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Portland General Electric Company 2nd Quarter 2003 Form 10-Q

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, 2003
	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, 2003: 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	31

	Item 3. Quantitative and Qualitative Disclosures
	About Market Risk	66

	Item 4. Controls and Procedures	68


Part II. Other Information

	Item 1. Legal Proceedings	69
	Item 6. Exhibits and Reports on Form 8-K	71
	Signature Page	73

Definitions

BPA											Bonneville Power Administration
Bankruptcy Court											United States Bankruptcy Court For The Southern District of New York
COBRA											Consolidated Omnibus Budget Reconciliation Act
CUB											Citizens' Utility Board
DEQ											Oregon Department of Environmental Quality
Enron											Enron Corp., as Debtor and Debtor in Possession in Chapter 11, Case No. 01-16034 pending in the US Bankruptcy Court For The Southern District of New York
EPA											Environmental Protection Agency
ERISA											Employee Retirement Income Security Act
FASB											Financial Accounting Standards Board
FERC											Federal Energy Regulatory Commission
IRS											Internal Revenue Service
KWh											Kilowatt-Hour
Mill											One tenth of one cent
MWh											Megawatt-hour
NW Natural											Northwest Natural Gas Company
NYMEX											New York Mercantile Exchange
OPUC											Public Utility Commission of Oregon
PBGC											Pension Benefit Guaranty Corporation
PGC											Portland General Corporation
PGE or the Company											Portland General Electric Company
PUHCA											Public Utility Holding Company Act of 1935
SEC											Securities and Exchange Commission
SFAS											Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board
Trojan											Trojan Nuclear Plant
Unsecured Creditors' Committee											Enron Unsecured Creditors' Committee
URP											Utility Reform Project
VEBA											Voluntary Employee Beneficiary Association
WECC											Western Electricity Coordinating Council

PART I

Financial Information

Item 1. Financial Statements

Portland General Electric Company and Subsidiaries Consolidated Statements of Income (Unaudited)
				Three Months Ended June 30,										Six Months Ended June 30,
				2003			2002							2003								2002
				(In Millions)

Operating Revenues				$	410		$		439						$					881			$						903

Operating Expenses
	Purchased power and fuel				235				269							519									526
	Production and distribution				30				32							58									60
	Administrative and other				36				33							72									71
	Depreciation and amortization				53				39							108									81
	Taxes other than income taxes				17				16							36									36
	Income taxes				11				17							26									45
					382				406							819									819

Net Operating Income					28				33							62									84

Other Income (Deductions)
	Miscellaneous				4					(3)							7									(1)
	Income taxes				1					3							2									4
					5					-							9									3

Interest Charges
	Interest on long-term debt and other				20					15							39									32
	Interest on short-term borrowings				-					2							-									3
					20					17							39									35

Net income before cumulative effect of a
			change in accounting principle		13					16							32									52
Cumulative effect of a change in accounting
		principle, net of related taxes of $(1)			-					-							2									-

Net Income					13					16							34									52

Preferred Dividend Requirement					-					-							1									1

Income Available for Common Stock				$	13			$		16			$				33				$					51
Portland General Electric Company and Subsidiaries Consolidated Statements of Retained Earnings (Unaudited)

				Three Months Ended June 30,							Six Months Ended June 30,
				2003		2002					2003													2002
				(In Millions)

Balance at Beginning of Period				$	508			$		486			$				488				$					451
Net Income					13					16									34									52
					521					502									522									503

Dividends Declared
	Preferred stock				-					-									1									1
					-					-									1									1
Balance at End of Period				$	521		$		502			$						521				$					502

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,
				2003					2002									2003										2002
				(In Millions)
Accumulated other comprehensive income (loss) - Beginning of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$			-			$		-					$				3									$				-
	Minimum pension liability adjustment						(3)				(2)									(3)													(2)
	Total				$		(3)			$	(2)					$				-							$						(2)

Net Income					$		13			$	16					$							34				$						52

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 $(2) and $2 for the three
		months ended June 30, 2003 and 2002 and $(4) and $(1)
		for the six months ended June 30, 2003 and 2002		3					(3)						6											2
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $1 for the six months
		ended June 30, 2003		-					-						(2)											-
		Reclassification adjustment in net income due to discontinuance
		of cash flow hedges, net of related taxes of $2 for the six
		months ended June 30, 2003		-					-						(4)											-
		Reclassification of unrealized gains (losses) to SFAS No. 71
		regulatory (liability) asset, net of related taxes of $1 and $(2)
		for the three months ended June 30, 2003 and 2002 and $1
		and $1 for the six months ended June 30, 2003 and 2002		(3)					3						(3)											(2)
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		-					-						(3)											-

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

Comprehensive income				$		13			$				16	$								31		$							52

Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$		-			$				-			$							-						$						-
	Minimum pension liability adjustment			(3)					(2)						(3)											(2)
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,
				2003					2002
					(In Millions)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $92 and $81)			$			3,777	$			3,706
	Accumulated depreciation						(1,819)				(1,768)
							1,958				1,938
Other Property and Investments
	Receivable from parent (less allowance for uncollectible accounts of $84 and $81)						-			-
	Nuclear decommissioning trust, at market value						26			31
	Non-qualified benefit plan trust						64			68
	Note receivable - Pelton Round Butte project sale						18			20
	Miscellaneous						36			28
							144			147
Current Assets
	Cash and cash equivalents				155						51
	Accounts and notes receivable (less allowance for uncollectible accounts of $41 and $28)				212						241
	Unbilled and accrued revenues				54						84
	Assets from price risk management activities				87						77
	Inventories, at average cost				45						45
	Prepayments and other				93						90
	Deferred income taxes				-						3
					646						591
Deferred Charges
	Unamortized regulatory assets				388						544
	Miscellaneous				35						30
					423						574
				$	3,171			$			3,250
Capitalization and Liabilities
Capitalization
	Common stock equity
		Common stock, $3.75 par value per share, 100,000,000
		shares authorized; 42,758,877 shares outstanding		$	160			$			160
		Other paid-in capital - net			481						481
	Retained earnings				521						488
	Accumulated other comprehensive income (loss):
			Unrealized gain (loss) on derivatives classified as cash flow hedges			-					3
			Minimum pension liability adjustment			(3)					(3)
	Cumulative preferred stock subject to mandatory redemption				24						27
	Limited voting junior preferred stock				-						-
	Long-term obligations				1,015						827
					2,198						1,983

Commitments and Contingencies (Notes 3-7)

Current Liabilities
	Long-term debt due within one year				49						191
	Preferred stock maturing within one year				1						1
	Accounts payable and other accruals				179						244
	Liabilities from price risk management activities				64						80
	Customer deposits				7						5
	Accrued interest				19						15
	Dividends payable				1						1
	Accrued taxes				41						22
	Deferred income taxes				6						-
					367						559
Other
	Deferred income taxes				357						383
	Deferred investment tax credits				19						20
	Trojan asset retirement obligation and transition costs				78						186
	Accumulated asset retirement obligation				17						-
	Unamortized regulatory liabilities				32						16
	Non-qualified benefit plan liabilities				63						62
	Miscellaneous				40						41
					606						708
				$	3,171			$			3,250

