected to be executed at the time of the stock issuance. A ruling by the OPUC on the stock issuance application is expected by the end of 2005.

Management Assessment

Based on the creation of the reserve fund, the commencement of the standard termination of the Enron Plan, and the status of the Settlement, all described above, PGE management now believes that the possibility of a material liability to PGE related to the Enron Plan is remote.

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, 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 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 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 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.

Enron has not terminated its group health plan and, as a result, no retiree has sought coverage from PGE. PGE management believes that in the event Enron terminates retiree coverage, it is unlikely that retirees will seek coverage from PGE 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 conditions will not have a material adverse effect on the Company's financial statements. In addition, following the issuance of new PGE common stock to the Debtors' creditors holding allowed claims as described above, PGE will no longer be part of Enron's control group. As a result, no retiree could be entitled to seek coverage after the stock issuance. However, any retiree who sought coverage from PGE while PGE was still in the control group would be entitled to have coverage from PGE. Based on the above, management now believes that the possibility of material liability to PGE associated with Enron retiree health benefits is remote.

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. Enron treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and as having become 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 consolidated group on December 24, 2002.

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

1. Enron's consolidated tax returns through 1995 have been audited and are closed.
2. The IRS has completed an audit of Enron's consolidated tax returns for 1996-2001 and reached a settlement with Enron on January 5, 2005 which indicates no net taxes due by Enron. The settlement also eliminates any further assessment of tax, interest or penalty associated with Enron's consolidated tax returns for the years 1996-2001 against PGE and any other member of the consolidated group in excess of the overpayment currently held by the IRS.
3. Enron filed consolidated federal income tax returns for 2002 and 2003, which returns reported NOLs sufficient to eliminate Enron's regular income tax and alternative minimum income tax liabilities for those years. These tax returns are currently being audited by the IRS. In September 2005, Enron filed its 2004 tax return, which reported sufficient NOLs to eliminate its regular income tax for 2004 and alternative minimum tax with respect to that year. For calendar year 2005, Enron expects that it will have sufficient NOLs to eliminate regular income tax should it earn positive taxable income for the year. However, such taxable income, if realized, could be subject to the alternative minimum tax. With respect to periods after 2001, PGE is potentially severally liable for post-petition interest as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the Debtors or settled by reducing any refund owed to Enron.

OPUC Stipulation

One of the conditions in the Stipulation described above is that, upon the issuance of the new PGE common stock, Enron agrees to provide indemnification to PGE for all taxes that may be imposed by reason of PGE being severally liable for any taxes as being a member of Enron's consolidated tax group. The indemnification is expected to be included in a Separation Agreement between Enron and PGE, which is expected to be executed at the time of the stock issuance. A ruling by the OPUC on the stock issuance application is expected by the end of 2005.

Management Assessment

Based on Enron's settlement with the IRS for the years 1996-2001 and Enron's expectations to have sufficient NOLs to eliminate any income tax liabilities for 2002 through 2004 and substantially all tax liabilities for 2005 when PGE is a member of Enron's consolidated group, PGE management now believes that the possibility of a material liability to PGE related to any IRS assessment against the Enron consolidated group for income taxes, interest, and penalties is remote.

Note 8 - New Accounting Standards

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143, was issued in March 2005 and is effective no later than the end of fiscal years ending after December 15, 2005. FIN 47 clarifies that the term "conditional asset retirement obligation" as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated, even though uncertainty exists about the timing and (or) method of settlement. FIN 47 requires recognition of the cumulative effect of initial application as a change in accounting principle and requires disclosure on a pro forma basis in financial statement footnotes as if it had been applied during all periods affected. PGE is evaluating the impact of the application of FIN 47 with respect to its asset retirement obligations.

In December 2004, SFAS No. 153 (SFAS 153), Exchanges of Nonmonetary Assets, Amendment of Accounting Principles Board Opinion No. 29, Accounting for Nonmonetary Transactions (APB 29), was issued. SFAS 153 requires that nonmonetary asset exchanges be recorded and measured at the fair value of the assets exchanged, with certain exceptions. SFAS 153 amends APB 29 to eliminate the fair-value exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for nonmonetary exchanges that do not have commercial substance. The application of SFAS 153 is required in financial statements of entities that have nonmonetary asset exchanges in fiscal periods beginning after June 15, 2005. PGE has adopted SFAS 153 as of July 1, 2005 with respect to any future nonmonetary asset exchanges.

SFAS No. 154 (SFAS 154), Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in June 2005. SFAS 154 changes the requirements for the accounting and reporting of the direct effect of changes in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement that does not include specific transition provisions; when a pronouncement includes specific transition provisions, those provisions should be followed. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in the income statement. SFAS 154, which is effective for fiscal years beginning after December 15, 2005, is not expected to have a material effect on the financial statements of the Company.

FASB Staff Position No. FAS 13-1 (FSP 13-1), Accounting for Rental Costs Incurred during a Construction Period, addresses the accounting for rental costs associated with ground and building operating leases that are incurred during a construction period. FSP 13-1 requires that rental costs associated with ground or building operating leases incurred during a construction period be recognized as rental expense and included in income from continuing operations. The application of FSP 13-1, which is required in the first reporting period beginning after December 15, 2005, is not expected to have a material effect on the financial statements of the Company.

Emerging Issues Task Force Issue No. 05-6 (EITF 05-6), Determining the Amortization Period for Leasehold Improvements, addresses the issue of determining the amortization period for leasehold improvements in operating leases that are either (a) purchased subsequent to the inception of the lease or (b) acquired in a business combination. EITF 05-6 requires that the amortization period for acquired leasehold improvements be based on the lesser of the useful life of the leasehold improvements or the period of the lease, including renewal periods that are reasonably assured of exercise at the time of the acquisition. EITF 05-6 does not apply to pre-existing leasehold improvements. The amortization period for pre-existing leasehold improvements is not allowed to be reevaluated for additional renewal periods when new leasehold improvements are placed into service significantly after and are not contemplated at or near the beginning of the lease term. PGE's adoption of EITF 05-6 on July 1, 2005 did not have a material impact on the financial statements of the Company.

Note 9 - Subsequent Event

On October 5, 2005, the URP and Ken Lewis (Complainants) filed a Complaint with the OPUC alleging that, since September 2, 2005 (the effective date of Oregon Senate Bill 408), PGE's rates are not just and reasonable and are in violation of Senate Bill 408 because they contain approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any government. The Complaint requests that the OPUC order the creation of a deferred account for all amounts charged to ratepayers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes. Also on October 5, 2005, the Complainants filed an Application for Deferred Accounting with the OPUC, claiming that PGE is charging ratepayers $92.6 million annually for federal and state income taxes that is not being paid, and that such charges are not fair, just and reasonable. The Application for Deferred Accounting requests that revenue due to the estimated PGE liabilities for federal and state income taxes, less any amounts of federal and state income taxes paid by PGE or on behalf of PGE, be deferred for later incorporation in rates. Management cannot predict the ultimate outcome of these matters or estimate any potential loss.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Overview

Operations - PGE continues to utilize its generating assets and participation in the wholesale energy marketplace to meet the electricity needs of its customers. Improvements in thermal generating operations and favorable wholesale market conditions have offset reduced generation from the Company's hydro plants resulting from this year's moderate drought conditions. Retail loads during the first nine months of 2005 fell somewhat below both current year projections and last year's first nine months due to the year's mild weather. On a weather-adjusted basis, however, total retail energy deliveries increased by about 1% from last year's first nine months due to customer growth within the Company's service territory. PGE maintains investment-grade ratings on its debt, with the Company's ratings upgraded by both Moody's and Fitch and the outlook changed to 'Stable' by all three rating agencies in 2005. PGE continues to maintain its system and to make necessary capital investments required to meet projected customer growth.

