UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 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 Act). Yes          No    X    

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of July 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	66
	Item 4. Controls and Procedures	70
PART II. Other Information
	Item 1. Legal Proceedings	71
	Item 6. Exhibits	73
	Signatures	75

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	Energy 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
MWh	Megawatt-hour
NRC	Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange
OPUC or the Commission	Public Utility Commission of Oregon
Oregon Electric	Oregon Electric Utility Company, LLC
PBGC	Pension Benefit Guaranty Corporation
PGC	Portland General Corporation
PGE or the Company	Portland General Electric Company
Port Westward	Port Westward Generating Plant
PRP	Potentially Responsible Party
PUHCA	Public Utility Holding Company Act of 1935
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board
Trojan	Trojan Nuclear Plant
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 June 30,						Six Months Ended June 30,
		2005			2004			2005					2004
		(In Millions)
Operating Revenues		$	333		$	332		$			704		$			727
Operating Expenses
	Purchased power and fuel		131			133			273						311
	Production and distribution		34			36			62						65
	Administrative and other		47			35			85						70
	Depreciation and amortization		58			57			118						116
	Taxes other than income taxes		18			17			38						37
	Income taxes		13			16			43						42
			301			294			619						641
Net Operating Income			32			38			85						86
Other Income
	Miscellaneous		1			1			3						3
	Income taxes		-			1			1						1
			1			2			4						4
Interest Charges
	Interest on long-term debt and other		17			18			35						36
Net Income		$	16		$	22	$		54			$			54
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 June 30,					Six Months Ended June 30,
		2005		2004			2005							2004
		(In Millions)
Balance at Beginning of Period		$	675		$	577	$		637			$			545
Net Income			16			22					54					54
			691			599					691					599
Dividends Declared		-			-		-						-
Balance at End of Period		$	691		$	599	$			691			$			599
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										Six Months Ended
			June 30,										June 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			$	4		$		5			$			(2)			$		2
	Minimum pension liability adjustment				(4)			(4)						(4)						(4)
	Total			$	-		$	1			$			(6)		$				(2)
Net Income				$	16		$	22			$				54	$				54
Other comprehensive income, net of tax:
	Unrealized gains (losses) on derivatives classified as cash flow   hedges:
		Other unrealized holding net gains (losses) arising during the
		period, net of related taxes of $5 and $(4) for the three
		months ended June 30, 2005 and 2004 and $(25) and $(7)
		for the six months ended June 30, 2005 and 2004		(9)			6				38					12
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $8 and $1 for the three months ended June 30, 2005 and June 30, 2004 and $8
		and $2 for the six months ended June 30, 2005 and 2004		(13)			(2)				(12)					(4)
		Reclassification adjustment in net income due to discontinuance
		of cash flow hedges, net of related taxes of $1		-			-				(1)					-
		Reclassification of unrealized gains (losses) to SFAS No. 71
		regulatory (liability) asset, net of related taxes of $(11) and $2
		for the three months ended June 30, 2005 and 2004 and $15
		and $3 for the six months ended June 30, 2005 and 2004		19			(3)				(22)					(4)
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		(3)			1				3					4
	Minimum pension liability adjustment			-			-				-					-
		Total Other comprehensive income (loss)		(3)			1				3					4
Comprehensive income				$	13		$			23	$				57	$			58
Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain on derivatives classified as cash flow hedges			$	1		$			6	$				1		$			6
	Minimum pension liability adjustment			(4)			(4)				(4)					(4)
Total				$		(3)	$			2	$				(3)	$			2
The accompanying notes are an integral part of these consolidated financial statements.

Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)
					June 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 $133 and $114)				$	4,114		$	3,992
	Accumulated depreciation				(1,752)			(1,717)
					2,362			2,275
Other Property and Investments
	Nuclear decommissioning trust, at market value				24			22
	Non-qualified benefit plan trust				69			64
	Miscellaneous				31			30
					124			116
Current Assets
	Cash and cash equivalents				260			204
	Accounts and notes receivable (less allowance for uncollectible accounts
		of $50 and $50)			167			170
	Unbilled revenues				49			80
	Assets from price risk management activities				148			77
	Inventories, at average cost				50			48
	Margin deposits				2			-
	Prepayments and other				101			113
					777			692
Deferred Charges
	Regulatory assets				257			295
	Miscellaneous				25			25
					282			320
					$	3,545		$	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				691			637
	Accumulated other comprehensive income (loss):
			Unrealized gain (loss) on derivatives classified as cash flow hedges		1			(2)
			Minimum pension liability adjustment		(4)			(4)
	Limited voting junior preferred stock				-			-
	Long-term obligations				884			892
					2,214			2,164
Commitments and Contingencies (see Notes)
Current Liabilities
	Long-term debt due within one year				30			30
	Accounts payable and other accruals				152			182
	Liabilities from price risk management activities				58			38
	Customer deposits				48			18
	Accrued interest				18			19
	Accrued taxes				39			37
	Deferred income taxes				36			15
					381			339
Other
	Deferred income taxes				258			308
	Deferred investment tax credits				11			13
	Trojan asset retirement obligation				104			96
	Accumulated asset retirement obligation				17			16
	Regulatory liabilities:
			Accumulated asset retirement removal costs		324			286
			Other		116			74
	Non-qualified benefit plan liabilities				78			70
	Miscellaneous				42			37
					950			900
					$	3,545		$	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)
			Six Months Ended
			June 30,
			2005		2004
			(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
	Net income		$	54	$	54
	Non-cash items included in net income:
		Depreciation and amortization	118		116
		Deferred income taxes	(30)		(5)
		Net assets from price risk management activities	(10)		(19)
		Power cost adjustment	9		20
		Other non-cash income and expenses (net)	(7)		15
	Changes in working capital:
		Net deposit activity	28		17
		Decrease in receivables	35		52
		Decrease in payables	(41)		(60)
		Other working capital items - net	30		(4)
	Other - net		14		2
Net Cash Provided by Operating Activities			200		188
Cash Flows From Investing Activities:
	Capital expenditures		(128)		(82)
	Other - net		(8)		4
Net Cash Used in Investing Activities			(136)		(78)
Cash Flows From Financing Activities:
	Repayment of long-term debt		(8)		(13)
Net Cash Used in Financing Activities			(8)		(13)
Increase in Cash and Cash Equivalents			56		97
Cash and Cash Equivalents, Beginning of Period			204		109
Cash and Cash Equivalents, End of Period			$	260	$	206
Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	29	$	31
		Income taxes	66		58
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. 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.

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). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions made to a Voluntary Employees' Beneficiary Association (VEBA) trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers. 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 but does not currently expect to make contributions to any of the other plans described above during the year.

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

Three Months Ended June 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	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	7		6		1		1		1		1
Expected return on plan assets	(10)		(10)		-		-		-		-
Amortization of transition asset	-		(1)		-		-		-		-
Amortization of prior service cost	-		1		-		-		-		-
Recognized (gain) loss		-		-		-		-		-		-
Net periodic benefit cost (income)	$	-	$	(1)	$	1	$	1	$	1	$	1
Six Months Ended June 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	$	6	$	6	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	14		12		1		1		2		2
Expected return on plan assets	(20)		(20)		-		-		-		-
Amortization of transition asset	-		(1)		-		-		-		-
Amortization of prior service cost	-		1		-		-		-		-
Recognized (gain) loss		-		-		-		-		-		-
Net periodic benefit cost (income)	$	-	$	(2)	$	1	$	1	$	2	$	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 its retail customers. PGE formerly used such instruments in electricity and natural gas trading (non-retail) activities, which were discontinued in early-2005. 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.