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,
				2003			2002
				(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by (used in) operating activities
	Net income		$	34		$		52
	Non-cash items included in net income:
		Cumulative effect of a change in accounting principle, net of tax		(2)				-
		Depreciation and amortization		108				81
		Deferred income taxes		(15)				44
		Net assets from price risk management activities		(25)				2
		Power cost adjustment		23				(26)
		Other non-cash income and expenses (net)		26				(30)
	Changes in working capital:
		Net margin deposit activity		2				64
		(Increase) Decrease in receivables		47				45
		Increase (Decrease) in payables		(44)				(58)
		Other working capital items - net		(4)				(8)
	Other - net			1				(2)
Net Cash Provided by Operating Activities				151				164

Cash Flows From Investing Activities:
	Capital expenditures			(69)				(75)
	Other - net			(14)				3
Net Cash Used in Investing Activities				(83)				(72)

Cash Flows From Financing Activities:
	Net decrease in short-term borrowings			-				(39)
	Repayment of long-term debt			(147)				(19)
	Issuance of long-term debt			193				-
	Debt issue costs			(6)				-
	Preferred stock retired			(3)				(2)
	Dividends paid			(1)				(1)
Net Cash Provided by (Used in) Financing Activities				36				(61)

Increase in Cash and Cash Equivalents				104				31
Cash and Cash Equivalents, Beginning of Period				51				8
Cash and Cash Equivalents, End of Period			$	155		$		39

Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	32		$		31
		Income taxes		22				2

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

Notes to Consolidated Financial Statements (Unaudited)

Note 1 - Principles of Interim Statements

The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim periods presented. Such statements, which are unaudited, are presented in accordance with the SEC's interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods on estimates of operating time expired, benefit received or activity associated with the based 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 2002 Annual Rep ort on Form 10-K and the other reports filed with the SEC since its 2002 Form 10-K was filed, the disclosures are adequate to make the information presented not misleading.

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

Emerging Issues Task Force Issue No. 02-3 (EITF 02-3), Accounting for Contracts Involved in Energy Trading and Risk Management Activities, which became effective in the third quarter of 2002, requires that unrealized and realized gains and losses associated with "energy trading activities" be reported on a net basis. Accordingly, PGE now records unrealized and realized gains and losses from trading activities on a net basis as a component of Operating Revenues. Previously, unrealized gains and losses from trading activities were recorded on a net basis in Purchased Power and Fuel expense; when such contracts were settled, sales were recorded in Operating Revenues and purchases were recorded in Purchased Power and Fuel expense. In accordance with requirements of EITF 02-3, all amounts in comparative financial statements for prior periods have been reclassified to conform to the new presentation. Such reclassification, which had no effect on margins from energy sales, resulted in reductions to Operating Revenues and Purchased Power and Fuel expense of $114 million and $190 million for the second quarter and first half of 2002, respectively.

Note 2 - Price Risk Management

PGE utilizes derivative instruments, including electricity forward and option contracts, natural gas forward and swap contracts, and crude oil futures contracts in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and endeavor to minimize net power costs for its retail customers, and in its trading activities to participate in electricity, natural gas, and crude oil markets. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), which was adopted on January 1, 2001, derivative instruments are recorded on the Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings, 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.

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

For energy trading activities, EITF 02-3 requires that all unrealized and realized gains and losses associated with "energy trading activities" be reported on a net basis. EITF 02-3 also requires that the comparative financial statements for prior periods be reclassified to conform to the new presentation. As a result, PGE records unrealized and realized gains and losses from trading activities on a net basis as a component of Operating Revenues.

Non-Trading Activities

As PGE's primary business is to serve its retail customers, it uses derivative instruments, including electricity forward and option, and natural gas forward and swap contracts to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers.

SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. Rates approved by the OPUC are based on a valuation of all the Company's energy resources, including derivative instruments that will settle during the 12-month period from January 1, 2003 to December 31, 2003. Such valuation was based on forward price curves in effect on November 12, 2002 for electricity and natural gas. The timing difference between the recognition of gains and losses on certain derivative instruments and their realization and subsequent collection in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. As these contracts are settled, the regulatory asset or regulatory liability is reversed. However, as there is currently no power cost adjustment in effect for 2003, unrealized gains and losses on new 2003 derivatives not included in rates, and changes in fair value of derivatives used to set rates, are not deferred as regulatory assets or regulatory liabilities.

In the first half of 2003, PGE recorded $23 million in net unrealized gains in earnings in its retail portfolio, including $1 million in net unrealized gains in the second quarter. The net unrealized gain in the first half of 2003 was partially offset by recording a $15 million SFAS No. 71 regulatory liability, calculated on the basis indicated above. In the first half of 2002, PGE recorded $1 million in net unrealized gains, including $5 million in net unrealized gains in the second quarter, all of which were fully offset by the recording of a SFAS No. 71 regulatory liability.

Derivative activities recorded in OCI for the three- and six-month periods ended June 30, 2003 from cash flow hedges consist of $5 million and $10 million, respectively, of unrealized gains from new contracts and changes in fair value. Also recorded in OCI in the first half of 2003 were $3 million in net gains reclassified in earnings for contracts that settled during the period, and $6 million in net gains for the discontinuance of cash flow hedges due to the probability that the original forecasted transaction will not occur; such gains were recorded in the first quarter of the year. The unrealized gain recorded in OCI in the first half of 2003 was partially offset by a $4 million SFAS No. 71 liability.

Derivative activities recorded in OCI for the three- and six-month periods ended June 30, 2002 from cash flow hedges consisted of $5 million of net unrealized losses and $3 million of net unrealized gains, respectively, that were fully offset by the recording of a SFAS No. 71 regulatory asset and regulatory liability.

No amounts were reclassified into earnings as a result of hedge ineffectiveness in the first half of 2003 or 2002. As of June 30, 2003, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 21 months. In addition, the Company estimates that of the $10 million of net unrealized gains at June 30, 2003, $7 million will be reclassified into earnings within the next twelve months, and $3 million will be reclassified over the remaining nine months.

Trading Activities

PGE utilizes electricity forward and option contracts, natural gas forward, swap and futures contracts, and crude oil futures contracts to participate in electricity, natural gas, and crude oil markets. Such activities are not reflected in PGE's retail prices. As indicated above, beginning with the third quarter of 2002, all unrealized and realized gains and losses associated with "energy trading activities" are reported on a net basis. Amounts included in the comparative financial statements for prior periods have been reclassified to Operating Revenues to conform to the new presentation.