Economy - Oregon's economy has slowed somewhat since the second quarter this year, but the momentum experienced last year has generally continued through the first nine months of 2005. Although the state's unemployment rate remains high, Oregon continues to rank among the nation's leaders in employment growth, with about 38,000 new jobs (including 3,400 in manufacturing) added through September 2005. Non-farm employment (seasonally adjusted) in September 2005 exceeded the previous peak set in late 2000. These job gains, which ranked among the highest in the nation, helped reduce Oregon's jobless rate from a high of 8.5% in July 2003 to about 6.1% in September 2005. PGE continues to experience customer growth, adding over 13,000 retail customers in this year's first nine months, and is working with state and local economic development organizations to assist area businesses on expansion-related matters and promote economic growth within the Company's service territory. Continued high energy prices and rising short-term interest rates, however, could affect future growth of both the national and regional economy.

Power Supply - Despite above average rainfall during this year's second quarter, regional hydro conditions have remained below normal in 2005, with "moderate drought" conditions experienced in the Northwest. Both the Clackamas and Deschutes river systems, where PGE's hydro generation facilities are located, remain below normal. However, increased output from mid-Columbia River hydro projects, with which PGE has long-term power purchase contracts, has helped offset lower generation from the Company's hydro projects. During the first nine months of 2005, PGE used its mix of generating assets and activities in the wholesale marketplace to offset the adverse financial effects of the region's below normal water levels. However, to the extent that hydro generation is below that projected in setting customer rates, margins could decline as more expensive replacement power is required to serve customers.

PGE's generating plants continue to operate well, with required annual maintenance at the Company's thermal facilities completed by the end of the third quarter. Construction of the Company's 400 MW natural gas-fired plant at Port Westward is on target for completion in mid-2007. Renewable generation from a 27 MWa wind power project in eastern Oregon, purchased under a 30-year agreement, is expected to become available by year-end. The project's fifty wind turbines, each capable of generating 1.5 megawatts, are expected to produce enough electricity to power 18,000 homes.

Regulatory Matters - During the third quarter of 2005, a stipulation was reached with the OPUC Staff and participating parties related to PGE's projected 2006 power costs under the Resource Valuation Mechanism process. The stipulation was approved by the OPUC on October 25, 2005. Due largely to substantial increases in the cost of wholesale power and continued high prices for natural gas, preliminary estimates indicate an approximate 4% to 5% average retail price increase, beginning in 2006. Such estimates, which include the effects of all credits and adjustments, will be finalized in mid-November 2005.

The Company's proposed Hydro Generation Adjustment tariff (which would allow rate adjustments reflecting changes in power costs caused primarily by variations in hydro conditions, power market prices, and natural gas prices), as well as a hydro cost deferral application for 2005, have been filed with the Commission. Decisions are expected by the end of this year.

In order to align its rate structure to sufficiently cover its operating costs, the Company is preparing a general rate case for consideration by the OPUC, which it currently plans to file in the first quarter of 2006.

New Oregon Law - Utility Rate Treatment of Income Taxes - A new law, Oregon Senate Bill 408, seeks to more closely match amounts collected under the ratemaking process with income taxes paid by investor-owned utilities or their consolidated group. The OPUC has issued temporary rules implementing the new law and PGE is participating in the Commission's more comprehensive, permanent rule-making process. On October 14, 2005, PGE filed a report, as required by the new law, on taxes "collected" and "paid" (as defined under the temporary rules and Senate Bill 408) for the years 2002-2004. Under the law, however, the first rate adjustment applies only to taxes paid and amounts collected from customers beginning in 2006. There is considerable uncertainty regarding several provisions of the law and the Company continues to evaluate its potential effects.

Future Ownership of PGE - In accordance with Enron's plan to issue new PGE common stock to its creditors holding allowed claims under its bankruptcy plan, applications have been filed (or will be filed shortly) with all of the required regulatory agencies. On September 1, 2005, Enron, PGE, OPUC Staff, and major customer groups reached a stipulation under which the signing parties recommended that the OPUC approve the application filed with the Commission. Rulings from the OPUC and other regulatory agencies are expected by the end of 2005. Enron has also indicated that it will continue to consider credible offers to purchase PGE's common stock. For further information, see "Enron Bankruptcy - Future Ownership of PGE" in "Financial and Operating Outlook" of this Item 2.

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 2005.

2005 Compared to 2004 for the Three Months Ended September 30

PGE's net income in the third quarter of 2005 was $19 million compared to $10 million in the third quarter of 2004. The increase was due primarily to improved margins on energy sales, as operations of the Company's thermal generating assets and activities in the wholesale marketplace offset the adverse effect of continued below normal regional hydro conditions. Partially offsetting the effect of improved margins were increased administrative and other expenses as well as a reserve for the potential refund to customers of previously collected amounts for local income taxes.

The following table summarizes Operating Revenues and Energy Sold and Delivered for the third quarter of 2005 and 2004:

			Three Months Ended September 30,
Operating Revenues			2005	2004	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 312	$ 314	$    (2)
		Direct Access Customer Revenues	-	2	(2)
Total Retail Revenues			312	316	(4)
Wholesale (Non-Trading)			35	26	9
Other Operating Revenues			8	6	2
Total Operating Revenues			$ 355	$ 348	$     7
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		4,274	4,337	(63)
	Energy Delivered to Direct Access Customers		326	206	120
Total Retail Energy Deliveries			4,600	4,543	57
Wholesale (Non-Trading)			570	574	(4)
Trading Activities			123	3,098	(2,975)
Total Energy Sold and Delivered			5,293	8,215	(2,922)

Total Retail Revenues decreased about 1% from last year's third quarter as the result of both a decline in retail energy sales and a reduction in Direct Access Customer Revenues. In addition, a reduction in amounts recovered from customers related to power cost adjustment mechanisms in effect during 2001 and 2002 resulted in a $6 million decrease in retail revenues (fully offset within Purchased Power and Fuel expense).

Total Retail Energy Deliveries, including energy delivered to direct access customers, increased about 1%. Retail Energy Sales decreased 1.5%, as 1% and 5% decreases in commercial and industrial sales, respectively, were partially offset by a slight increase in residential sales, resulting primarily from an approximate 11,000 increase in residential customers served in the third quarter of 2005. The decline in commercial and industrial energy sales was largely related to an increase in electricity delivered to those customers that now purchase their energy requirements from ESSs, including a single large industrial customer that accounted for about one-third of the increase. A 1.4% average rate increase for 2005, related to PGE's Resource Valuation Mechanism, partially offset the above reductions in commercial and industrial energy sales during this year's third quarter. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2. for further information). The decrease in Direct Access Customer Revenues, consisting of service charges for electricity delivered to customers who purchase energy from ESSs, was attributable to "transition adjustment" credits for these customers, reflecting the difference between the cost and market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Wholesale revenues increased by about 35% from last year's third quarter due primarily to a 37% average price increase, driven largely by higher natural gas prices. This was partially offset by an approximate 1% reduction in wholesale electricity sales.

The increase in Other Operating Revenues from last year's third quarter was caused primarily by increased margins on the sale of natural gas in excess of generating plant requirements and higher revenues from the sale of transmission capacity not currently required to serve existing load.

Purchased Power and Fuel expense decreased $14 million (8%) from last year's third quarter. The decrease includes $6 million related to the amortization of costs deferred under power cost adjustment mechanisms in effect during 2001 and 2002, which were later recovered from customers (fully offset within Retail revenues). The remaining decrease was due to an approximate 8% reduction in PGE's average variable power cost, due to a 57% increase in low-cost generation from the Boardman coal plant (which did not operate during a portion of last year's third quarter due to an extended maintenance outage), and to higher unrealized gains from derivative instruments. (See "Power and Fuel Supply - Price Risk Management" in "Financial and Operating Outlook" of this Item 2. for further information). PGE generation increased about 3% from last year's third quarter, with increased coal-fired generation largely offset by 35% and 3% reductions, respectively, in combustion turbine and hydro production. Total generation met approximately 47% of PGE's retail load during the third quarter of 2005, compared to 44% last year.

The following table indicates PGE's total system load (includes both retail and wholesale but excludes unrealized results from derivative instruments) for the third quarter of 2005 and 2004.

		Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)			Average Variable Power Cost (Mills/kWh)
	2005		2004	2005	2004
Generation	2,145		2,073	14.5	19.4
Term Purchases	2,528		2,662	37.5	37.4
Spot Purchases	489		513	57.6	45.8
Total Send-Out	5,162		5,248	32.6*	35.4*

(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $6 million (9%) from the third quarter of 2004 primarily due to higher employee benefit expenses, including medical and pension costs. These were partially offset by reduced expenses related to Boardman's extended maintenance outage in 2004.

Income taxes remained unchanged from last year's third quarter as higher taxes resulting from an increase in pretax operating income were offset by certain state tax credits and refunds.

Other Income (Miscellaneous) decreased $4 million due primarily to the establishment of a reserve related to the potential refund to customers of previously-collected local income taxes. This was partially offset by an increase in income from non-qualified benefit plan trust assets and higher interest on short-term investments.

2005 Compared to 2004 for the Nine Months Ended September 30

PGE's net income in the first nine months of 2005 was $73 million, compared to $64 million in the first nine months of 2004. The increase was due primarily to improved margins on energy sales, as operations of the Company's thermal generating assets and activities in the wholesale marketplace offset the adverse effect of below normal regional hydro conditions. In addition, the first nine months of 2004 included higher expenses related to maintenance activities at the Boardman coal plant. Partially offsetting the above were higher administrative and general expenses (including those related to employee benefits and the settlement of certain asserted claims), higher distribution expenses, and a reserve for the potential refund to customers of previously collected amounts for local income taxes.

The following table summarizes Operating Revenues and Energy Sales for the nine-month periods ending September 30, 2005 and 2004:

			Nine Months Ended September 30,
Operating Revenues			2005	2004	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$   953	$   965	$    (12)
		Direct Access Customer Revenues	-	5	(5)
Total Retail Revenues			953	970	(17)
Wholesale (Non-Trading)			87	82	5
Other Operating Revenues:
	Trading Activities - net		-	1	(1)
	Other		19	22	(3)
Total Operating Revenues			$1,059	$1,075	$    (16)
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		12,838	13,099	(261)
	Energy Delivered to Direct Access Customers		914	578	336
Total Retail Energy Deliveries			13,752	13,677	75
Wholesale (Non-Trading)			1,650	1,999	(349)
Trading Activities			697	8,660	(7,963)
Total Energy Sold and Delivered			16,099	24,336	(8,237)

Total Retail Revenues decreased about 2% from the first nine months of last year. A $17 million decrease resulted from a reduction in amounts recovered from customers related to power cost adjustment mechanisms in effect during 2001 and 2002 (fully offset within Purchased Power and Fuel expense). A decline in retail energy sales and a reduction in Direct Access Customer Revenues were partially offset by 1.4% average rate increase for 2005, related to PGE's Resource Valuation Mechanism. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2. for further information). Total Retail Revenues decreased about 1% from last year's third quarter as the result of both a decline in retail energy sales and a reduction in Direct Access Customer Revenues.

Total Retail Energy Deliveries, including energy delivered to direct access customers, increased about 1%. Retail Energy Sales decreased 2%, as all major customer classes reduced their energy use in the first nine months of 2005. Despite an approximate 11,000 increase in average customers served during the first nine months of this year, residential energy sales declined about 1%, due primarily to mild weather. Declines in commercial and industrial energy sales of 2.3% and 4.4%, respectively, were largely related to an increase in electricity delivered to those customers that now purchase their energy requirements from ESSs, including a single large industrial customer that accounted for about one-third of the increase. The decrease in Direct Access Customer Revenues, consisting of service charges for electricity delivered to commercial and industrial customers who purchase energy from ESSs, was attributable to "transition adjustment" credits for these customers, reflecting the difference between the cost and market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Wholesale revenues increased by about 6% from last year's first nine months due primarily to a 29% increase in average price, driven largely by higher natural gas prices. This was partially offset by an approximate 17% reduction in wholesale electricity sales resulting from reduced market activity.

The decrease in Other Operating Revenues from last year was caused primarily by reduced margins on the sale of natural gas in excess of generating plant requirements, related to decisions that resulted in increased combustion turbine generation in the first nine months of 2005.

Purchased Power and Fuel expense decreased $52 million (11%) from the first nine months of last year. The decrease includes $17 million related to the amortization of costs deferred under power cost adjustment mechanisms in effect during 2001 and 2002, which were later recovered from customers (fully offset within Retail revenues). The remaining decrease was due to an approximate 10% reduction in PGE's average variable power cost, due primarily to a 27% increase in low-cost coal-fired generation (primarily from the Boardman coal plant), and to higher unrealized gains from derivative instruments. (See "Power and Fuel Supply - Price Risk Management" in "Financial and Operating Outlook" of this Item 2. for further information). Company generation increased about 4% from that of last year's first nine months, with increased coal-fired generation largely offset by 29% and 13% reductions, respectively, in combustion turbine and hydro production. Total generation met approximately 44% of PGE's retail load during the first nine months of 2005, compared to 41% last year.

The following table indicates PGE's total system load (includes both retail and wholesale but excludes unrealized results from derivative instruments) for the first nine months of 2005 and 2004.

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)
	2005	2004	2005	2004
Generation	6,061	5,850	12.4	15.8
Term Purchases	8,567	9,135	33.7	33.9
Spot Purchases	809	989	48.5	41.9
Total System Load	15,437	15,974	28.8*	31.9*
(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $18 million (9%) from the first nine months of 2004 due to increased employee benefit expenses (including medical and pension costs), the settlement of certain asserted claims, and an increase in distribution maintenance expenses. These were partially offset by reduced expenses related to last year's extended maintenance outage at Boardman and a first-quarter snow and ice storm.

Income taxes increased $1 million from the first nine months of last year as higher taxes resulting from an increase in pretax income were offset by certain state tax credits and refunds.

Other Income (Miscellaneous) decreased $4 million due primarily to the establishment of a reserve related to the potential refund to customers of previously-collected local income taxes. This was partially offset by higher interest on short-term investments and an increase in income from non-qualified benefit plan trust assets.

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 changes in the price of power and fuel as well as by weather conditions, as temperatures outside the normal range can affect electricity usage and resultant cash flow.

Cash provided by operating activities totaled $402 million in the first nine months of 2005 compared to $284 million in the same period last year. The increase was due primarily to a $117 million increase in cash collateral deposits received from certain wholesale customers, a $25 million decrease in payments for power and fuel purchases, the liquidation of a $10 million investment in debt securities, and a $5 million decrease in interest payments. These items were partially offset by a $17 million decrease in amounts received for electricity sales and a $22 million increase in income tax payments.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. The $50 million increase in capital expenditures in the first nine months of 2005 is primarily attributable to construction costs of Port Westward, the purchase of the Boardman coal handling facility (which was previously leased by the Company), and hydro relicensing activities. Other expenditures were related to the expansion of PGE's distribution system to support both new and existing customers within the Company's service territory.

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, and long-term financing activities to support such requirements.

During the first nine months of 2005, PGE retired $18 million of First Mortgage Bonds, $8 million of conservation bonds, and $3 million of preferred stock. In July 2005, PGE paid a common stock dividend of $150 million to Enron. No cash dividends on common stock were declared or paid in the first nine months of 2004. PGE paid $1 million of preferred stock dividends in the first nine months of 2005 (classified as interest expense).

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, 2005, PGE has the capability to issue additional preferred stock and First Mortgage Bonds in amounts sufficient to meet its currently anticipated capital and operating requirements.

PGE has a $400 million five-year, unsecured, revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and various banks that is available for general corporate purposes. The maximum amount of the facility is available to PGE for borrowings and/or the issuance of standby letters of credit. The agreement provides for borrowings at a variable interest rate and requires annual facility fees based on the Company's unsecured credit rating. The facility, which is unsecured, contains a financial covenant that limits consolidated indebtedness, as defined in the facilities, to 65% of total capitalization. At September 30, 2005, the Company's indebtedness to total capitalization ratio, as calculated under the facility, was 41.6%. At September 30, 2005, the Company had utilized approximately $24 million in letters of credit, $15 million of which were related to wholesale trading activities and $9 million of which were related to Port Westward.