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

For energy trading (non-retail) activities, PGE reports all unrealized and realized gains and losses 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.

In the first half of 2005, PGE recorded $11 million in net unrealized gains in earnings in its retail portfolio, including $4 million in net unrealized losses in the second quarter. In addition, a $1 million gain was recorded due to a reduction in the SFAS No. 71 regulatory liability. In the first half of 2004, PGE recorded $20 million in net unrealized gains in earnings in its retail portfolio, including $12 million in net unrealized gains in the second quarter. The net unrealized gain in the first half of 2004 was partially offset by recording a $19 million SFAS No. 71 regulatory liability.

Derivative activities recorded in OCI for the three- and six-month periods ended June 30, 2005 from cash flow hedges consisted of $14 million of unrealized losses and $63 million of unrealized gains, respectively, from new contracts and changes in fair value; such amounts were partially offset by $21 million and $20 million, respectively, in net gains reclassified for contracts that settled during the three- and six-month periods. Net gains of $2 million were recorded in the first half of 2005 for the discontinuance of cash flow hedges due to the probability that the original forecasted transactions will not occur. A $37 million SFAS No. 71 regulatory liability was recorded in the first half of 2005.

Derivative activities recorded in OCI for the three- and six-month periods ended June 30, 2004 from cash flow hedges consist of unrealized gains of $10 million and $19 million, respectively, from new contracts and changes in fair value, partially offset by $3 million and $6 million, respectively, in net gains reclassified in earnings for contracts that settled during the three- and six-month periods. A $7 million SFAS No. 71 regulatory liability was recorded in the first half of 2004.

Hedge ineffectiveness from cash flow hedges was not material in the first half of 2005 and 2004. As of June 30, 2005, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 75 months. The Company estimates that of the $55 million of net unrealized gains at June 30, 2005, $35 million will be reclassified into earnings within the next twelve months (partially offset by a $34 million SFAS No. 71 regulatory liability), and $20 million will be reclassified over the remaining 63 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 six-month periods ended June 30, 2005 and 2004:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Trading Activities (In Millions)
Unrealized Gain (Loss)	$	-	$	-	$	(1)	$	(1)
Realized Gain (Loss)		-		1		1		2
Net Gain (Loss) in Operating Revenues	$	-	$	1	$	-	$	1
Electricity Trading - MWhs (thousands)
Sales	88		2,186		574		5,562
Purchases	88		2,186		574		5,562

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, beginning in October 2000. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. Authorized collection of decommissioning costs of Trojan is unaffected by the settlement agreements or the OPUC orders.

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

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Plaintiff's claims. 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. Oral argument before the Oregon Supreme Court is currently scheduled for September 2005.

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

On August 31, 2004, the administrative law judge issued an Order (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.

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 (MBIT) 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 MBIT 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 MBIT 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 MBIT and, if not, whether refunds are controlled by the OPUC three-year limitation for billing adjustments. Proceedings are in process and a decision from the OPUC is expected this fall. 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. Management cannot predict the ultimate outcome of this matter.

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 Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision. A decision is pending. Additionally, if 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) is approved by the U.S. District Court and the Bankruptcy Court, the claims based on the grievances will be barred. The IBEW has objected to the proposed bar. The U.S. District Court and the Bankruptcy Court are scheduled to hold simultaneous hearings on the Tittle Action, including consideration of any objections, in September 2005. 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, related to the Harbor Oil site. PGE was one of fourteen companies named as PRPs with respect to the Harbor Oil site. The letter starts a 60-day period for PRPs to participate in formal negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site.

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 will be 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. 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):

			June 30, 2005	December 31, 2004
Receivables from affiliated companies
	Enron Subsidiaries:
		Portland General Holdings, Inc. - in Bankruptcy
		Accounts Receivable(a)	$  5	$  5
		Other Allowance for Uncollectible Accounts (a)	(1)	(1)
		PGH II and its subsidiaries - not in Bankruptcy
		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)	19	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 Six Months Ended June 30			2005	2004
Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services(a)	$ 2	$12
(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 $19 million income taxes payable to Enron at June 30, 2005 represents a net current income taxes payable for the second quarter of 2005 that was paid to Enron in July 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 and, as long as PGE is a subsidiary of a registered holding company under PUHCA, the SEC. Under OPUC regulations, services provided to affiliates by PGE are charged at the higher of cost or market, while affiliated services received by PGE are charged at the lower of cost or market. Under SEC regulations, both services provided to, and received from, affiliates are charged at cost. Services will be provided at cost unless there is a conflict between OPUC and SEC regulations, in which case PGE and Enron have agreed not to provide the services until the matter can be resolved.

Enron - Beginning 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 six months of 2005, Enron billed PGE approximately $2 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 $12 million, consisting of $11 million for medical/dental benefits and retirement savings plan matching, and $1 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 during the first six months of 2005 as work continues toward resolution of the issues. At June 30, 2005, PGE had $3 million payable to Enron related to these costs, including approximately $1 million incurred in 2005.

Portland General Holdings, Inc. - in Bankruptcy - On June 27, 2003, PGH, a wholly owned subsidiary of Enron located in Portland, filed to initiate bankruptcy proceedings under the federal Bankruptcy Code. The PGH filing 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. PGH continues to operate its business and manage its properties as a debtor in possession under the Bankruptcy Code. Substantially all assets of PGH have been distributed or placed in segregated accounts. Accordingly, PGH has moved the Bankruptcy Court to dismiss its Chapter 11 case. A hearing on the motion to dismiss is scheduled on September 15, 2005.

At June 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. PGE will continue to assess the collectibility of this receivable.

PGH Non-Qualified Benefit Plans - In 1983, PGE adopted certain non-qualified deferred compensation arrangements and associated "rabbi" trusts for the benefit of key employees, officers, and directors. PGE, as well as affiliated companies PGC, PGH, and certain of their subsidiary companies, had employees who participated in these plans.

Upon the bankruptcy filing by Enron and certain of its affiliates, and the subsequent bankruptcy filing of PGH, payment by those companies of participant benefits earned under the plans by employees of those companies ceased. Plan participants with benefits due from the bankrupt companies sought to have the companies or the trusts commence payments without success. Certain PGH plan participants indicated their intention to commence a lawsuit against PGE and other parties if they were unable to reach a resolution with respect to their benefit payments.

Enron and representatives of the PGH plan participants reached a settlement that was approved by the Bankruptcy Court on February 24, 2005. On April 4, 2005, PGE received $8.4 million (net of tax), including $1 million for ongoing trustee and administrative fees and taxes, in exchange for the Company's assumption of the liabilities to the participants, totaling $6.9 million on a present value basis. PGE established a Non-Qualified Benefit Plan Trust for Transferred Liabilities to hold the transferred funds and adopted three new non-qualified plans for payment of the benefits to the former PGH plan participants.

PGH II and its Subsidiary - not in Bankruptcy - 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 are 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.

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 June 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 federally-mandated 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 will consider 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. 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 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. In December 2004, the FERC requested comments regarding the manner in which such studies should be conducted and the principles that should control. PGE and numerous other parties filed comments and reply comments. Comments in support of aspects of PGE's position were filed by the Oregon and Washington public utility commissions and by the Oregon and Washington senate delegations. A decision by the FERC to adopt PGE's approach to these studies could reduce the Company's ultimate refund liability.

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. PGE is not included in the bankruptcy, but the common stock of PGE held by Enron is part of the bankruptcy estate.