The following tables indicate unrealized and realized gains and losses on electricity and fuel trading activities and transaction volumes for electricity trading contracts that settled in the three-and six-month periods ended June 30, 2003 and 2002:

	Trading Activities
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	(In Millions)
	2003		2002			2003			2002
Unrealized Gain (Loss)	$	1	$	-			$	2		$	(2)
Realized Gain (Loss)		1		1				-			2
Net Gain (Loss) in Operating Revenues	$	2	$	1			$	2		$	-

	Electricity Trading
	Megawatt-Hours (thousands)
	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2003	2002	2003	2002
Sales	3,660	3,993	6,230	5,987
Purchases	3,660	3,993	6,230	5,987

Note 3 - Legal and Environmental Matters

Trojan Investment Recovery - In 1993, following the closure of Trojan, PGE sought full recovery of and a rate of return on its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. The filing was a result of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order 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 filed in 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 remanding 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 19 98 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).

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 its investment in the Trojan plant. Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. 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 Enron/P GC merger. 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. 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 denying all of URP's challenges, and approving the accounting and ratemaking elements of the settlement. URP appealed the decision to the Marion County Circuit Court, and in December 2002 PGE was granted intervention. A decision is expected in the fall of 2003.

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 remand to the OPUC became effective. The OPUC has taken no action on the remand.

In a separate legal proceeding, two class actions suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers. In March 2003, the Company was served with two identical cases filed in Multnomah County Circuit Court. PGE intends to vigorously defend these cases.

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

Union Grievances - Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enron, n ot PGE. The IBEW filed an answer and counterclaim that the issue is arbitrable, and PGE filed a reply that denied the counterclaim and raised four affirmative defenses. A trial has been set for September 2003. Management cannot predict the ultimate outcome of these grievances.

Other Legal Matters - PGE is party to various other claims, legal actions and complaints arising in the ordinary course of business. Management cannot predict the ultimate outcome of these matters.

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

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

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

In accordance with the Voluntary Agreement, in March 2001, 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 a final investigation report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

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

Management believes that the Company's contribution to the sediment contamination, if any, would qualify it as a de minimis Potentially Responsible Party. Nonetheless, management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Note 4 - Related Party Transactions

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

			June 30, 2003	December 31, 2002
Receivables from affiliated companies
	Enron Corp and other Enron Subsidiaries in Bankruptcy:
		Merger Receivable	$ 84	$ 81
		Allowance for Uncollectible - Merger Receivable	(84)	(81)
		Accounts Receivable^(a)	2	2
		Other Allowance for Uncollectible Accounts^(a)	(2)	(2)
	Other Enron Subsidiaries:
		Portland General Holdings, Inc. - in Bankruptcy
		Accounts Receivable^(a)	5	5
		Other Allowance for Uncollectible Accounts^(a)	(2)	(2)
		PGH2 and its subsidiaries - not in Bankruptcy
		Accounts Receivable^(a)	5	4
		Note Receivable^(a)	1	1

Payables to affiliated companies
	Enron Corp:
		Accounts Payable^(b)	6	19
		Income Taxes Payable^(c)	24	7

^{(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			2003	2002
Revenues from affiliated companies
	Other Enron Subsidiaries:
		Sales of electricity and transmission	$ -	$ 1
Expenses billed to affiliated companies
	PGH2 and its subsidiaries:
		Intercompany services^(a)	1	1

Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services^(a)	17	11

Interest (net) from affiliated companies
	Enron Corp:
		Interest income^(b)	3	3
	PGH 2 and its subsidiaries:
		Interest income^(b)	-	2
^{(a) Included in Administrative and other on the Consolidated Statements of Income}
^{(b) Included in Other Income (Deductions) on the Consolidated Statements of Income}

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

Enron suspended its monthly payments to PGE in September 2001, pursuant to its Stock Purchase Agreement with NW Natural, under which NW Natural was to have assumed Enron's merger payment obligation upon its purchase of PGE. The Stock Purchase Agreement was terminated in May 2002. At June 30, 2003, Enron owed PGE approximately $84 million, including accrued interest. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001.

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

Income Taxes 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 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 $24 million income taxes payable balance at June 30, 2003 represents a net current income taxes payable of $17 million for the first six months of 2003 and $7 million of taxes payable at December 31, 2002 for income taxes owed up to May 7, 2001. In the first six months of 2003, PGE paid $21 million to Enron for income taxes payable. On July 15, 2003, PGE made an additional payment to Enron of $16 million. For further information, see Note 7, Enron Bankruptcy.

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

Enron - PGE receives corporate overhead and employee benefit charges from Enron. In the first six months of 2003, Enron billed PGE approximately $10 million for retirement savings plan matching and medical and dental benefits. In addition, PGE accrued $7 million for corporate overhead costs. For the same period in 2002, Enron billed PGE approximately $5 million for retirement savings plan matching and medical and dental benefits, and $6 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001, except for payments for employee benefit plans. At December 31, 2002, PGE had a $19 million payable to Enron, primarily for corporate overhead costs. In reaching an agreement with Enron regarding the allocation of corporate overheads in the post-bankruptcy period, PGE resumed payments for corporate overhead costs in March 2003. In the first six months of 2003, PGE paid $30 million to Enron, consisting of $21 million for corporate overhead costs from January 2002 through June 2003 and $9 million for employee benefits. The $6 million payable to Enron at June 30, 2003 consisted of $3 million for corporate overheads and $3 million for employee benefit costs.

Other Enron Subsidiaries in Bankruptcy - PGE purchased electricity from, and sold electricity to, Enron Power Marketing, Inc. (EPMI) during 2000 and 2001. PGE also provided transmission services to EPMI under a transmission contract that was guaranteed by Enron. PGE has not purchased electricity from, or sold electricity to, EPMI since December 2001, and EPMI has not paid for transmission services since September 2002.

At December 31, 2002, PGE was owed a net $2 million by EPMI for power sales and transmission services, which remained outstanding at June 30, 2003. EPMI is part of Enron's bankruptcy proceedings. Due to uncertainties associated with the realization of this receivable from EPMI, a $2 million reserve has been established. PGE included amounts owed by EPMI for power sales and transmission services in the proofs of claim filed with the Bankruptcy Court.

On April 17, 2003, PGE entered into a settlement agreement with EPMI and Enron to terminate the transmission contract. The settlement agreement was approved by the Bankruptcy Court and accepted by the FERC. Under the settlement, PGE retained a $200,000 deposit from EPMI related to the transmission contract and Enron's guaranty was terminated. PGE amended its proofs of claim in the Enron bankruptcy to include a prepetition unsecured claim against EPMI and a prepetition guaranty claim against Enron for $1 million owed PGE for transmission services. For further information, see Note 7, Enron Bankruptcy.

Portland General Holdings, Inc. - in Bankruptcy - On June 27, 2003, Portland General Holdings, Inc. (PGH), a wholly owned subsidiary of Enron located in Portland, filed to initiate bankruptcy proceedings under the federal Bankruptcy Code. The PGH filing has been procedurally consolidated with the Enron bankruptcy proceeding. None of PGH subsidiaries are included in the bankruptcy filing. At June 30, 2003, PGE had outstanding accounts receivable from PGH of $5 million, comprised of $4 million related to employee benefit plans and $1 million for employee and other corporate governance services. Based on management's assessment of the realizability of the receivable from PGH, a reserve of $2 million was established in December 2002. PGE will continue to assess the collectibility of the above receivable.