On July 29, 2005, the SEC issued an order under PUHCA 1935 authorizing PGE to issue and sell unsecured short-term debt with a maturity of less than one year through July 31, 2006, subject to certain conditions regarding interest rates, issuance expenses and the maintenance of a common equity ratio of at least 30% of consolidated capitalization. The SEC order permits PGE to incur indebtedness under its unsecured five-year $400 million revolving credit facility as well as other short-term indebtedness. The aggregate principal amount outstanding at any one time under the revolving credit facility and other short-term indebtedness may not exceed $600 million. Following the repeal of PUHCA 1935, PGE's short-term financing transactions will require authorization by the FERC under the Federal Power Act.

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 is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 57.3% and 58.2% at September 30, 2005 and December 31, 2004, 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 $210 million to $230 million annually over the period 2005-2007. Combined with all other sources, total cash provided by operations is estimated to range from $270 million to $305 million annually during the 2005-2007 period.

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

	2005	2006	2007
Capital expenditures (*)	$305 - $325	$305 - $325	$230 - $250
Long-term debt maturities	$30	$11	$70

(*) Includes expenditures related to the construction of Port Westward (approximately $108 for 2005, $114 for 2006, and $14 for 2007)

.

Cash flow from operations in excess of cash requirements may be used to fund costs associated with acquisition of new energy resources. Additional liquidity is available under PGE's revolving credit facility. Cash balances are temporarily invested primarily in government money market funds and short-term commercial paper. 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.

On July 19, 2005, PGE declared and paid a cash dividend of $150 million to Enron, the sole shareholder of the Company's common stock. PGE's equity ratio (as calculated under OPUC requirements) remains above the 48% level required by the Commission under terms of PGC's 1997 merger with Enron. PGE's common equity ratio also remains above the Company's 50% objective, as described above.

Credit Ratings

PGE's secured and unsecured debt are rated at investment grade by Moody's Investors Service (Moody's), Standard and Poor's (S&P), and Fitch Ratings (Fitch).

PGE 's current credit ratings are as follows:

	Moody's	S&P	Fitch
First Mortgage Bonds	Baa1	BBB+	A-
Senior unsecured debt	Baa2	BBB	BBB+
Preferred stock	Ba1	BBB-	-
Commercial paper	Prime-2	A-2	F-2
Outlook:	Stable	Stable	Stable

In September 2005, S&P raised its outlook on PGE from 'Developing' to 'Stable'.

Should Moody's or S&P (or both) 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, 2005, PGE had posted approximately $21 million of collateral, consisting of $15 million in letters of credit and $6 million in cash. Based on the Company's non-trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of September 30, 2005, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $24 million and decreases to approximately $1 million by year-end 2005. The approximate amount of additional collateral that could be requested upon a dual agency downgrade event to below investment grade is approximately $37 million and decreases to approximately $3 million by year-end 2005.

In addition to collateral calls, 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 facilities, increasing the cost of funding the Company's day-to-day working capital requirements. 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 Enron, in September 2002 PGE 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.

Contractual Obligations and Commercial Commitments

PGE's contractual obligations have not changed materially from those amounts disclosed in the Company's 2004 Annual Report on Form 10-K.

Financial and Operating Outlook

Retail Customer Growth and Energy Deliveries

Weather adjusted retail energy deliveries to PGE and ESS customers increased 0.6% for the nine months ended September 30, 2005, compared to the same period last year. The increase was due primarily to 1.1% and 2.1% increases, respectively, for commercial and industrial customers. Increased industrial usage was largely attributable to a single large customer that normally generates its own power requirements, but which purchased energy from the Company during the first nine months of 2005. Weather adjusted residential energy deliveries were down 0.7% compared to the first nine months of 2004, as reduced energy use was only partially offset by an approximate 11,000 increase in the average number of customers served. PGE forecasts total weather adjusted energy deliveries to PGE and ESS customers in 2005 to increase by approximately 1% from last year.

Power and Fuel Supply

Hydro conditions in the region continued to remain below normal levels during the first nine months of 2005. 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 2005 runoff through September (as measured at The Dalles, Oregon) at 74% of normal, compared to actual runoffs of 77% in 2004 and 83% in 2003. In 2005, hydro conditions in the Clackamas and Deschutes river systems, where PGE's facilities are located, are projected to be 72% and 87% of normal, respectively, compared to actual runoffs of approximately 82% and 87% of normal, respectively, in 2004.

PGE generated 44% of its retail load requirement in the first nine months of 2005, with 36% met with thermal generation and the remaining 8% 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. Factors that could affect the availability and price of purchased power and fuel include weather conditions in the Northwest and Southwest, as well as the performance of major generating facilities in both regions. In addition, market prices for natural gas have increased significantly in 2005 due to the combined effects of severe hurricanes in the Gulf of Mexico and record hot weather in the United States. Such price increases could, in the longer term, affect the cost of natural gas required to fuel PGE's combustion turbine generating plants as well as prices of power purchased in the wholesale market.

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 to minimize net power costs to serve 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 OCI 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

Commencing on December 2, 2001, and from time to time thereafter, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. Although PGE was not included in the bankruptcy, the common stock of PGE held by Enron is one of the assets of the bankruptcy estate.

Enron's Chapter 11 plan (Chapter 11 Plan) became effective on November 17, 2004. The Chapter 11 Plan and the related disclosure statement provide information about the assets that were in the bankruptcy estate, including the common stock of PGE, and how those assets or their proceeds will be distributed to the creditors.

Future Ownership of PGE

Enron has announced that it intends to move forward to distribute PGE common stock to its creditors in accordance with the Chapter 11 Plan. As part of this process, current PGE common stock would be cancelled and shares of new PGE common stock would be issued. Initially, at least 30 percent of the new PGE common stock would be issued to the Debtors' creditors that hold allowed claims, with the remainder issued to a Disputed Claims Reserve (DCR) where it will be held to be released over time to the Debtors' creditors holding allowed claims in accordance with the Chapter 11 Plan. Following issuance of the new PGE common stock to the Debtors' creditors and the DCR, PGE will no longer be a subsidiary of Enron.

The registered owner of the new PGE common stock held in the DCR will be the Disbursing Agent associated with the DCR. The Disbursing Agent will oversee the release of new PGE common stock from the DCR to the Debtors' creditors that hold allowed claims. All shares of new PGE common stock held in the DCR will be voted by the Disputed Claims Reserve Overseers (DCRO). The DCRO is currently comprised of the same individuals who serve on Enron's Board of Directors.

Issuance of new PGE common stock is subject to certain conditions and requires approval of the OPUC, the FERC, the NRC, and certain other regulatory agencies. Applications for approval have been filed with the OPUC (on June 17, 2005), the NRC (on July 12, 2005), and the FERC (on September 21, 2005). An application was filed with the SEC on July 19, 2005 seeking authorization under PUHCA 1935 for Enron to divest PGE. PUHCA 1935 is repealed effective February 8, 2006 and, as a result, on September 8, 2005, the application previously filed with the SEC was withdrawn. On October 31, 2005, PGE was informed that the NRC Staff has determined that the issuance of new PGE common stock is not a transfer of control and does not require NRC approval.

On September 1, 2005, Enron, PGE, OPUC Staff and major customer groups reached a stipulation (Stipulation) in PGE's application seeking OPUC approval to issue new PGE stock. The Stipulation sets forth a series of 17 conditions that will apply if the OPUC approves the application. The conditions include: maintaining PGE's financial strength during the conclusion of the Enron bankruptcy process, certain indemnifications for PGE from Enron related to Enron employee benefit plans and taxes (as described below), certain service quality measures, and additional direct access options for commercial and industrial customers. A ruling from the OPUC and the other regulatory agencies is expected by the end of 2005.