Enron and its debtor-in-possession subsidiaries (collectively the Debtors) filed their Chapter 11 plan (the Chapter 11 Plan) and related disclosure statement (the Disclosure Statement) with the Bankruptcy Court. The Chapter 11 Plan and Disclosure Statement, as amended, provide information about the assets that are in the bankruptcy estate, including the common stock of PGE, and how those assets will be distributed to the creditors. The Chapter 11 Plan was confirmed by the Bankruptcy Court on July 15, 2004 and it became effective on November 17, 2004.

On March 10, 2005, the OPUC issued an order in which it denied the application of Oregon Electric Utility Company, LLC (Oregon Electric) to purchase PGE and on April 6, 2005, Enron announced that it had reached an agreement with Oregon Electric to terminate the sale agreement for PGE. As a result, Enron announced that in accordance with the Chapter 11 Plan, new shares of PGE's common stock will be issued over time to the Debtor's creditors that hold allowed claims. For further information, see "Future Ownership of PGE" below.

Management cannot predict with certainty what impact the Chapter 11 Plan may have on PGE. However, the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy.

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

1. Amounts Due from Enron and Enron-Supported Affiliates in Bankruptcy - On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts representing intercompany obligations between PGE and Enron and its bankrupt subsidiaries arising prior to the commencement of the bankruptcy case. In December 2004, PGE made a distribution to Enron of all pre-petition amounts owed by Enron and its affiliates, and related proofs of claim, except for those related to PGH. The distribution was made in an effort to eliminate all pre-petition intercompany balances from PGE's books in order to remove the uncertainties regarding the value of the proofs of claim. Following the distribution, PGE's balance sheet at December 31, 2004 was cleared of all pre-petition intercompany balances with Enron and its affiliates, with the exception of PGH. As of June 30, 2005, PGE has outstanding accounts receivable of $5 million due from PGH which is part of the Enron bankruptcy proceedings. Based on management's assessment of the realizability of accounts receivable from PGH, a reserve of $1 million has been established.
2. Controlled Group Liability - Enron's bankruptcy has raised questions regarding potential PGE liability for certain employee benefit plan and tax obligations of Enron.

Pension Plans

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). PBGC has informed the Debtors that it 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 it 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 PBGC seeking to assert its UBL Claims against Enron's affiliates as set forth below with respect to controlled group liability. Except for one PBGC premium which is not material, the Debtors are current on their PBGC premiums and their minimum funding contributions to the Pension Plans. Therefore, the Debtors' value the Premium Claims and the Contribution Claims at $0. Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has not provided support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

Because the Enron Plan is underfunded, in certain circumstances the Enron Plan may be terminated and taken control of by the PBGC upon approval of a Federal District Court. In addition, with consent of the PBGC, Enron could seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.

Upon termination of an underfunded pension plan, all of the members of the ERISA controlled group of the plan sponsor become jointly and severally liable for the plan's underfunding. The PBGC can demand payment from one or more of the members of the controlled group. If payment is not made, a lien in favor of the PBGC automatically arises against 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 January 30, 2004, the Bankruptcy Court entered the order authorizing Enron and certain of its affiliated Debtors to contribute $200 million to the Pension Plans and terminate them in a manner that should eliminate the PBGC's claims. However, there can be no assurance that Enron will have the ability to obtain funding for accrued benefits on acceptable terms, that certain funding contingencies will be met, or that the required government agencies that review pension plan terminations will approve the termination of the Pension Plans. If the proposal to fund and terminate the Enron Plan is approved and consummated, it should eliminate any need for the PBGC to attempt to collect from PGE any liability related to the Enron Plan.

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

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

Unless and until the District Court authorizes the PBGC to terminate the Pension Plans and the PBGC makes a demand on PGE to pay some or all of any unfunded benefit liabilities under the Pension Plans, which would not occur unless the Proposed Pension Settlement (discussed below) is not approved by both the District and Bankruptcy Courts or the parties do not satisfy the terms of the Proposed Pension Settlement, PGE has no liability for the unfunded benefit liabilities and no termination liens arise against any PGE property.

Proposed Settlement

In July 2005, Enron filed a motion with the Bankruptcy Court seeking approval of a settlement (Settlement) with the PBGC and the plaintiffs in 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 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 will proceed 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 would 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 and Enron's objection to such PBGC claims has been stayed. On July 26, 2005, the District Court preliminarily approved the Settlement. A joint hearing between the District Court and the Bankruptcy Court to consider approval of the Settlement is scheduled to be held in September 2005.

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

Retiree Health Benefits

PGE management understands, based on discussions with Enron management, that Enron maintains a group health plan for certain of its retirees. If retirees of Enron lose coverage under Enron's group health plan for retirees due to Enron's bankruptcy proceedings, the retirees must be provided the opportunity to purchase continuing coverage (known as COBRA Coverage) from an Enron group health plan, if any, or the appropriate group health plan of another member of 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.

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

Income Taxes

Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax allocation agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. Due to the uncertainty with the reconsolidation during 2003, PGE held certain tax payments due Enron. Enron obtained an agreement from the IRS on February 2, 2004 stipulating that PGE did become a member of the Enron consolidated group on December 24, 2002. PGE resumed tax payments due Enron in early 2004.

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

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. For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. A net operating loss for the year 2002 is expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from future IRS audits for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.
3. Enron's 2003 tax return was filed on September 14, 2004. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2003. Enron had 2003 NOLs sufficient to eliminate Enron's regular income tax and alternative minimum income tax liabilities for 2003. Enron expects to file its 2004 tax return on or before September 15, 2005 and expects to have sufficient NOLs to eliminate its regular income tax for 2004, but could possibly be subject to the 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.

On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million with respect to income tax, interest, and penalties for taxable years in which PGE was included in Enron's consolidated tax return. The IRS subsequently amended the proof of claim to $43.6 million. The IRS and Enron reached a settlement on Enron's 1996-2001 tax liability on January 5, 2005. The settlement, which indicates no net taxes due by Enron to the IRS, eliminates any further assessment of tax, interest or penalties for the years 1996-2001 against any member of the consolidated group in those years in excess of the overpayment currently held by the IRS.

With respect to periods after 2001, the Company 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.

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

Future Ownership of PGE

On April 6, 2005, following the OPUC's denial of Oregon Electric's application to buy PGE's common stock from Enron, Enron and Oregon Electric terminated their sale agreement.

Enron has announced that it intends to move forward to issue 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 Debtor's creditors that hold allowed claims, with the remainder issued to a Disputed Claims Reserve where it will be held in trust/escrow, to be released over time to the Debtor's creditors holding allowed claims in accordance with the Chapter 11 Plan. Following issuance of the new PGE common stock to the Debtor's creditors and the Disputed Claims Reserve, PGE will no longer be a subsidiary of Enron.

The registered owner of the new PGE common stock held in the Disputed Claims Reserve will be Steven Forbes Cooper, LLC, as Disbursing Agent. The Disbursing Agent will oversee the release of new PGE common stock from the Disputed Claims Reserve to Debtor's creditors that hold allowed claims. All shares of new PGE common stock held in the Disputed Claims Reserve will be voted by the Disputed Claims Reserve Overseers (DCRO). Initially, the DCRO is comprised of the same individuals who currently 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 SEC, the Nuclear Regulatory Commission (NRC), and certain other regulatory agencies. Applications for approval to issue shares of new PGE stock to Enron's creditors have been filed with the OPUC (on June 17, 2005), and the NRC (on July 12, 2005). An application was filed with the SEC on July 19, 2005 seeking authorization under the Public Utility Holding Company Act of 1935 (PUHCA) for Enron to divest PGE. If the Domenici-Barton Energy Policy Act of 2005 is enacted, PUHCA will be repealed effective six months from the date of enactment. Assuming enactment in the near future, SEC authorization will not be needed and the SEC application may be withdrawn.