PGH2 and its Subsidiaries - not in Bankruptcy - PGH2, a wholly owned subsidiary of PGH, is the parent company of various subsidiaries that receive services from PGE. PGH2 and its subsidiaries are not part of Enron's or PGH's bankruptcy proceedings. PGH2 subsidiaries include Portland General Distribution, LLC (PGDC), and its subsidiary Portland General Broadband Wireless, LLC (PGBW) (telecommunications companies), Microclimates, Inc. (MI) (a project management company), and Portland Energy Solutions Company, LLC (PES), which provides cooling services to buildings in downtown Portland, Oregon.

For the first six months of 2003, PGE billed PGH2 and its subsidiaries $1 million for employee and other corporate governance services. As of June 30, 2003, PGE had outstanding accounts and notes receivable from PGH2 and its subsidiaries of $6 million, comprised of $2 million related to non-regulated asset sales, $3 million for employee and other corporate governance services, and a $1 million secured loan to PES. Of the total $6 million receivable balance, $4 million was due from PGDC and its subsidiary, PGBW, related to assets sold for a capital project and for employee services provided by PGE.

On July 9, 2003, PGDC's equity interest in PGBW was sold. As a result, $3 million of the sales proceeds were used to pay PGE to reduce the outstanding accounts receivable balances owed by PGH2 and its subsidiaries.

PGE has a revolving credit agreement to loan PES $2 million. The agreement was approved by the OPUC (see below for an amendment to the agreement). Under the agreement, PGE advances funds to PES to complete a district cooling system project, with advances accruing interest at 16% per annum. The OPUC order provides that interest paid by PES to PGE in excess of PGE's authorized cost of capital (9.083%) is to be deferred for future refund to customers. PGE also has a security interest in certain contracts and equipment related to the project. As of December 31, 2002, PES owed PGE $1 million under the revolving credit agreement, including accrued interest, which remains outstanding at June 30, 2003.

The agreement with PES expired on April 1, 2003. PGE filed an application with the OPUC for approval of an amendment to extend the agreement to March 31, 2004, reduce the maximum loan amount from $2 million to $1.5 million, and reduce the interest rate from 16% to 12% per annum. On July 15, 2003, the OPUC approved the extension of the termination date and the reduction of the maximum loan amount, but retained the interest rate at 16% per annum.

In addition, PGE provides employee and other corporate governance services to PES, for which PES owed PGE $1 million at June 30, 2003.

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

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

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

Note 5 - Receivables - California Wholesale Market

As of June 30, 2003, PGE has net accounts receivable balances totaling approximately $62 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).

On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.

PGE is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceeding and has filed a proof of claim in each of the proceedings. Management continues to assess PGE's exposure relative to its California receivables and has established reserves of $29 million related to this receivable amount, including $11.5 million recorded in the first quarter of 2003. 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. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.

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

Note 6 - Refunds on Wholesale Transactions

California

In a June 19, 2001 order adopting a price mitigation program for 11 states within the WECC area, the FERC referred to a settlement judge the issue of refunds for non federally-mandated transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and the PX.

On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering an evidentiary hearing proceeding to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Hearings were held in March and April 2002 to determine the appropriate proxy prices to use and which sales were exempt from refunds because they had been made pursuant to orders of the Department of Energy. Further hearings were held in August through October 2002 to determine the method of calculation of amounts owed to, and refunds owed by, sellers into the California market. Appeals of the FERC orders establishing the refund methodology have been filed and are pending in the Ninth Circuit Federal Court of Appeals. On August 21, 2002 the Ninth Circuit issued an order requiring the FERC to reopen the record to allow the parties to present add itional evidence of market manipulation.

On August 13, 2002, the FERC staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation. In 2002, following the staff report, additional comments and objections were filed with the FERC by PGE and other utilities. In addition, it was disclosed that some gas traders reported incorrect prices to the firms that report gas indices, a FERC administrative law judge issued an order finding that a company had manipulated the gas market by withholding capacity, and a former officer of Enron's West Power Trading Division entered a guilty plea to conspiracy to commit wire fraud in connection with California's energy market.

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. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.

On March 3, 2003, in response to the FERC reopening the record as ordered by the Ninth Circuit, numerous parties filed documents with the FERC addressing possible market manipulation. The most comprehensive filings were by the California parties. In addition to alleging that the markets were manipulated and that the refund cases should thus be expanded, they alleged that numerous sellers, including PGE, participated in various strategies that affected the market adversely. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of the California parties.

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, issued in December 2002, but modifying the methodology it had previously ordered for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates that the new methodology could increase the amount of the potential refunds by approximately $20 million. Although further proceedings will be necessary to determine exactly how the new methodology will affect the refund liability, the Company now estimates its potential liability to be between $20 million and $50 million.

PGE does not agree with several aspects of the FERC's methodology for determining potential refunds. On April 25, 2003, PGE joined a group of utilities in filing a request for rehearing of various aspects of the March 26, 2003 order, including the repricing of the gas cost component of the proxy price from which refunds are to be calculated. Opposing parties likewise filed motions for rehearing.

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. On June 25, 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. On July 25, 2003, numerous parties filed motions for rehearing of the FERC order issued June 25, 2003.

Potential Refund Mitigation

The FERC has indicated that any refunds PGE may be required to pay related to California sales can be offset by accounts receivable related to sales in California (as discussed in Note 5, Receivables - California Wholesale Market). As indicated in Note 5, PGE has established reserves of $29 million related to the receivable amount. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from the effective dates of the applicable transactions; such interest has not yet been recorded by the Company.

In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism in effect at the time. This could further mitigate the financial effect of any refunds made or received by the Company.

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

Note 7 - Enron Bankruptcy

Commencing on December 2, 2001, Enron, along with certain of its subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code. PGE is not included in the bankruptcy, but the common stock of PGE held by Enron is part of the bankruptcy estate.

On July 11, 2003, Enron and its debtor-in-possession subsidiaries (collectively the Debtors) filed their proposed joint chapter 11 plan (the chapter 11 Plan) and related disclosure statement (the Disclosure Statement) with the Bankruptcy Court. The chapter 11 Plan and Disclosure Statement 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.

Although Enron is continuing the sale process for PGE, under the chapter 11 Plan, if PGE is not sold, the shares of PGE's common stock will be distributed over time to the Debtors' creditors. It is also anticipated that once a sufficient amount of the common stock is distributed to creditors, the shares would be publicly traded. The chapter 11 Plan is subject to creditor approval and confirmation by the Bankruptcy Court.

Management cannot predict with certainty what impact Enron's bankruptcy, including the chapter 11 Plan, may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and PGC in 1997 (Merger Conditions), Enron's access to PGE cash or assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC appr oval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances its operations separately from Enron, on both a short-term and long-term basis. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.

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

1. Amounts Due from Enron and Enron-Supported Affiliates in Bankruptcy - As described in Note 4, Related Party Transactions, PGE is owed approximately $84 million (including accrued interest) by Enron at June 30, 2003 (Merger Receivable). Such amount was to have been paid to the Company for customer price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including approximately $73 million (including accrued interest) for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, at June 30, 2003, PGE has outstanding accounts receivable of $7 million from other Enron subsidiary companies which are part of the bankruptcy proceedings, including $5 million due from Portland General Holdings, Inc. and $2 million due from EPMI. Based on management's assessment of the realizability of these balances, a reserve of $4 million has been established.