Enron has indicated that if all regulatory approvals are received and if sufficient claims have been resolved in a timely manner to allow at least 30% of the new PGE common stock to be issued, then the issuance of new PGE common stock is expected to occur in April 2006. PGE intends to apply for the listing of the new PGE common stock on a national securities exchange or national securities association.

Enron has also indicated that, in accordance with its ongoing efforts to maximize the value of the Enron bankruptcy estate, Enron will continue to consider credible offers to purchase PGE's common stock until the new PGE common stock is issued. Following issuance of the new PGE common stock, approval of any offer to purchase the new PGE common stock from the DCR will be the responsibility of the DCRO, in accordance with guidelines approved by the Bankruptcy Court.

Controlled Group Liability

Notwithstanding the above, Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plan 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). At December 31, 2004, the total fair value of PGE Plan assets was $2 million higher than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis. In addition, the PGE Plan was over-funded on an accumulated benefit obligation basis by approximately $58 million as of December 31, 2004.

Enron's management has informed PGE that, as of December 31, 2004, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $48 million on a SFAS No. 87 basis and approximately $166 million on a plan termination basis. The Pension Benefit Guaranty Corporation (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 the Employee Retirement Income Security Act of 1974, as amended (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). The PBGC has informed the Debtors that the PBGC has reduced its aggregate estimate of the UBL Claims for the Pension Plans to $321.8 million, including $240.2 million for the Enron Plan and $64.6 million related to the PGE Plan, although the PBGC has not amended the UBL Claims to reflect those amounts. Pursuant to an order of the Bankruptcy Court, Enron created a reserve fund equal to the amount of the maximum PBGC exposure, as delineated in the PBGC UBL Claims, of $321.8 million. This reserve provides security to the PBGC and PGE and other affiliates of Enron against the possibility of the PBGC seeking to assert its UBL Claims against Enron's affiliates as set forth below with respect to controlled group liability. As the Debtors are current on their PBGC premiums and their minimum funding contributions to the Pension Plans, the Debtors value the Premium Claims and the Contribution Claims at $0.

Enron has commenced a voluntary termination of the Enron Plan, in accordance with the Enron Plan terms, and is terminating it in a "standard" termination in accordance with ERISA.

As the Enron Plan is an underfunded pension plan, upon termination of the Enron Plan, all of the members of the ERISA controlled group of Enron 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 all of the assets of that member of the controlled group. The amount of the lien is equal to the lesser of the underfunding or 30% of the aggregate net worth of all of the controlled group members. In addition, if the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in favor of the plan in the amount of the missed funding automatically 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 the plan sponsor and the members of its controlled group. PGE management believes that the 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. Based on discussions with Enron management, PGE's management understands that Enron has made all required contributions to date. In addition, the PBGC retains an interest in the proceeds of any sale by Enron of its ownership interest in PGE.

On June 2, 2004, the PBGC issued notices to Enron and Enron Facility Services, Inc., an Enron affiliate, stating that the PBGC had determined that the Pension Plans should be terminated and, 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. Such litigation has been stayed and is expected to be dismissed with prejudice pursuant to terms of the settlement described below that has been approved by the District Court and the Bankruptcy Court.

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.

Settlement of Claims Related to the Enron Plan

On September 12, 2005, in a joint hearing, the U.S. District Court for the Southern District of Texas, Houston Division (District Court) and the Bankruptcy Court approved the motions previously filed seeking final approval of a settlement (Settlement) with the PBGC and the plaintiffs in the class action litigation styled Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action) and the United States Department of Labor (DOL) in the litigation styled Elaine L. Chao v. Enron Corp., et al. (DOL Action). Under the Settlement, the Tittle Action plaintiffs and the DOL will have a shared general unsecured claim of $356.25 million and receive distributions pursuant to Enron's Chapter 11 Plan. Further, Enron is proceeding with the standard termination of the Pension Plans, as discussed above, and any need for the PBGC to attempt to collect from PGE any liability related to the Enron Plan should be eliminated. As a result of the Settlement, all litigation in the District Court on the involuntary termination of the Pension Plans and in the Bankruptcy Court on the PBGC claims against the Debtors with respect to the Pension Plans (including the portion related to the PGE Plan) and Enron's objection to such PBGC claims has been stayed and should, by the terms of the Settlement, be dismissed with prejudice.

OPUC Stipulation

One of the conditions in the Stipulation described above is that, upon the issuance of the new PGE common stock, Enron agrees to provide indemnification to PGE for, among other things, any liabilities related to Enron-sponsored employee benefit plans, including the Enron Plan. The indemnification is expected to be included in a Separation Agreement between Enron and PGE, which is expected to be executed at the time of the stock issuance. A ruling by the OPUC on the stock issuance application is expected by the end of 2005.

Management Assessment

Based on the creation of the reserve fund, the commencement of the standard termination of the Enron Plan, and the status of the Settlement, all described above, PGE management now believes that the possibility of a material liability to PGE related to the Enron Plan is remote.

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, 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 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 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 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.

Enron has not terminated its group health plan and, as a result, no retiree has sought coverage from PGE. PGE management believes that in the event Enron terminates retiree coverage, it is unlikely that retirees will seek coverage from PGE 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 conditions will not have a material adverse effect on the Company's financial statements. In addition, following the issuance of new PGE common stock to the Debtors' creditors holding allowed claims as described above, PGE will no longer be part of Enron's control group. As a result, no retiree could be entitled to seek coverage after the stock issuance. However, any retiree who sought coverage from PGE while PGE was still in the control group would be entitled to have coverage from PGE. Based on the above, management now believes that the possibility of material liability to PGE associated with Enron retiree health benefits is remote.

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. Enron treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and as having become 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 consolidated group on December 24, 2002.

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

1. Enron's consolidated tax returns through 1995 have been audited and are closed.
2. The IRS has completed an audit of Enron's consolidated tax returns for 1996-2001 and reached a settlement with Enron on January 5, 2005 which indicates no net taxes due by Enron. The settlement also eliminates any further assessment of tax, interest or penalty associated with Enron's consolidated tax returns for the years 1996-2001 against PGE and any other member of the consolidated group in excess of the overpayment currently held by the IRS.
3. Enron filed consolidated federal income tax returns for 2002 and 2003, which returns reported NOLs sufficient to eliminate Enron's regular income tax and alternative minimum income tax liabilities for those years. These tax returns are currently being audited by the IRS. In September 2005, Enron filed its 2004 tax return, which reported sufficient NOLs to eliminate its regular income tax for 2004 and alternative minimum tax with respect to that year. For calendar year 2005, Enron expects that it will have sufficient NOLs to eliminate regular income tax should it earn positive taxable income for the year. However, such taxable income, if realized, could be subject to the alternative minimum tax. With respect to periods after 2001, PGE is potentially severally liable for post-petition interest as well as any portion of the claim allowed in the bankruptcy that the IRS does not collect from the Debtors or settled by reducing any refund owed to Enron.

OPUC Stipulation

One of the conditions in the Stipulation described above is that, upon the issuance of the new PGE common stock, Enron agrees to provide indemnification to PGE for all taxes that may be imposed by reason of PGE being severally liable for any taxes as being a member of Enron's consolidated tax group. The indemnification is expected to be included in a Separation Agreement between Enron and PGE, which is expected to be executed at the time of the stock issuance. A ruling by the OPUC on the stock issuance application is expected by the end of 2005.

Management Assessment

Based on Enron's settlement with the IRS for the years 1996-2001 and Enron's expectations to have sufficient NOLs to eliminate any income tax liabilities for 2002 through 2004 and substantially all tax liabilities for 2005 when PGE is a member of Enron's consolidated group, PGE management now believes that the possibility of a material liability to PGE related to any IRS assessment against the Enron consolidated group for income taxes, interest, and penalties is remote.

Energy Policy Act of 2005

EPAct 2005, signed into law on August 8, 2005, significantly revised the Federal Power Act and Natural Gas Act. It also substantially changed the qualifying facility provisions of the Public Utility Regulatory Policies Act of 1978 (PURPA) and enacted tax incentives for the development of renewable and cleaner-fuel electric generating resources and for other electric and gas related purposes. EPAct 2005 includes transmission and reliability measures, including a plan for mandatory reliability standards to be developed and enforced by an electric reliability organization under the FERC, which also has enhanced oversight of power and transmission markets.