Enron has indicated that, if all regulatory approvals are received, 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 Enron's 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 Disputed Claims Reserve will be the responsibility of the DCRO, in accordance with guidelines prescribed by the Bankruptcy Court.

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.

Note 9 - Credit Facilities and Debt

On May 27, 2005, PGE entered into a $400 million five-year, unsecured, revolving credit facility with a group of commercial banks. The facility is available for general corporate purposes and replaced the Company's $50 million 364-day and $100 million three-year revolving credit facilities. The maximum amount of the facility is available to PGE for borrowings and/or the issuance of standby letters of credit. The facility allows the Company to borrow for one, two, three or six months at a fixed interest rate established at the time of the borrowing or at a variable interest rate for any period up to the then remaining term of the facility. The facility provides that all outstanding loans mature on the termination date of the facility, provided that the Company may annually extend the termination date for an additional year upon approval of the lenders holding a majority of the total commitments under the facility. The facility requires annual fees based on PGE's unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. At June 30, 2005, PGE was in compliance with these covenants.

Note 10 - Commitments

Purchase Commitments

In an order issued June 21, 2005, the FERC approved a 50-year joint license application for the Pelton Round Butte hydro project filed by PGE and the Confederated Tribes of the Warm Springs Reservation of Oregon, the project's co-owners. The order also approved a settlement agreement, previously completed and signed by all participating parties, that includes provisions for fish passage over the project's three dams. PGE's ownership share of project commitments associated with the settlement agreement total approximately $66 million as of June 30, 2005, reflecting estimated payments of $3 million in 2005, $17 million in both 2006 and 2007, $5 million in 2008, $2 million in 2009, and $22 million over the remaining years.

Natural Gas Storage

PGE has entered into a ten-year natural gas storage agreement for the purpose of fueling the Company's Port Westward and Beaver generating plants located adjacent to the storage facility. The agreement, which becomes effective May 1, 2007, requires annual payments of approximately $3.6 million over the term of the agreement.

Coal and Transportation Agreements

PGE has coal and related rail transportation agreements with take-or-pay provisions for the purpose of fueling the Company's Boardman plant. The Company has entered into a new three-year coal agreement, covering the years 2006-2008; the rail transportation agreements extend through 2013. Total payments under these agreements are estimated at $13 million annually in both 2006 and 2007, $14 million in 2008, and approximately $3 million annually from 2009 through 2013.

Note 11 - Subsequent Events

Common Stock Dividend

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 Pension Plan

On August 2, 2005, PGE made a transfer from PGE's Pension Plan of $2.7 million in pension assets to Enron Corp.'s Cash Balance Plan to reflect a net exchange of assets and benefit obligations. The transfer was made pursuant to an agreement between PGE and Enron to exchange pension assets and benefit obligations between the Plans for benefits earned by certain individuals. These exchanges consolidated benefits for those individuals in one plan or the other, where the individuals changed employers and as a result had ceased earning benefits under one Plan and began earning benefits under the other Plan.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Overview

Operations - Effective operation of the Company's generating assets and activities in the wholesale marketplace, as well as an improved local economy, partially offset the effects of this year's below normal hydro conditions. The Company continues to maintain investment-grade ratings on its debt (Moody's raised its ratings on PGE's secured and unsecured debt in June 2005) and the Company has put in place a new five-year, $400 million unsecured revolving credit facility, providing further access to capital for system improvements. In July 2005, PGE declared and paid a $150 million cash dividend to Enron, the sole shareholder of the Company's common stock.

Retail loads during the first half of 2005 fell somewhat below both current year projections and last year's first half due to warmer-than-normal weather. On a weather-adjusted basis, however, total retail energy deliveries increased by about 1% from last year's first half due to customer growth within PGE's service territory.

In May 2005, following the completion of radiological decommissioning of Trojan (including removal of all large radioactive components from the site and the transfer of spent fuel to interim dry storage), the NRC formally approved the termination of the plant's operating license and released the plant site for unrestricted use. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site, storage facility decontamination is completed, and the storage installation is fully decommissioned. PGE has accelerated the planned demolition of major non-radiological structures at Trojan, including the cooling tower and those buildings that once housed the plant's turbine, reactor, and spent fuel pool.

Economy - Although Oregon's economy slowed somewhat in the second quarter this year, the momentum experienced last year has generally continued through the first half of 2005. Although the state's unemployment rate remains high, Oregon continues to rank among the nation's leaders in employment growth, with nearly 26,000 new jobs (including 4,000 in manufacturing) added through June 2005. Non-farm employment (seasonally adjusted) in June 2005 exceeded the previous peak set in late 2000. PGE continues to experience customer growth, adding over 9,500 retail customers in this year's first half, 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.

Power Supply - Despite above average rainfall during this year's second quarter, regional hydro conditions remain below normal for the year. Current projections indicate a continued shortfall from normal levels, with "moderate drought" conditions expected to continue in the Northwest. Both the Clackamas and Deschutes river systems, where PGE's hydro generation facilities are located, are projected to remain below normal. During the first half 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.

During the second quarter of 2005, PGE filed preliminary estimates with the OPUC of the Company's projected 2006 power costs under the Resource Valuation Mechanism process. Current projections, which will be finalized in November, indicate an approximate 3% to 4% average retail price increase (including the effect of all credits and adjustments), beginning next year. The Company's proposed Hydro Generation Adjustment tariff, which would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions, as well as a hydro cost deferral application for 2005, have been filed with the Commission and remain pending.

PGE's generating plants continue to operate well, with required annual maintenance completed at the Company's thermal facilities during the year's first half. In June 2005, the FERC approved a 50-year joint license application for the Pelton Round Butte hydro project, which continues to provide a low-cost source of power for PGE customers. Construction of the Company's 350 MWa natural gas-fired plant at Port Westward is proceeding, with the plant 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.

Future Ownership of PGE - Following OPUC denial of the proposed sale of PGE to Oregon Electric, and the subsequent termination of the sale agreement, Enron announced its intent to move forward with the issuance of PGE common stock to the Debtor's creditors that hold allowed claims, in accordance with Enron's bankruptcy plan. The issuance is not expected to occur until April 2006. 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 June 30

PGE's net income in the second quarter of 2005 was $16 million compared to $22 million in the second quarter of 2004. The decrease was due primarily to the effect of higher administrative and general expenses, including the settlement of certain asserted claims and increased employee benefit expenses. This was partially offset by 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 poor regional hydro conditions.