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

Pension Plans

The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2002, the total fair value of PGE Plan assets was $16 million lower than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, the PGE Plan was over-funded on an accumulated benefit obligation basis by about $30 million as of December 31, 2002. Based on discussions with Enron management, it is PGE management's understanding that, as of December 31, 2002, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $52 million on a SFAS No. 87 basis and approximately $182 million on a plan termination basis. The Pension Benefit Guaranty Corporation (PBGC) insures pension plans, including the PGE Plan and the Enron Plan. Further, Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases. The claims are duplicative in nat ure, representing unliquidated claims for PBGC insurance premiums (the Premium Claims) and unliquidated claims for due but unpaid minimum funding contributions (the Contribution Claims) under the Internal Revenue Code of 1986, as amended (the Tax Code) 29 U.S.C. Section 1082 and claims for unfunded benefit liabilities (the UBL Claims). Enron and the relevant sponsors of the defined benefit plans are current on their PBGC premiums and their contributions to the pension plans. Therefore, Enron has valued the Premium Claims and the Contribution Claims at $0. The total amount of the UBL Claims is $305.5 million (including $271 million for the Enron Plan, and $24.8 million for the PGE Plan). In addition, 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 provided no support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

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

Because the Enron Plan is underfunded and Enron is in bankruptcy, in certain circumstances the Enron Plan may be terminated and taken control of by the PBGC upon approval of a Federal District Court. In addition, with consent of the PBGC, Enron could seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with the Employee Retirement Income Security Act of 1974, as amended (ERISA).

Upon termination of an underfunded pension plan, all of the members of the 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 members of the Enron controlled group. PG E management believes that the lien would be subordinate to prior perfected liens on the assets of the member of the controlled group. Substantially all of PGE's assets are subject to a prior perfected lien in favor of the holders of its First Mortgage Bonds. Management believes that any lien asserted by the PBGC would be subordinate to that lien. Based on discussions with Enron's management, PGE's management understands that Enron has made all required contributions to date and the next contribution is not due until September 2003.

In its Disclosure Statement, Enron states that it intends to seek the approval of the Bankruptcy Court to fund certain benefits under the Enron Plan and to terminate it in a manner that should eliminate the PBGC's claims. It also states, however, that there can be no assurance that the funding and termination will be approved, or that upon approval Enron will have the ability to obtain funding for accrued benefits on acceptable terms.

If the proposal to fund and terminate the Enron Plan, as stated in the Disclosure Statement, 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. However, there can be no assurance that this proposal will remain in the Plan ultimately approved by the Debtors' creditors. In addition, as stated in the Disclosure Statement, there can be no assurance at this time that the funding and termination will be approved by the Bankruptcy Court or that, upon such approval, Enron will have the ability to obtain funding on acceptable terms.

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 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 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 coverage for Enron's retirees, and the retirees would not be entitled to choose the plan from which to obtain coverage. Retirees electin g to purchase COBRA coverage would be provided the same coverage that is provided to similarly situated retirees under the most appropriate plan in the Enron controlled group. Retirees electing to continue coverage would be required to pay for the coverage, up to an amount not to exceed 102% of the cost of coverage for similarly situated beneficiaries. Retirees are not required to acquire coverage under COBRA. Retirees will be able to shop for coverage from third party sources and determine which is the least expensive coverage.

Management believes that in the event Enron terminates retiree coverage, any material liability to PGE associated with Enron retiree health benefits is unlikely for two reasons. First, based on 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. Management believes that it is unlikely that any PGE plans would be found to be the most appropriate to provide COBRA coverage. Second, even if a PGE plan were selected, management believes that retirees in good health should be able to find less expensive coverage from other providers, which will reduce the number of retirees electing COBRA coverage. Management believes that the additional cost to PGE to provide coverage to a limited number of retirees that are unable to acquire other coverage because they are hard to insure or have preexisting conditions will not be material. No reserves 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. As of July 31, 2003, PGE has paid $37 million to Enron under the tax allocation agreement.

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

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

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

Enron's 2002 tax return has not yet been filed. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron expects that, in addition to offsetting its income tax liabilities for years before 2002, these NOLs will be sufficient to fully offset Enron's regular and alternative minimum income tax liabilities for 2002 and its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.

Enron believes that all of the requirements for re-consolidation of PGE with the Enron consolidated group have been met. The Disclosure Statement states that the Debtors intend to seek a determination from the IRS confirming that PGE did in fact become a member of the Enron consolidated group on December 24, 2002. However, because of the inherently factual nature of the determination of the re-consolidation, there can be no assurance that the IRS will agree to rule, or if it does agree to rule, to agree with this position. In the event that the IRS does not agree and the matter is not otherwise resolved in the bankruptcy proceeding, PGE will file an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax allocation agreement. Enron management believes that all administrative expense claims will be paid in full.

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

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

To the extent, if any, that the IRS would look to PGE to pay any assessment not paid by Enron, PGE would exercise whatever legal rights, if any, that are available for recovery in Enron's bankruptcy 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 the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.

Enron Debtor in Possession Financing - PGE has been informed by Enron management that shortly after the filing of its bankruptcy petition in December 2001, Enron entered into a debtor in possession credit agreement with Citicorp USA, Inc. and JPMorgan Chase Bank. The agreement was amended and restated in July 2002 and in May 2003. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor in possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose again st the pledged shares of PGE stock or to exercise control over PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

Enron Auction Processes Related to PGE

Enron continues to pursue the sale of PGE through the auction process that it announced on August 27, 2002. However, Enron has stated that it reserves the right not to sell PGE if the bids received are not deemed fully reflective of its value. A sale of PGE would require the consideration and approval of regulatory agencies, including the OPUC.

If PGE is not sold, under the chapter 11 Plan the shares of PGE's common stock will be distributed over time to the Debtors' creditors. Until shares are distributed to creditors, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of the creditors.

Until the chapter 11 Plan or another filing related to the sale of PGE is approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to the Debtors' creditors.

Note 8 - Asset Retirement Obligations

PGE adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003. SFAS No. 143 requires the recognition of Asset Retirement Obligations (AROs), measured at estimated fair value, for legal obligations related to the dismantlement and restoration costs associated with the retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition of AROs that are measurable, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the Statement of Incom e. Both amounts are included in Depreciation and Amortization expense for Utility plant and Other Income (Deductions) for Other property on the Statement of Income.

Regulation - Pursuant to regulation, AROs of rate-regulated long-lived assets are included in depreciation expense allowed in rates. Any differences in the timing of recognition of costs for financial reporting and rate-making purposes are deferred as a regulatory asset or regulatory liability under SFAS No. 71. PGE expects any changes in estimated AROs to be incorporated in future rates. Substantially all significant AROs are included in rate regulation.