EPAct 2005 also repealed PUHCA 1935 and enacted PUHCA 2005, effective February 8, 2006. Under PUHCA 2005, the FERC obtains access to holding company books and records and it may determine cost allocations in certain affiliate transactions. The FERC has issued proposed rules implementing PUHCA 2005, but final rules have not yet been adopted. Accordingly, the effect of PUHCA 2005 on PGE is not yet determinable.

New Oregon Law - Utility Rate Treatment of Income Taxes

A new law, Oregon Senate Bill 408, seeks to adjust the way that PGE and most other Oregon investor-owned electric and gas utilities collect income taxes from ratepayers. Senate Bill 408 attempts to more closely match amounts collected under the ratemaking process with income taxes paid by investor-owned utilities or their consolidated group. It requires that utilities file annual reports with the OPUC (by October 15) regarding the amount of taxes paid by the utility or its consolidated group (with certain adjustments), as well as the amount of taxes collected in rates, as defined by the statute. If the OPUC determines that the difference between the two amounts is greater than $100,000, the Commission is to require the utility to establish an "automatic adjustment clause" to adjust rates. PGE's initial report was filed on October 14, 2005 for the calendar years 2002, 2003, and 2004. That report indicated a difference between taxes assumed to have been collected and adjusted taxes paid, as determined according to Senate Bill 408 and OPUC temporary rules, of $4,369,764 in 2002, $59,979,805 in 2003, and $65,402,565 in 2004. However, under the law the first adjustment under the automatic adjustment clause applies only to taxes paid to units of government and collected from ratepayers on or after January 1, 2006.

Considerable uncertainty exists regarding the new law, with several issues subject to interpretation by the OPUC. Until the Commission issues rules that implement the law, its impact on customers and utilities will be difficult to assess. In addition, it is expected that such orders may be challenged in the courts. The OPUC has adopted temporary rules implementing the new law in order to allow for submission of the initial tax report and has opened a more comprehensive, permanent rule-making process. PGE continues to evaluate the potential effects of the new law.

Complaint and Application for Deferral - Income Taxes

On October 5, 2005, the URP and Ken Lewis (Complainants) filed a Complaint with the OPUC alleging that, since September 2, 2005 (the effective date of Oregon Senate Bill 408), PGE's rates are not just and reasonable and are in violation of Senate Bill 408 because they contain approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any government. The Complaint requests that the OPUC order the creation of a deferred account for all amounts charged to ratepayers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes. Also on October 5, 2005, the Complainants filed an Application for Deferred Accounting with the OPUC, claiming that PGE is charging ratepayers $92.6 million annually for federal and state income taxes that is not being paid, and that such charges are not fair, just and reasonable. The Application for Deferred Accounting requests that revenue due to the estimated PGE liabilities for federal and state income taxes, less any amounts of federal and state income taxes paid by PGE or on behalf of PGE, be deferred for later incorporation in rates. Management cannot predict the ultimate outcome of these matters or estimate any potential loss.

Class Action Lawsuit - Multnomah County Business Income Taxes

In January 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MCBIT) after 1996. The plaintiffs allege that during the period 1997 through the third quarter 2004, PGE collected in excess of $6 million from its customers for MCBIT that was never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As a member of Enron's consolidated income tax return, PGE paid the tax it collected to Enron. The plaintiffs seek a judgment against PGE for restitution of MCBIT collected from customers. Plaintiffs also seek interest, recoverable costs, and reasonable attorney fees. The plaintiffs filed an amended complaint on February 25, 2005, adding claims for fraud, unjust enrichment, conversion, statutory violations, and seeking punitive damages. On February 24, 2005, PGE requested a declaratory ruling from the OPUC on this matter. On May 17, 2005, the OPUC agreed to consider the question posed by PGE; whether the OPUC rules authorized PGE collections of the MCBIT and, if not, whether refunds are controlled by the OPUC three-year limitation for billing adjustments. On March 24, 2005, PGE filed in the Circuit Court a motion to abate or in the alternative to dismiss. On May 23, 2005, the Circuit Court granted PGE's motion for a stay for all purposes until October 15, 2005, with the opportunity to renew if the OPUC has not issued its declaratory ruling. On October 5, 2005, the OPUC issued an order in the declaratory ruling docket. The OPUC determined that the rules in question required only that PGE allocate this tax to Multnomah County customers and did not require that PGE calculate it in any particular way. Because the OPUC did not find that PGE had violated its rule, the OPUC did not answer whether its three-year limitation on billing adjustments applied. Proceedings will continue in Multnomah County Circuit Court. PGE has notified the Court of the Company's intent to voluntarily refund MCBIT (plus interest) to customers and has filed motions requesting the Court's guidance regarding the number of years for which refunds should be made. Based on management's assessment of these matters, PGE established a reserve in the third quarter of 2005 and believes that any additional loss will not have a material adverse impact on the Company's financial statements.

City of Portland Resolution

On September 21, 2005, the Portland City Council approved a resolution directing the City Attorney and City staff to obtain from PGE information regarding the collection and payment of utility income taxes to determine whether the Company's rates charged to residents of the City are "fair and reasonable." The resolution further directs the City Attorney and City staff to report to the City Council within sixty days of adoption of this resolution. PGE has provided the requested information.

General Rate Case

PGE is in the process of preparing a general rate case for consideration by the OPUC, which the Company currently plans to file in the first quarter of 2006. A major component of the rate case will be the recovery of costs for the Company's investment in the new natural gas-fired Port Westward project, scheduled to become operational in mid-2007. The review by the OPUC, including a detailed analysis of PGE's projected costs and proposed rate structure, is expected to take about 10 months and will include input from stakeholders and the public. PGE's last general rate case was filed in October 2000, with an OPUC decision issued in August 2001 that authorized price changes effective on October 1, 2001.

Resource Valuation Mechanism

The 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 electricity service suppliers, the RVM utilizes a combination of market prices and the cost of the Company's resources to establish power costs and set prices 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.

Preliminary Power Cost Filing - 2006 In April 2005, PGE submitted an RVM filing with the OPUC containing a preliminary estimate of 2006 power costs, with updates to such estimates subsequently filed. On September 28, 2005, upon completion of settlement conferences, a stipulation was reached between PGE, OPUC Staff, and parties to the RVM proceedings which provides for a final RVM filing by PGE in November 2005. The OPUC approved the stipulation on October 25, 2005. Preliminary estimates indicate an approximate 4% to 5% average retail price increase (including the effect of all credits and adjustments), due largely to substantial increases in the cost of wholesale power and continued high prices for natural gas.

Power Cost Adjustment Mechanism - 2001

To address the impact of price volatility in the 2000-2001 wholesale power and natural gas markets, the OPUC authorized PGE 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 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); the recovery period was subsequently extended through December 2005. At September 30, 2005, the remaining balance to be collected was approximately $5 million. PGE did not have a power cost adjustment mechanism in place for 2004 and has none currently in place for 2005.

Hydro Generation Adjustment

The effect of adverse hydro conditions in recent years has required that PGE acquire replacement power resources for shortfalls in hydro-based power, incurring substantially higher variable power costs than those included in the Company's electricity prices. In July 2004, PGE requested OPUC consideration of a Hydro Generation Adjustment tariff that would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions.

In anticipation of the effects of poor hydro conditions in 2005, the Company in December 2004 filed with the OPUC an "Application for Deferral of Costs and Benefits due to Hydro Generation Variance" that would defer costs, beginning on January 1, 2005, for future amortization in prices.

In April 2005, PGE and OPUC Staff entered into stipulations in both the Hydro Generation Adjustment and deferral application proceedings described above; other parties in the proceedings did not enter into the stipulations. The stipulations agreed to and requested that the OPUC adopt a System Dispatch Power Cost Adjustment Mechanism to defer for future recovery in rates a portion of power cost changes caused by variations in hydro conditions, power market prices, and natural gas prices during calendar years 2005 and 2006. Following a procedural schedule adopted by the Commission for consideration of the stipulations, hearings were conducted and briefs submitted in August and September, with decisions by the OPUC expected by year-end 2005.