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

			Three Months Ended June 30,
Operating Revenues			2005	2004	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 304	$ 305	$    (1)
		Direct Access Customer Revenues	-	1	(1)
Total Retail Revenues			304	306	(2)
Wholesale (Non-Trading)			25	17	8
Other Operating Revenues:
	Trading Activities - net		-	1	(1)
	Other		4	8	(4)
Total Operating Revenues			$ 333	$ 332	$     1
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		4,040	4,131	(91)
	Energy Delivered to Direct Access Customers		306	197	109
Total Retail Energy Deliveries			4,346	4,328	18
Wholesale (Non-Trading)			467	498	(31)
Trading Activities			88	2,186	(2,098)
Total Energy Sold and Delivered			4,901	7,012	(2,111)

Total Retail Revenues decreased slightly from last year's second quarter as the result of lower retail energy sales. However, Total Retail Energy Deliveries increased slightly. Retail energy sales decreased 2.2%, as 7% and 5% decreases in industrial and commercial sales, respectively, were only partially offset by a 3.4% increase in residential sales (due in part to cooler April weather). The decline in commercial and industrial energy sales was largely attributable to a corresponding increase in energy delivered to customers that purchase their energy requirements from ESSs (as provided by Oregon's electricity restructuring law), including a single large industrial customer that accounted for about one-third of the increase. An approximate 13,000 increase in the average number of customers served and a 1.4% average rate increase for 2005 also partially offset the above reductions in commercial and industrial energy sales during this year's second quarter. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2. for further information).

Direct Access Customer Revenues consist of service charges for energy delivered to commercial and industrial customers who have selected direct access and energy supply from ESSs. The decrease in Direct Access Customer Revenues in this year's second quarter was attributable to "transition adjustment" credits for ESS customers, which reflect the difference between the cost and the market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Wholesale revenues increased by about 47% from last year's second quarter due primarily to a 57% increase in average price, driven largely by higher natural gas prices. This was partially offset by an approximate 6% reduction in wholesale electricity sales.

The decrease in Other Operating Revenues from last year's second quarter was caused primarily by reduced margins on the sale of natural gas in excess of generating plant requirements and by decreased revenue from the sale of transmission capacity not currently required to serve existing load.

Purchased Power and Fuel expense decreased $2 million (2%) from last year's second quarter. The decrease was due to an approximate 3% reduction in PGE's average variable power cost for the quarter, due primarily to an 86% increase in low-cost generation from the Boardman coal plant, which operated for only part of last year's second quarter due to an extended maintenance outage. A reduction in wholesale power purchased to meet a lower total system load requirement also contributed to the decrease. Company generation increased about 22% from that of last year's second quarter due to increased coal-fired generation. PGE hydro production approximated that of last year's second quarter. Total generation met approximately 40% of PGE's retail load during the second quarter of 2005, compared to 32% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the second quarter of 2005 and 2004.

		Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)			Average Variable Power Cost (Mills/kWh)
	2005		2004	2005	2004
Generation	1,701		1,399	12.7	15.6
Term Purchases	2,895		3,348	34.3	29.3
Spot Purchases	163		77	51.3	36.3
Total Send-Out	4,759		4,824	28.5*	29.3*

(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $10 million (14%) from the second quarter of 2004 primarily due to the settlement of certain asserted claims. In addition, employee benefit expenses (including medical and pension costs) increased from the second quarter of last year.

Income taxes decreased $4 million primarily due to lower taxable income.

2005 Compared to 2004 for the Six Months Ended June 30

PGE's net income in the first half of 2005 was $54 million, unchanged from the first half of 2004. Improved margins on energy sales, resulting from operations of the Company's thermal generating assets and activities in the wholesale marketplace, were offset by higher administrative and general expenses, including the settlement of certain asserted claims and increased employee benefit expenses.

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

			Six Months Ended June 30,
Operating Revenues			2005	2004	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 641	$ 651	$    (10)
		Direct Access Customer Revenues	-	3	(3)
Total Retail Revenues			641	654	(13)
Wholesale (Non-Trading)			52	56	(4)
Other Operating Revenues:
	Trading Activities - net		-	1	(1)
	Other		11	16	(5)
Total Operating Revenues			$ 704	$ 727	$   (23)
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		8,564	8,762	(198)
	Energy Delivered to Direct Access Customers		588	372	216
Total Retail Energy Deliveries			9,152	9,134	18
Wholesale (Non-Trading)			1,080	1,425	(345)
Trading Activities			574	5,562	(4,988)
Total Energy Sold and Delivered			10,806	16,121	(5,315)

Total Retail Revenues decreased about 2% from the first half of last year, primarily as the result of lower retail energy sales. However, Total Retail Energy Deliveries increased slightly. Retail energy sales decreased 2.3%, as all major customer classes saw a reduction in use from the first half of 2004. Decreases in industrial and commercial energy sales of 3.9% and 2.9%, respectively, were largely attributable to a corresponding increase in energy delivered to customers of ESSs, including a single large industrial customer that accounted for about one-third of the increase. Residential energy sales declined 1%, as warmer weather in this year's first quarter was only partially offset by an increase in customers served and cooler weather in April. A 1.4% average rate increase for 2005 also partially offset the above reductions in energy sales during the first half of this year. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2. for further information).

Direct Access Customer Revenues consist of service charges for energy delivered to commercial and industrial customers who have selected direct access and energy supply from ESSs. The decrease in Direct Access Customer Revenues in this year's first half was attributable to "transition adjustment" credits for ESS customers, which reflect the difference between the cost and the market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Wholesale revenues decreased by about 7% from last year's first half due to a 24% reduction in wholesale electricity sales resulting from reduced market activity. This was partially offset by an approximate 23% increase in average prices, resulting from both higher natural gas prices and a reduction in regional hydro availability.

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 half of 2005.

Purchased Power and Fuel expense decreased $38 million (12%) from the first half of last year. The decrease was due primarily to a reduction in wholesale power purchased to meet a lower total system load requirement and to a decrease in PGE's average variable power cost, due largely to a 24% increase in low-cost coal-fired generation, primarily from the Boardman plant. In addition, higher unrealized gains from derivative instruments contributed to a decrease from last year's first half (for further information, see "Power and Fuel Supply - Price Risk Management" in "Financial and Operating Outlook" of this Item 2). Purchased Power and Fuel costs in the first half of 2005 and 2004 included charges of $9 million and $21 million, respectively, for amortization of costs deferred under power cost adjustment mechanisms in effect during 2001 and 2002, which were later recovered from customers. Company generation increased about 4% from that of last year's first half, with higher thermal generation partially offset by 16% lower hydro production. Total generation met approximately 43% of PGE's retail load during the first half of 2005, compared to 41% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the first six months of 2005 and 2004. Average variable power costs exclude the effect of provisions for uncollectible wholesale accounts receivable.

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)
	2005	2004	2005	2004
Generation	3,916	3,777	11.3	13.8
Term Purchases	6,039	6,473	32.1	32.2
Spot Purchases	320	476	34.6	39.1
Total System Load	10,275	10,726	26.8*	30.0*
(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $12 million (9%) from the first half of 2004 primarily due to the settlement of certain asserted claims. In addition, employee benefit expenses (including medical and pension costs) increased from the first half of last year. Reduced expenses related to last year's extended maintenance outage at Boardman and a first-quarter snow and ice storm were partially offset by increased distribution maintenance expenses incurred in the first half of 2005.

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 $200 million in the first half of 2005 compared to $188 million in the same period last year. The increase was due primarily to a $27 million reduction in payments for power and fuel purchases, an $11 million increase in deposits (primarily cash collateral received from certain wholesale customers), the liquidation of a $10 million investment in debt securities, and a $2 million decrease in interest payments. These items were partially offset by a $30 million decrease in amounts received for electricity sales and an $8 million increase in income tax payments to Enron.

Cash from operations was invested primarily in government money market funds and short-term commercial paper at June 30, 2005. 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) within guidelines approved by PGE's Board of Directors.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. The $46 million increase in capital expenditures in the first half 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 half of 2005, PGE repaid $5 million of conservation bonds and retired $3 million of preferred stock. No cash dividends on common stock were declared or paid in the first or second quarters of 2005 or 2004. However, a $150 million cash dividend was declared and paid in July 2005 (see "Cash Requirements" below).