Also through regulation, PGE collects in rates removal costs for certain assets that do not have associated legal asset retirement obligations. At June 30, 2003, PGE has an estimated $223 million regulatory liability for these removal costs recorded in Accumulated Depreciation.

Cumulative Effect - Upon adoption of SFAS No. 143, PGE recorded a $2 million after-tax gain in earnings from the cumulative effect of a change in accounting principle related to other property. This transition adjustment represents a difference in using a straight-line amortization vs. accretion methodology under SFAS No. 143.

The $11 million transition adjustment for rate-regulated utility plant, consisting of the Boardman and Colstrip coal plants, Beaver and Coyote Springs gas turbine plants, and the Bull Run hydro project, is deferred as a regulatory liability pursuant to SFAS No. 71.

The ARO associated with the Trojan plant was recorded on a nominal dollar basis at the time of its abandonment in 1993, with costs to be recovered through regulation recorded as a regulatory asset. With the adoption of SFAS No. 143, the regulatory asset and the related ARO for the Trojan plant were reduced by $96 million to adjust the balances to an estimated fair value as required by SFAS No. 143.

Asset Retirement Obligations Activity - Upon adoption of SFAS No. 143, PGE recorded AROs of $15 million for utility plant and $1 million for other property and adjusted the ARO for the Trojan Plant to $80 million.

The following presents the proforma effects to the balances and activities in AROs for the accounting periods reported herein had SFAS No. 143 been in effect for all periods:

		Proforma		Proforma
		Six Months Ended		Year Ended
		June 30, 2003		December 31, 2002
Beginning Balance		$	96	$	104
Activity
	AROs incurred		-		-
	Expenditures (Trojan)		(10)		(18)
	Accretion		3		6
	Revisions		(1)		4
Ending Balance		$	88	$	96

Unrecognized Asset Retirement Obligations

PGE has certain tangible long-lived assets for which AROs are not measurable. An ARO will be required to be recorded when circumstances change. The assets that may require removal when the plant is no longer in service include the Oak Grove hydro project and transmission and distribution plant located on public right-of-ways and on certain easements. Management believes that these assets will be used in utility operations for the foreseeable future.

Note 9 - New Accounting Standards

SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to incorporate issues relating to the Derivatives Implementation Group process, other FASB projects dealing with financial instruments, and the application of the definition of a derivative. The Statement is effective for contracts entered into or modified after June 30, 2003, except for provisions relating to Statement 133 Implementation Issues. Statement 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 14, 2003 are applied in accordance with their respective effective dates. PGE is currently evaluating the impact of the application of SFAS No. 149 but does not expect its adoption to have a material effect on the financial statements of the Company.

SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Included in SFAS No. 150 is a requirement that mandatorily redeemable financial instruments that the issuing company is obligated to redeem at a fixed amount and on specified or determinable dates must be reclassified as liabilities on the balance sheet. In addition, any dividends on such instruments are to be included in interest expense on the income statement. As PGE has outstanding preferred stock that is mandatorily redeemable on fixed dates, the Company is required to comply with SFAS No. 150, beginning July 1, 2003. PGE does not expect the adoption of SFAS No. 150 to have a material effect on its financial statements.

Emerging Issues Task Force Issue No. 01-8 (EITF 01-8), Determining Whether an Arrangement Contains a Lease, provides guidance in determining whether an arrangement or contract should be considered a lease subject to the requirements SFAS No. 13, Accounting for Leases. PGE is required to comply with EITF 01-8 beginning July 1, 2003; arrangements and contracts entered into or modified prior to that date are not affected by the new guidance. PGE is currently evaluating the impact of the application of EITF 01-8 to new or modified contracts that may be entered into in future periods.

Note 10 - Credit Facilities and Debt

On April 8, 2003, PGE issued $50 million of 5.279% First Mortgage Bonds, maturing in 2013. The bonds were issued as a private placement. The Company purchased a policy insuring the principal and interest payments on the Bonds, which will add approximately 1.0% to annual interest costs of these bonds. Net proceeds from this issue were used to refinance current maturities of long-term debt and for other general corporate purposes.

On May 1, 2003, PGE remarketed $142 million of Pollution Control Bonds for a term of six years at fixed rates of 5.20% (for $121 million of the bonds) and 5.45% (for $21 million). The bonds are secured by First Mortgage Bonds issued by the Company.

On May 28, 2003, PGE completed a new $150 million 364-day revolving credit facility with a group of commercial banks. This facility replaced separate $72 million and $150 million facilities, which were terminated upon execution of the new agreement. Under the new credit facility, PGE has the option to use letters of credit, in addition to borrowings, totaling up to the $150 million. The facility contains a material adverse change clause and financial covenants that limit consolidated indebtedness, as defined in the facility, to 60% of total capitalization; it also requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.75:1. The new facility is secured by First Mortgage Bonds issued by the Company and prohibits the payment of any cash dividends or other distributions by PGE on its common stock.

On August 4, 2003, PGE issued $150 million of First Mortgage Bonds, Medium-Term Notes. The bonds were issued through a private placement, with one-third ($50 million) maturing in each of the years 2013, 2023, and 2033. Interest rates for the three maturities are 5.625%, 6.750%, and 6.875%, respectively. Net proceeds from the issues will be used to redeem certain existing long-term debt. Notices of redemption have been issued to redeem on September 3, 2003 the $25 million balance of the First Mortgage Bonds, 9.46% Series due August 12, 2021, and $75 million of the First Mortgage Bonds, 7-3/4% Series due April 15, 2023. In addition, PGE has issued a notice of redemption to redeem on September 4, 2003 for $50 million of 8.25% Junior Subordinated Deferrable Interest Debentures, due December 31, 2035.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the consolidated financial statements 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 2003.

2003 Compared to 2002 for the Three Months Ended June 30

PGE's net income in the second quarter of 2003 was $13 million, compared to $16 million in the second quarter of 2002. The decrease was due primarily to both lower margins on decreased energy sales and higher interest expense, partially offset by a $5 million (net of taxes) increase in Other Income. A power cost adjustment mechanism in place during 2002 partially offset the negative earnings impact of lower energy sales in last year's second quarter; there is no power cost mechanism in effect for 2003.