Hydro Relicensing

PGE's long-term power purchase contracts with certain public utility districts in the State of Washington expire between 2005 and 2018. PGE has executed new agreements with Grant County Public Utility District (Grant), operator of the Priest Rapids and Wanapum projects, for periods corresponding to Grant's new license term to be determined by the FERC. Delivery of power under the new agreements began on November 1, 2005. Under the agreements, Grant will annually determine the output required for its purposes, with PGE required to purchase approximately 25% of the output beyond Grant's needs over the term of the new license, for which PGE will pay a proportional share of the project's debt service and operating costs. PGE's share of the output will decline over time as Grant's needs increase, with the Company's share in the two projects reduced from the current 237 MW to an estimated 171 MW in 2009. Also under the agreements, PGE will purchase an additional 41 average megawatts of power beginning in 2005, increasing to 51 average megawatts for the period 2007 through 2011.

Receivables and Refunds on Wholesale Market Transactions

Receivables - California Wholesale Market

As of September 30, 2005, PGE has net accounts receivable balances totaling approximately $63 million from the California ISO and the PX for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to 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 - On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and PX. The order established 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. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court of Appeals has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first considered arguments regarding jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. Briefing and oral argument have been completed on this first phase. As to the jurisdictional issues, on September 6, 2005, the Court ruled that FERC did not have jurisdiction to order municipal utilities and other governmental entities to make refunds for the sales they had made to the ISO and PX that are the subject of the refund proceeding. The Court has not yet issued a decision on the other issues pending in the first phase, and the Court agreed to defer the rehearing deadline on the jurisdictional issue decision until the remainder of the first phase is decided. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before FERC become final and are appealed.

Also on May 12, 2004, 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 liability. 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. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology of the September 24, 2004 order, 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. Partly as a means of limiting its exposure to additional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In August 2005, PGE joined in a settlement agreement resolving issues relating to the allocation of the wind-up costs of the PX for both past and future periods. The settlement has been approved by the FERC. Although under the agreement PGE will bear certain additional costs associated with PX obligations to conduct and finalize refund calculations, PGE does not expect those costs to be material to its financial statements.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. By order issued August 8, 2005, FERC provided guidelines regarding the manner in which these studies should be conducted and the principles that should govern their preparation. PGE filed for rehearing of certain aspects of the August 8 order, and, on September 14, it filed its cost recovery study with FERC. The study showed that, pursuant to the principles set forth in the August 8 order and subject to rehearing, PGE's costs to serve the ISO and PX markets exceeded the revenues PGE will receive from those mitigated sales by over $27 million. The study showed that PGE's refund liability should be reduced by that amount. Reply comments were filed by California parties that contested aspects of PGE's filing and proposed certain revisions that would reduce the refund offset amount to zero. The FERC has indicated that it intends to make decisions on marketers' cost recovery filings by mid-November 2005. Due to the continuing uncertainty related to these matters, PGE has made no adjustment to the $40 million reserve previously established for the Company's potential liability, as described above.

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.

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 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 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. Management 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.

Anomalous Bidding Allegations - By order issued on June 25, 2003, the FERC instituted an investigation into allegations of anomalous bidding activities and practices ("economic withholding") on the part of numerous parties, including PGE. The FERC determined that bids above $250 per MW in the period from May 1, 2000 through October 2, 2000 may have violated tariff provisions of the ISO and the PX. The FERC required companies that bid in excess of $250 per MW to provide information on their bids to the FERC investigation staff. PGE responded to the FERC's inquiries and, on May 12, 2004, the FERC investigation staff issued to PGE a letter terminating the investigation as to the Company without further action. On March 10, 2005, certain California parties filed appeals with the Ninth Circuit Court of Appeals, contesting the FERC's conduct of the investigation of the anomalous bidding allegations and the issuance of the dismissal letters.

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 proceedings 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.

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 rate making 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 reduce 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, together with the Current Class, the Class Action Plaintiffs). 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 (Class Action 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 Class Action Plaintiffs' claims. On December 14, 2004, the Judge granted the Class Action Plaintiffs' motion for Class Certification and Partial Summary Judgment and denied PGE's motion for Summary Judgment. PGE filed a proposed order certifying the issue for an interlocutory appeal. An order rejecting the proposed order was entered on February 1, 2005. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed and seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions and oral arguments were subsequently held. A decision is 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.

On August 31, 2004, the administrative law judge issued an Order (Scoping 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 Scoping Order. On December 20, 2004, the URP and Class Action Plaintiffs filed an application with the OPUC for reconsideration of the Scoping Order. On February 11, 2005, the OPUC denied reconsideration and on April 18, 2005, URP and Linda K. Williams filed a complaint against the OPUC in Marion County Circuit Court challenging the OPUC's affirmation of the Scoping Order. The OPUC filed a motion to dismiss the complaint, and on September 21, 2005, the Marion County Circuit Court granted the OPUC's motion. Hearings in the first phase of the OPUC proceeding have been held, with a decision expected in the early 2006.

Threatened Litigation - Class Action Lawsuit - On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs), stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, PGE's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million. No action has been filed to date.

Management cannot predict the ultimate outcome of the above 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. No reserves have been established by PGE for any amounts related to this issue.

Union Grievances

In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers Local 125 (IBEW), 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 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 to the Oregon Court of Appeals. A decision is pending. Both the U.S. District Court and the Bankruptcy Court approved the settlement of the class action litigation styled In re Enron Corp. Securities Derivative & "ERISA" Litigation, Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action). On September 13, 2005, the U.S. District Court entered a Bar Order in the Tittle Action, which specifically bars all claims arising out of this case including the IBEW grievance proceeding. On October 18, 2005, at the request of the Oregon Court of Appeals, PGE filed a response memorandum in which PGE argued that the Bar Order makes the grievance moot. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Colstrip Plant - Royalty Claim

The Montana Department of Revenue, as agent for the Minerals Management Service of the U.S. Department of the Interior, issued two orders to Western Energy Co. (WECO) in 2002 and 2003. The orders asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip Units 3 and 4. On March 28, 2005, the Appeals Division of the Minerals Management Service of the U.S. Department of the Interior denied in part, and granted in part, WECO's appeals of the orders from the Montana Department of Revenue. WECO transports the coal under a Coal Transportation Agreement with owners of Colstrip Units 3 and 4, in which PGE has a 20% ownership interest. WECO appealed these orders to the Interior Board of Land Appeal of the U.S. Department of the Interior on April 28, 2005. PGE is monitoring the process. Based upon review of the Coal Transportation Agreement, the owners of Colstrip Units 3 and 4 believe they have reasonable defenses against any claims for such royalties and taxes.

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 PRPs 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 the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis PRP.

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 PRPs, 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 PRPs, including PGE. Management cannot predict the ultimate outcome of this matter or estimate any potential loss. However, it believes this matter will not have a material adverse impact on the Company's financial statements.

Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company's power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyl's (PCBs), have been detected at the site. On September 29, 2003, following investigation and site assessment by the EPA, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter starts a period for PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site. Discussions among the EPA and the PRPs, including PGE, have commenced.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Harbor Oil Site or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company's 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. The site investigation has been completed and a report was submitted to the DEQ in August 2005. The report concludes that fuel and related contaminants have not migrated to the Willamette River from the site. Although the DEQ has stated that it is satisfied with the report, it has asked PGE to provide additional information about the Site. 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 (CAA). 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 CAA. 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 oxide emissions. 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 has issued an information request with respect to the Colstrip units. The EPA 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 CAA. 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 Units 3 and 4 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.