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds and the Company's Articles of Incorporation. As of June 30, 2005, PGE had the capability to issue additional First Mortgage Bonds and preferred stock in amounts sufficient to meet its anticipated capital and operating requirements.

On May 27, 2005, PGE entered into a $400 million five-year, unsecured, revolving credit facility with a group of commercial banks. The facility is available for general corporate purposes and replaced the Company's $50 million 364-day and $100 million three-year revolving credit facilities. The maximum amount of the facility is available to PGE for borrowings and/or the issuance of standby letters of credit. At June 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 the Port Westward project. The facility allows the Company to borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing or at a variable interest rate for any period up to the then remaining term of the facility. The facility provides that all outstanding loans mature on the termination date of the facility, provided that the Company may annually extend the termination date for an additional year upon approval of the lenders holding a majority of the total commitments under the facility. The facility requires annual facility fees based on PGE's unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the facilities, to 65% of total capitalization. At June 30, 2005, the Company's indebtedness to total capitalization ratio, as calculated under the facility, was 39.9%.

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 59.4% and 58.2% at June 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 securing new energy resources. Additional liquidity is available under PGE's revolving credit facility.

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	Developing	Stable

In June 2005, Moody's raised its ratings of PGE's senior secured and unsecured debt, preferred stock, and commercial paper. Moody's also raised its Outlook from Under Review for Possible Upgrade 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 June 30, 2005, PGE had posted approximately $17 million of collateral, consisting of $15 million in letters of credit and $2 million in cash. Based on the Company's non-trading and trading portfolios, estimates of current energy market prices, and the current level of collateral outstanding, as of June 30, 2005, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $17 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 $21 million and decreases to approximately $1 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.

Although measures of PGE's financial performance, including financial ratios, remain strong, due to continuing uncertainty regarding the impact of Enron's Chapter 11 Plan on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, since Enron's Chapter 11 Plan has become effective, the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy.

Financial and Operating Outlook

Retail Customer Growth and Energy Deliveries

Weather adjusted retail energy deliveries to PGE and ESS customers increased approximately 1% for the six months ended June 30, 2005, compared to the same period last year. The increase was due primarily to 1% and 9.8% 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 half of 2005. Weather adjusted residential energy deliveries were down 0.8% compared to the first half of 2004, as a decrease in energy use more than offset an approximate 11,400 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 during the first half of 2005 remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicate the January-to-July runoff (as measured at The Dalles, Oregon) at 76% 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 43% of its retail load requirement in the first half of 2005, with 32% met with thermal generation and the remaining 11% 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.

Additional 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.

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 for customers. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, PGE records unrealized gains and losses in earnings in the current period for derivative instruments that do not qualify for either the normal purchases and normal sales exception or cash flow hedge accounting. Derivative instruments that qualify for the normal purchases and normal sales exception are recorded in earnings on a settlement basis, and cash flow hedges are recorded in 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

Bankruptcy Proceedings and Chapter 11 Plan

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

The Chapter 11 plan (Chapter 11 Plan) became effective on November 17, 2004. It 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. They are available at Enron's website located at www.enron.com/corp/por and the Bankruptcy Court's website located at www.nysb.uscourts.gov and at the website maintained at the direction of the Bankruptcy Court at www.elaw4enron.com.

Future Ownership of PGE

On April 6, 2005, following the OPUC's denial of Oregon Electric's application to buy PGE's common stock from Enron, Enron and Oregon Electric terminated their sale agreement.

Enron has announced that it intends to move forward to issue 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 Debtor's creditors that hold allowed claims, with the remainder issued to a Disputed Claims Reserve where it will be held in trust/escrow, to be released over time to the Debtor's creditors holding allowed claims in accordance with the Chapter 11 Plan. Following issuance of the new PGE common stock to the Debtor's creditors and the Disputed Claims Reserve, PGE will no longer be a subsidiary of Enron.

The registered owner of the new PGE common stock held in the Disputed Claims Reserve will be Steven Forbes Cooper, LLC, as Disbursing Agent. The Disbursing Agent will oversee the release of new PGE common stock from the Disputed Claims Reserve to Debtor's creditors that hold allowed claims. All shares of new PGE common stock held in the Disputed Claims Reserve will be voted by the Disputed Claims Reserve Overseers (DCRO). Initially, the DCRO is comprised of the same individuals who currently 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 to issue shares of new PGE stock to Enron's creditors have been filed with the OPUC (on June 17, 2005), and the NRC (on July 12, 2005). An application was filed with the SEC on July 19, 2005 seeking authorization under PUHCA for Enron to divest PGE. If the Domenici-Barton Energy Policy Act of 2005 is enacted, PUHCA will be repealed effective six months from the date of enactment. Assuming enactment in the near future, SEC authorization will not be needed and the SEC application may be withdrawn.

Enron has indicated that, if all regulatory approvals are received, 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 Enron's 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 Disputed Claims Reserve will be the responsibility of the DCRO, in accordance with guidelines approved by the Bankruptcy Court.

For further information, see "Public Ownership Initiatives" in this Item 2.

Liabilities and Impairments

Although PGE is not included in the Enron bankruptcy, it has been affected. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. PGE has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating.

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

1. Amounts Due from Enron and Enron-Supported Affiliates in Bankruptcy - On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts representing intercompany obligations between PGE and Enron and its bankrupt subsidiaries arising prior to the commencement of the bankruptcy case. In December 2004, PGE made a distribution to Enron of all pre-petition amounts owed by Enron and its affiliates, and related proofs of claim, except for those related to PGH. The distribution was made in an effort to eliminate all pre-petition intercompany balances from PGE's books in order to remove the uncertainties regarding the value of the proofs of claim. Following the distribution, PGE's balance sheet was cleared of all pre-petition intercompany balances with Enron and its affiliates, with the exception of PGH. As of June 30, 2005, PGE has outstanding accounts receivable of $5 million due from PGH. Based on management's assessment of the realizability of accounts receivable from PGH, a reserve of $1 million has been established.

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

Pension Plans

Funding Status

The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). 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 PBGC insures pension plans, including the PGE Plan and the Enron Plan and the pension plans of other Debtors. Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases with respect to the Enron Plan and the plans of the other Debtors (Pension Plans). The claims are duplicative in nature because certain liability under ERISA is joint and several. Five of the PBGC's claims represent unliquidated claims for PBGC insurance premiums (the Premium Claims), five are unliquidated claims for due but unpaid minimum funding contributions (the Contribution Claims) under the Internal Revenue Code of 1986, as amended, and ERISA, 26 U.S.C. Section 412, and 29 U.S.C. Section 1082, and the remaining five claims are for unfunded benefit liabilities (the UBL Claims). PBGC has informed the Debtors that it 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 it 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 PBGC seeking to assert its UBL Claims against Enron's affiliates as set forth below with respect to controlled group liability. Except for one PBGC premium which is not material, the Debtors are current on their PBGC premiums and their minimum funding contributions to the Pension Plans. Therefore, the Debtors' value the Premium Claims and the Contribution Claims at $0. Enron management has informed PGE that the PBGC has informally alleged in pleadings filed with the Bankruptcy Court that the UBL claim related to the Enron Plan could increase by as much as 100%. PBGC has not provided support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

Because the Enron Plan is underfunded, in certain circumstances the Enron Plan may be terminated and taken control of by the PBGC upon approval of a Federal District Court. In addition, with consent of the PBGC, Enron could seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.