The following table summarizes Operating Revenues and Energy Sales for the second quarter of 2003 and 2002:

	Three Months Ended
	June 30,						Increase/(Decrease)
Operating Revenues	2003			2002			Amount					%
(In Millions)

Retail	$	313		$		338		$		(25)				(7%)
Wholesale (Non-Trading)	90			101			(11)				(11%)
Other Operating Revenues:
Trading Activities - net	2			1			1				*
Other		5			(1)				6				*
Total Operating Revenues	$		410	$		439		$		(29)				(7%)

Energy Sales
(In Thousands of MWhs)

Retail	4,423			4,378			45					1%
Wholesale (Non-Trading)	2,823			3,828			(1,005)					(26%)
Trading Activities	3,660			3,993			(333)					(8%)
Total Energy Sales	10,906			12,199			(1,293)					(11%)

							(*not meaningful)

The decrease in Retail Revenues was caused primarily by lower prices. As provided by a process included in the OPUC's 2001 general rate order, PGE reduced its retail customer rates on January 1, 2003 to reflect a decrease in projected 2003 variable power costs (see "Retail Rate Changes" in the Financial and Operating Outlook section for further information). Partially offsetting the lower prices was an increase in retail energy sales, due to both warmer temperatures and an increase in the number of customers during the last year. Residential and Commercial energy use increased 3% and 1%, respectively, from last year's second quarter. Decreased Wholesale (Non-Trading) Revenues resulted from lower energy sales due to a reduction in energy marketing activity, reduced hydro production, and increased retail load requirements. Partially offsetting the decrease in wholesale energy sales was a 22% increase in average wholesale power prices, reflecting both increased natural gas prices and adverse hydro conditions in the region. The increase in Other Operating Revenues was primarily related to sales of natural gas in excess of generating plant requirements, as power purchases in the wholesale market economically displaced more expensive gas-fired thermal generation. Such sales in the second quarter of 2003 resulted in a $2 million gain, compared to a loss of $3 million in the second quarter of 2002.

Purchased Power and Fuel expense decreased $34 million (13%) due to both lower system load, resulting from reduced wholesale energy sales, and lower average power prices. PGE's average variable power cost decreased 8% from the second quarter of 2002, due primarily to a decrease in the average cost of power purchases. Purchased Power and Fuel expense in the second quarter of 2002 included a credit for the deferral of approximately $4 million related to the Company's power cost mechanism then in effect, while the second quarter of 2003 includes a $6 million charge for the amortization of costs deferred under the mechanism, which were recovered from customers in the second quarter. There is currently no power cost adjustment mechanism in place for 2003. Company generation approximated that of last year's second quarter, as increased coal-fired generation largely offset decreased combustion turbine and hydro generation. Total generation met approximately 30% of PGE's retail load during the sec ond quarter of 2003, compared to 31% 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 2003 and 2002. Average variable power costs exclude the effect of PGE's power cost mechanisms, discussed above, on purchased power and fuel costs.

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

	2003	2002		2003	2002
Generation	1,399	1,441		7.4	14.2
Firm Purchases	5,616	5,976		31.5	35.7
Spot Purchases	525	1,029		29.4	16.5
Total System Load	7,540	8,446		28.9*	31.4*
			(*includes wheeling costs)

Operating Expenses (excluding Purchased Power and Fuel, Depreciation and Amortization, and taxes) increased $1 million (2%). Increased corporate overhead expenses (including higher pension cost provisions) and customer support expenses were largely offset by a reduction in major maintenance expenses at the Company's generating plants.

Depreciation and Amortization expense increased $14 million (36%), primarily due to decreased amortization of regulatory liabilities, the effects of which were offset within Operating Revenues. This includes $8 million in credits given to customers in the second quarter of 2002 related to a distribution received by PGE in 2000 from Nuclear Electric Insurance Limited. Such amount offset the recovery from customers in last year's second quarter of amounts related to the Company's power cost adjustment covering the period January through September 2001. Other reductions in regulatory liabilities include a combined $4 million in customer credits related to merger-related cost savings and gains on certain major property sales and other nonrecurring items. The remaining increase consists primarily of increased amortization of computer software, including the Company's new customer information and billing system.

Income taxes decreased $6 million primarily due to lower taxable income.

Other Income (Miscellaneous) increased $7 million due primarily to a $3 million increase in the market value of non-qualified benefit plan trust assets and a $1 million increase in interest income on regulatory assets. In addition, last year's second quarter results included a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company.

Interest Charges increased $3 million due primarily to an increase in outstanding long-term obligations, including first mortgage bonds issued in October 2002 and April 2003. Proceeds from the issuance of first mortgage bonds were used to reduce short-term debt, refinance current maturities of long-term debt, and for other general corporate purposes.

2003 Compared to 2002 for the Six Months Ended June 30

PGE's net income in the first half of 2003 was $34 million, compared to $52 million in the first half of 2002. Earnings were unfavorably impacted by a decline in retail energy sales, resulting from both warmer weather in the first quarter of 2003 and from Oregon's continued slow economy. A power cost adjustment mechanism in place during 2002 partially offset the negative earnings impact of lower energy sales in the first half of last year. In addition, the Company recorded an after tax provision of approximately $7 million in the first quarter of 2003 related to amounts due PGE for certain prior year wholesale electricity sales made in California. The reduction in net operating income resulting from the above was partially offset by a $6 million (net of taxes) increase in Other Income. Results for the first half of 2003 include a $2 million gain from a cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143.

The following table summarizes Operating Revenues and Energy Sales for the six-month periods ending June 30, 2003 and 2002:

	Six Months Ended
	June 30,							Increase/(Decrease)
Operating Revenues	2003			2002				Amount							%
(In Millions)

Retail	$	660			$		743			$		(83)		(11%)
Wholesale (Non-Trading)	200			161				39						24%
Other Operating Revenues:
Trading Activities - net	2			-				2						*
Other			19			(1)					20		*
Total Operating Revenues	$		881	$		903			$		(22)		(2%)

Energy Sales
(In Thousands of MWhs)

Retail	9,175			9,320				(145)							(2%)
Wholesale (Non-Trading)	5,495			5,645				(150)							(3%)
Trading Activities	6,230			5,987				243							4%
Total Energy Sales	20,900			20,952				(52)							-

								(*not meaningful)

The decrease in Retail Revenues from the first half of 2002 was caused by both lower prices and energy sales. As provided in the OPUC's 2001 general rate order, PGE reduced its retail customer rates on January 1, 2003 to reflect a decrease in projected 2003 variable power costs (see "Retail Rate Changes" in the Financial and Operating Outlook section for further information). Retail energy sales declined from last year's first half as a result of warmer temperatures in the first quarter of 2003, Oregon's continued slow economy, and increased conservation efforts, as average use for residential customers declined about 4%. Such decreases more than offset an approximate 2% increase in the number of retail customers served. Increased Wholesale (Non-Trading) Revenues resulted from higher market prices, reflecting both increased natural gas prices and adverse hydro conditions in the region. Sales volume declined due to reductions in energy marketing activity and hydro production in the second q uarter of 2003. The increase in Other Operating Revenues was primarily related to sales of natural gas in excess of generating plant requirements, as power purchases in the wholesale market economically displaced more expensive gas-fired thermal generation. Such sales in the first half of 2003 resulted in a $9 million gain, compared to a loss of $11 million in the first half of 2002.

Purchased Power and Fuel expense decreased $7 million (1%) due primarily to lower power prices. PGE's average variable power cost decreased 8% from the first half of 2002, due primarily to the economic displacement of combustion turbine generation with lower-cost power purchases. Purchased Power and Fuel expense in the first half of 2002 included a net $23 million credit related to the Company's power cost mechanism then in effect, consisting of a $31 million credit for the deferral of 2002 power costs and an $8 million charge for amortization of costs deferred in 2001. The first half of 2003 includes a $29 million charge for the amortization of costs deferred under the mechanism in 2001 and 2002 which were recovered from customers in the first half of 2003. There is currently no power cost adjustment mechanism in place for 2003. Also included in the first half of 2003 is an $11.5 million ($7 million after taxes) provision for uncollectible accounts receivable for wholesale electricity sal es in the California market. (For further information, see Note 5, Receivables - California Wholesale Market, in the Notes to Financial Statements). Company generation approximated that of last year's first half, as increased coal-fired generation largely offset both reduced hydro production and combustion turbine generation, resulting from the forced outage of the Coyote Springs plant during the second quarter of 2003. Total generation met approximately 37% of PGE's retail load in the first half of both 2003 and 2002.