New Accounting Standards

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143, was issued in March 2005 and is effective no later than the end of fiscal years ending after December 15, 2005. FIN 47 clarifies that the term "conditional asset retirement obligation" as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated, even though uncertainty exists about the timing and (or) method of settlement. FIN 47 requires recognition of the cumulative effect of initial application as a change in accounting principle and requires disclosure on a pro forma basis in financial statement footnotes as if it had been applied during all periods affected. PGE is evaluating the impact of the application of FIN 47 with respect to its asset retirement obligations.

SFAS No. 154 (SFAS 154), Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3, was issued in June 2005. SFAS 154 changes the requirements for the accounting and reporting of the direct effect of changes in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement that does not include specific transition provisions; when a pronouncement includes specific transition provisions, those provisions should be followed. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in the income statement. SFAS 154, which is effective for fiscal years beginning after December 15, 2005, is not expected to have a material effect on the financial statements of the Company.

FASB Staff Position No. FAS 13-1 (FSP 13-1), Accounting for Rental Costs Incurred during a Construction Period, addresses the accounting for rental costs associated with ground and building operating leases that are incurred during a construction period. FSP 13-1 requires rental costs associated with ground or building operating leases incurred during a construction period to be recognized as rental expense and included in income from continuing operations. The application of FSP 13-1, which is required in the first reporting period beginning after December 15, 2005, is not expected to have a material effect on the financial statements of the Company.

Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. These estimates and assumptions are based on historical experience and other factors that are believed to be reasonable under the circumstances based on the judgment of the Company's management. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The Company's critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2004 Form 10-K and have not changed materially from that discussion.

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," "should," "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 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' bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);
• events related to Enron's Chapter 11 Plan;
• events related to the issuance of new PGE common stock to the Debtors' creditors who hold allowed claims and to the Disputed Claims Reserve;
• 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;
• general political, economic, and financial market conditions; and,
• terrorist activities.

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 (including changes in commodity prices, foreign currency exchange rates, and interest rates), as well as to 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. Gains and losses on instruments used for trading purposes are recognized on a net basis within Operating Revenues on PGE's income statement. (Trading activities were discontinued in early 2005; existing trading transactions will continue to settle through December 31, 2005). 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 losses in fair value due to the 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 non-trading portfolio in the first nine months of 2005 were $3.5 million, $5.1 million, and $1.8 million, respectively, and in the first nine months of 2004 were $1.2 million, $2.3 million, and $0.6 million, respectively.

PGE's non-trading activities are subject to regulation. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and regulatory liabilities to reflect the effects of regulation under SFAS No. 71. As contracts are settled, these deferrals reverse. In its non-trading value at risk, PGE does not reflect any amount of these potential deferrals under SFAS No. 71.

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, 2005, 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.

Interest Rate Risk

Although PGE had no short-term debt outstanding at September 30, 2005, 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, setting limits and monitoring exposures, and 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, 2005, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following table presents PGE's credit exposure for commodity non-trading activities and their subsequent maturity as of September 30, 2005. The table reflects 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	2005	2006	2007	2008	2009	After 2009
Investment Grade	$  400	93%	$  199	$  73	$  208	$ 55	$ 33	$  10	$ 21
Non-Investment Grade	16	4%	15	3	13	-	-	-	-
Internally Rated - Investment Grade	14	3%	8	9	5	-	-	-	-
Total	$  430	100%	$  222	$  85	$  226	$ 55	$ 33	$  10	$ 21

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) which is responsible for providing oversight of the adequacy and effectiveness of the corporate policies, guidelines, and procedures for market and credit risk management related to the Company's energy portfolio management activities. The RMC, which provides quarterly reports to the Audit Committee of PGE's Board of Directors, 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 reviews and recommends for adoption policies and procedures, establishes risk limits subject to PGE Board approval, and monitors compliance with policies, procedures, and limits on a regular basis through reports and meetings.

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

Item 4. Controls and Procedures

1. 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 and are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
2. 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 2004 Annual Report on Form 10-K and other reports filed with the SEC since its 2004 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.

On September 21, 2005, the Marion County Circuit Court granted the OPUC's motion to dismiss the complaint filed by URP and Linda K. Williams challenging the OPUC's affirmation of the Scoping Order issued by the administrative law judge in the three OPUC dockets opened in March 2004 to address the issue of a return on PGE's investment in Trojan.

Gordon v. Reliant Energy, Inc./Duke Energy Trading and Marketing, et al v. Arizona Public Service Company, et al, Superior Court of the State of California for the County of San Diego, Proceeding Nos. 4204 and 4205. In re Wholesale Electricity Antitrust Cases I & II, USDC Southern District of California, Case Nos. CV02-990, 1000, 1001; USCA Ninth Circuit Court of Appeals, Case No. 02-57200, et al.

On October 3, 2005 the trial court issued an Order Sustaining the Demurrer without Leave to Amend & Dismissing the Master Complaint.

David Kafoury, an individual, and Kafoury Brothers, LLC, an Oregon Limited Liability Corporation, each as representative of class, etc. v. Portland General Electric Company, Multnomah County Circuit Court for the State of Oregon, Case No. 0501-00627

On October 5, 2005, the OPUC issued an order in the declaratory ruling docket in which it determined that the rules in question required only that PGE allocate this tax to Multnomah County customers and did not require that PGE calculate it in any particular way. PGE has notified the Court of the Company's intent to voluntarily refund MCBIT (plus interest) to customers and has filed motions requesting the Court's guidance regarding the number of years for which refunds should be made. The Court has established a briefing schedule and set oral argument on the Company's motions for December 12, 2005.

Portland General Electric Company v. International Brotherhood of Electrical Workers, Local No. 125 (Union Grievances). Multnomah County Circuit Court for the State of Oregon, Case No. 0205-05132.

Both the U.S. District Court and the Bankruptcy Court approved the settlement of the class action litigation styled In re Enron Corp. Securities Derivative & "ERISA" Litigation, Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action) and on September 13, 2005, the U.S. District Court entered a Bar Order in the Tittle Action, which specifically bars all claims arising out of that case, including the IBEW grievance proceeding. On October 18, 2005, at the request of the Oregon Court of Appeals, PGE filed a response memorandum in which PGE argued that the Bar Order makes the grievance moot.

Portland General Electric Co. v. City of Glendale (California), United States District Court for the District of Oregon, Case No. 051321

On August 25, 2005, the Company filed a complaint in the U.S. District Court for the District of Oregon against the City of Glendale (Glendale) seeking a declaratory ruling with respect to a long-term power sale and exchange agreement between the Company and Glendale entered into in 1988 which expires in 2012. Under the agreement, Glendale purchases firm system capacity up to 20 MW plus associated energy costs as scheduled by Glendale. Glendale has requested refunds, asserting that its price is capped so the Company cannot charge a price greater than the most expensive generation resource in the Company's inventory. Glendale has also asserted that the shutdown of Trojan was the equivalent of a sale of a Company resource that triggered a duty under the agreement to renegotiate price terms "to avoid a significant distortion in the Parties' bargain." The Company's complaint seeks a declaratory ruling that the Company does not owe Glendale any amounts under the agreement and that the decommissioning of Trojan does not require the Company to renegotiate payments due to it from Glendale. On October 18, 2005, Glendale filed a Complaint with the FERC requesting the FERC to direct the Company to adjust the price and provide refunds of $23,325,059 plus interest. The Court has granted a stipulation filed by PGE and Glendale to stay the Court proceedings pending a decision by the FERC on its jurisdiction.

Item 6. Exhibits

(3) Articles of Incorporation and Bylaws

3.1 * Articles of Incorporation of Portland General Electric Company [Registration No. 2-78085, Exhibit (4)].

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 (Form 10-K for the fiscal year ended December 31, 1987, Exhibit (3)].

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) [Registration Statement No. 33-46357, Exhibit (4)(a)].

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 [Form 10-Q for the quarter ended September 30, 2002, Exhibit (3)].

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

(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 (filed herewith).

31.2 Certification of Chief Financial Officer of Portland General Electric Company (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 4, 2005	By:	/s/ James J. Piro
			James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer

Date:	November 4, 2005	By:	/s/ Kirk M. Stevens
			Kirk M. Stevens Controller and Assistant Treasurer