Upon termination of an underfunded pension plan, all of the members of the ERISA controlled group of the plan sponsor become jointly and severally liable for the plan's underfunding. The PBGC can demand payment from one or more of the members of the controlled group. If payment is not made, a lien in favor of the PBGC automatically arises against 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. In addition, the PBGC retains an interest in the proceeds of any sale by Enron of its ownership interest in PGE.

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

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

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

Unless and until the District Court authorizes the PBGC to terminate the Pension Plans and the PBGC makes a demand on PGE to pay some or all of any unfunded benefit liabilities under the Pension Plans, which would not occur unless the Proposed Pension Settlement (as described below) is not approved by both the District and Bankruptcy Courts or the parties do not satisfy the terms of the Proposed Pension Settlement, PGE has no liability for the unfunded benefit liabilities and no termination liens arise against any PGE property.

Proposed Settlement

In July 2005, Enron filed a motion with the Bankruptcy Court seeking approval of a settlement (Settlement) with the PBGC and the plaintiffs in 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 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 will proceed 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 would 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 and Enron's objection to such PBGC claims has been stayed. On July 26, 2005, the District Court preliminarily approved the Settlement. A joint hearing between the District Court and the Bankruptcy Court to consider approval of the Settlement is scheduled to be held in September 2005.

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

Minimum Funding Obligation

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

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

Retiree Health Benefits

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

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

Income Taxes

Under regulations issued by the U.S. Treasury Department, each member of a consolidated group during any part of a consolidated federal income tax return year is severally liable for the tax liability of the consolidated group for that year. PGE became a member of Enron's consolidated group on July 2, 1997, the date of Enron's merger with PGC. Based on discussions with Enron's management, PGE management understands that Enron has treated PGE as having ceased to be a member of Enron's consolidated group on May 7, 2001 and becoming a member of Enron's consolidated group once again on December 24, 2002. On December 31, 2002, PGE and Enron entered into a tax allocation agreement pursuant to which PGE agreed to make payments to Enron that approximate the income taxes for which PGE would be liable if it were not a member of Enron's consolidated group. Due to the uncertainty with the reconsolidation during 2003, PGE held certain tax payments due Enron. Enron obtained an agreement from the IRS on February 2, 2004 stipulating that PGE did become a member of the Enron consolidated group on December 24, 2002. PGE resumed tax payments due Enron in early 2004.

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

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. For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. A net operating loss for the year 2002 is expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from future IRS audits for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.
3. Enron's 2003 tax return was filed on September 14, 2004. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2003. Enron had 2003 NOLs sufficient to eliminate Enron's regular income tax and alternative minimum income tax liabilities for 2003. Enron expects to file its 2004 tax return on or before September 15, 2005 and expects to have sufficient NOLs to eliminate its regular income tax for 2004, but could possibly be subject to the 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.

On March 28, 2003, the IRS filed various proofs of claim for taxes in the Enron bankruptcy, including a claim for approximately $111 million with respect to income tax, interest, and penalties for taxable years in which PGE was included in Enron's consolidated tax return. The IRS subsequently amended the proof of claim to $43.6 million. The IRS and Enron reached a settlement on Enron's 1996-2001 tax liability on January 5, 2005. The settlement, which indicates no net taxes due by Enron to the IRS, eliminates any further assessment of tax, interest or penalties for the years 1996-2001 against PGE and any other member of the consolidated group in those years in excess of the overpayment currently held by the IRS.

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.

To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy proceeding, or to otherwise seek to obtain contributions from the other solvent members of the consolidated group. As a result, management believes the income tax, interest, and penalty exposure to PGE (related to any future liabilities from Enron's consolidated tax returns during the period PGE was a member of Enron's consolidated returns) would not be material. No reserves have been established by PGE for any amounts related to this issue.

PGE management cannot predict with certainty what impact the Chapter 11 Plan may have on PGE. However, the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy.

Public Ownership Initiatives

City of Portland

Following the termination of the agreement for the sale of PGE to Oregon Electric, the City of Portland began negotiating with Enron for the purchase of PGE. The City Council also passed a non-emergency ordinance that authorizes the issuance of up to $3 billion of revenue bonds for the possible acquisition. On July 21, 2005, discussions between Enron and the City were terminated.

State of Oregon

The Oregon legislature passed legislation that would create a public corporation (Oregon Community Power) that could purchase and operate PGE, to be financed by revenue bonds. The governor vetoed the legislation on July 22, 2005.

Other

In March 2005, Oregon Mutual Utility Development, Inc., a group of customers and business leaders, proposed a plan to purchase the common stock of PGE and convert the Company to mutual ownership by the Company's ratepayers. Although the state legislature passed a bill that would have established a financing mechanism for such a purchase, Oregon's governor vetoed the legislation on July 20, 2005.

Public Utility Holding Company Act of 1935

On July 29, 2005, the SEC issued an order under PUHCA 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 in an aggregate principal amount outstanding at any one time not to exceed $600 million.

The Domenici-Barton Energy Policy Act of 2005 (EPAct) has passed the House and Senate in Congress and it is expected that the President will sign the EPAct into law. Among other things, the EPAct provides for the repeal of PUHCA effective six months from the date of enactment. If enacted and after the effective date set for PUHCA repeal, PGE will no longer be regulated under PUHCA as a subsidiary of a registered holding company. After the repeal of PUHCA, PGE's short-term debt issuances will be regulated by the FERC under the Federal Power Act.

New Oregon Law - Utility Rate Treatment of Income Taxes

New state legislation that could affect rate treatment of federal, state, and local income taxes paid by certain Oregon utilities has been passed by both houses of the Oregon Legislature and has been submitted to the Governor. The legislation would require annual reporting of income taxes assumed to be authorized for collection in customer rates and income taxes paid to governmental entities. In addition, the legislation would, under some circumstances, require rate adjustments reflecting in part the difference between such amounts. The legislation would apply only to income taxes assumed to be in rates and paid after January 1, 2006, with no rate adjustments effective until late 2007. Considerable uncertainty exists regarding the effect and constitutionality of the legislation. PGE is evaluating potential effects of the legislation.

Class Action Lawsuit - Multnomah County Business Income Taxes

On January 18, 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 (MBIT) 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 MBIT 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 MBIT 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 MBIT and, if not, whether refunds are controlled by the OPUC three-year limitation for billing adjustments. Proceedings are in process and a decision from the OPUC is expected this fall. 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. Management cannot predict the ultimate outcome of this matter.

Resource Valuation Mechanism

A general rate order issued by the OPUC in 2001 approved a new Resource Valuation Mechanism (RVM) tariff that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines for Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, the RVM utilizes a combination of market prices and the value of the Company's resources to establish power costs and set 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 On April 1, 2005, PGE submitted an RVM filing with the OPUC containing an estimate of 2006 power costs based upon preliminary information. An update to preliminary estimates contained in the April filing was filed on June 10, 2005, with further updates to be filed later in 2005. Preliminary estimates indicate an approximate 3% to 4% 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). At June 30, 2005, the remaining balance to be collected was approximately $10 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 electric 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 on December 30, 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.

On April 11, 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 agree to and request 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 generation and natural gas plant operations in calendar years 2005 and 2006. A procedural schedule has been adopted for consideration of the stipulations by the Commission.

Decisions by the OPUC in the above proceedings are expected in 2005.

Nuclear Decommissioning

On May 23, 2005, following the completion of radiological decommissioning of the Trojan Nuclear Plant (Trojan), the U.S. Nuclear Regulatory Commission (NRC) approved the termination of Trojan's Facility Operating License and released the plant site for unrestricted use. In addition, pursuant to the determination by Oregon's Energy Facility Siting Council that the radiological decommissioning of Trojan is complete and the site meets all criteria for unrestricted release, the Oregon Department of Energy (ODOE) has amended applicable Oregon Administrative Rules to reflect the termination of Trojan's operating license. As a condition of the termination, PGE is required to maintain $100 million in nuclear liability insurance coverage until all radioactive material has been removed and transported from the location, or until the NRC authorizes the termination or modification of such financial protection.

PGE maintains a separate NRC license to store spent nuclear fuel in an Independent Spent Fuel Storage Installation at the Trojan plant site until a federal waste repository is completed and spent fuel is removed from the site. The storage facility continues to be monitored by PGE, the NRC, and the ODOE to ensure safe storage.

Hydro Relicensing

In an order issued June 21, 2005, the FERC approved a 50-year joint license application for the Pelton Round Butte hydro project filed by PGE and the Confederated Tribes of the Warm Springs Reservation of Oregon, the project's co-owners. The order also approved a settlement agreement, previously completed and signed by all participating parties, that includes provisions for fish passage over the project's three dams. During the approximate ten-year application process, PGE incurred about $35 million of engineering, legal, and other costs to renew the license. These costs were capitalized and will be amortized over the 50-year license period.

Receivables and Refunds on Wholesale Market Transactions

Receivables - California Wholesale Market

As of June 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 federally-mandated 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 will consider 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. 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 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. In December 2004, the FERC requested comments regarding the manner in which such studies should be conducted and the principles that should control. PGE and numerous other parties filed comments and reply comments in January 2005. Additionally, late comments in support of aspects of PGE's position were filed by the Oregon and Washington public utility commissions and by the Oregon and Washington senate delegations in March, 2005. A decision by the FERC to adopt PGE's approach to these studies could reduce the Company's ultimate refund liability.

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. Oral argument before the Oregon Supreme Court is currently scheduled for September 2005.

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

On August 31, 2004, the administrative law judge issued an Order (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.

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, Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision. A decision is pending. Additionally, if 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) is approved by the U.S. District Court and the Bankruptcy Court, the claims based on the grievances will be barred. The IBEW has objected to the proposed bar. The U.S. District Court and the Bankruptcy Court are scheduled to hold simultaneous hearings on the Tittle Action, including consideration of any objections, in September 2005. 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 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 may next appeal these orders to the Interior Board of Land Appeal. 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. 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, related to the Harbor Oil site. PGE was one of fourteen companies named as PRPs with respect to the Harbor Oil site. The letter starts a 60-day period for PRPs to participate in formal negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site.

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 will be 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. 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

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.

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.

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," "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 Debtor's 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; and,
• general political, economic, and financial market conditions.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

PGE is exposed to various forms of market risk (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 trading portfolio in the first half of 2005 were each zero, and in the first half of 2004 were $0.1 million, $0.2 million, and zero, respectively. The average, high, and low value at risk on the non-trading portfolio in the first half of 2005 were $3.7 million, $5.0 million, and $2.7 million, respectively, and in the first half of 2004 were $1.3 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 June 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 June 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 June 30, 2005, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following tables present PGE's credit exposure for commodity non-trading and trading activities and their subsequent maturity as of June 30, 2005. The tables reflect credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

Non-Trading Activities

(Dollars in millions)				Maturity of Credit Risk Exposure
Rating	Credit Risk Before Collateral	Percentage of Total Exposure	Credit Collateral	2005	2006	2007	2008	2009	After 2009
Investment Grade	$  175	94%	$  68	$  46	$  57	$ 32	$ 19	$  7	$ 14
Non-Investment Grade	7	4%	7	3	4	-	-	-	-
Internally Rated - Investment Grade	4	2%	-	3	1	-	-	-	-
Total	$  186	100%	$  75	$  52	$  62	$ 32	$ 19	$  7	$ 14

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
Internally Rated - Investment Grade	$      1	100%	$    -	$   1	$    -	$    -	$  -	$   -	$    -

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

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

Risk Management Committee

PGE has a Risk Management Committee (RMC) 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.

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 May 17, 2005, the OPUC agreed to consider the question posed by PGE; whether the OPUC rules authorized PGE collections of the MBIT and, if not, whether refunds are controlled by the OPUC three-year limitation for billing adjustments. A decision from the OPUC is expected this fall. 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.

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.

If Enron's 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) is approved by the U.S. District Court and the Bankruptcy Court, the claims based on the grievances will be barred. The IBEW has objected to the proposed bar. The U.S. District Court and the Bankruptcy Court are scheduled to hold simultaneous hearings on the Tittle Action, including consideration of any objections, in September 2005.

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

On June 3, 2005, PGE and the Oregon Department of Justice (DOJ) entered into a Settlement Agreement and Release of Claims (Agreement) in order to prevent the expense of further litigation. Under the Agreement, PGE paid a nominal amount to the DOJ as consideration for releasing PGE from all claims, demands, actions or cases of action, connected to the trading of electricity in the wholesale marketplace by PGE during the period January 1, 1997 through December 31, 2001. Upon the execution of the Agreement, the above case was dismissed. All parties agreed to execute and file a Stipulated General Judgment of Dismissal.

Robert and Julie Remington, et al v. Northwestern Energy, L.L.C.; PPL Montana, LLC; Puget Sound Energy, Inc.; Avista Energy, Inc.; Pacific Energy GP, Inc.; Pacific Energy Group LLC.; Touch America Holdings, Inc.; PacifiCorp; Bechtel Construction Operations Incorporated; Western Energy Company; Portland General Electric Company; and John Does 1-20, Montana Second Judicial District, Rosebud County, Case No. DV 03-109

On July 18, 2005, an Amended Complaint was filed, which modifies the plaintiffs and provides further clarification of the underlying claims. Hereafter this case will be known as "Ankeny, et al v. Northwestern Energy, L.L.C.; PPL Montana, LLC; Puget Sound Energy, Inc.; Avista Energy, Inc.; Pacific Energy GP, Inc.; Pacific Energy Group LLC.; Touch America Holdings, Inc.; PacifiCorp; Bechtel Construction Operations Incorporated; Western Energy Company; Portland General Electric Company; and John Does 1-20, Montana Second Judicial District, Rosebud County, Case No. DV 03-109".

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.

4.1* Five Year Credit Agreement, dated as of May 27, 2005, among Portland General Electric Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and a group of lenders [Form 8-K, June 2, 2005, Exhibit 4.1]

(10) Material Contracts

10.1 * Updated summary description of the Portland General Electric Company Annual Cash Incentive Master Plan for 2004 [Form 8-K, February 17, 2005, Exhibit 10.1]

10.2 * Summary description of the Portland General Electric Company 2005 Annual Cash Incentive Plan [Form 8-K, April 4, 2005, Exhibit 10.1]

10.3 * Portland General Electric Company Severance Pay Plan for Executive Employees, dated June 15, 2005 [Form 8-K, June 20, 2005, Exhibit 10.1]

10.4 * Portland General Electric Company Outplacement Assistance Plan, dated June 15, 2005 [Form 8-K, June 20, 2005, Exhibit 10.2]

(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:	August 5, 2005	By:	/s/ James J. Piro
			James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer

Date:	August 5, 2005	By:	/s/ Kirk M. Stevens
			Kirk M. Stevens Controller and Assistant Treasurer