Due to anticipated adverse hydro conditions in the region, PGE filed an application with the OPUC seeking deferral, for future recovery from customers, of hydro replacement power costs for the period February 11, 2003 (application date) through December 31, 2003. Operating results for the first half of 2003 do not reflect the deferral of such costs, pending OPUC consideration of the Company's application. Under the Company's proposed methodology, approximately $12 million in power costs would have been deferred for future ratemaking treatment in the first half of 2003, of which $8 million is applicable to the second quarter. Such amount was recorded in the first half of 2003 and fully reserved, pending future disposition by the OPUC. See "Hydro Replacement Power Costs" in the Financial and Operating Outlook section for further information.

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 2003 and 2002. Average variable power costs exclude the effect of PGE's power cost mechanisms, discussed above, on purchased power and fuel costs.

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

	2003	2002	2003	2002
Generation	3,653	3,710	16.9	15.1
Firm Purchases	10,393	9,989	33.9	42.4
Spot Purchases	1,318	1,858	39.9	20.9
Total System Load	15,364	15,557	32.3*	35.3*
(*includes wheeling costs)

Operating Expenses (excluding Purchased Power and Fuel, Depreciation and Amortization, and taxes) decreased $1 million (1%). A reduction in major maintenance expenses at the Company's generating plants was partially offset by an increase in corporate overhead expenses, including increased provision for pension costs.

Depreciation and Amortization expense increased $27 million (33%), primarily due to decreased amortization of regulatory liabilities, the effects of which were offset within Operating Revenues. This includes $8 million in credits given to customers in the first half of 2002 related to a distribution received by PGE in 2000 from Nuclear Electric Insurance Limited. Such amount offset the recovery from customers in last year's first half of amounts related to the Company's power cost adjustment covering the period January through September 2001. Other reductions in regulatory liabilities include a combined $9 million in customer credits related to merger-related cost savings and gains on certain major property sales and other nonrecurring items. The remaining increase consists primarily of a $3 million increase in amortization of computer software, including the Company's new customer information and billing system, and a $2 million increase in the deferral, for future recovery from customers , of costs related to implementation of Oregon's electricity restructuring law. In addition, amortization in the first half of 2002 included a $4 million credit to establish regulatory assets related to the sale of the Pelton Round Butte hydroelectric project.

Income taxes decreased $19 million primarily due to lower taxable income.

Other Income (Miscellaneous) increased $8 million due primarily to a $4 million increase in interest income on regulatory assets, including the deferred Power Cost Adjustment, and to a $1 million increase in the market value of non-qualified benefit plan trust assets. In addition, last year's first half results included a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company.

Interest charges increased $4 million due primarily to an increase in outstanding long-term obligations, including first mortgage bonds issued in October 2002 and April 2003.

Capital Resources and Liquidity

Review of Cash Flow Statement

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

A significant portion of cash from operations comes from depreciation and amortization of utility plant, charges that are recovered in customer revenues but require no current cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash. Cash provided by operating activities totaled $151 million in the first half of 2003 compared to $164 million in the same period last year. The decrease is due primarily to a reduction in the amount of cash collateral deposits refunded by certain wholesale customers, related to the settlement of certain energy contracts.

Cash from operations and remaining proceeds from the April and May 2003 issuance of long-term debt (described below) were invested primarily in government money market funds at June 30, 2003, providing the Company with sufficient liquidity to meet operating and other requirements.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. A $6 million decrease in capital expenditures in the first half of 2003 is primarily due to reduced expenditures related to PGE's distribution system. The $17 million decrease in "Other - net" is related to a 1996 power sale termination agreement, under which the Company received monthly payments of $2.5 million through December 2002.

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

During the first half of 2003, PGE repurchased $142 million in Pollution Control Bonds that were subsequently remarketed (see below). In addition, the Company repaid $4 million of conservation bonds, retired $3 million preferred stock, and paid $1 million in preferred stock dividends. No common stock cash dividends were declared in 2002 or in the first half of 2003.

In April 2003, PGE issued $50 million of 5.279% First Mortgage Bonds, maturing in 2013. The bonds were issued as a private placement. The Company purchased a policy insuring the principal and interest payments on the Bonds, which will add approximately 1.0% to annual interest costs of these bonds. Net proceeds from this issue were used to refinance current maturities of long-term debt and for other general corporate purposes.

In May 2003, PGE remarketed $142 million of Pollution Control Bonds for a term of six years at fixed rates of 5.20% (for $121 million of the bonds) and 5.45% (for $21 million). The bonds are secured by First Mortgage Bonds issued by the Company.

Also in May 2003, PGE completed a new $150 million 364-day revolving credit facility with a group of commercial banks. This facility replaced separate $72 million and $150 million facilities, which were terminated upon execution of the new agreement. Under the new credit facility, PGE has the option to use letters of credit, in addition to borrowings, totaling up to the $150 million; at June 30, 2003, the Company had utilized approximately $3 million in letters of credit. The facility contains a material adverse change clause and financial covenants that limit consolidated indebtedness, as defined in the facility, to 60% of total capitalization; it also requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.75:1. PGE's indebtedness to total capitalization and interest coverage ratio at June 30, 2003 were 46.0% and 4.57:1, respectively. The new facility is secured by First Mortgage Bonds issued by the Company and requires annual facility fees o f 0.25%. The new facility prohibits the payment of any cash dividends or other distributions by PGE on its common stock.

PGE has received approval from the OPUC to issue up to $200 million of First Mortgage Bonds, Medium-Term Notes. On August 4, 2003, PGE issued $150 million of such bonds through a private placement, with one-third ($50 million) maturing in each of the years 2013, 2023, and 2033. Interest rates for the three maturities are 5.625%, 6.750%, and 6.875%, respectively. Net proceeds from the issues will be used to redeem certain existing long-term debt and for other general corporate purposes. Notices of redemption have been issued to redeem on September 3, 2003 the $25 million balance of the First Mortgage Bonds, 9.46% Series due August 12, 2021, and $75 million of the First Mortgage Bonds, 7-3/4% Series due April 15, 2023. In addition, PGE has issued a notice of redemption to redeem on September 4, 2003 for $50 million of 8.25% Junior Subordinated Deferrable Interest Debentures, due December 31, 2035.

In the first half of 2003, existing cash and short-term investments, along with cash provided by operations, replaced the use of commercial paper in meeting the Company's day-to-day requirements. Management believes that the Company has sufficient liquidity to meet such requirements.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in PGE's Articles of Incorporation and the Indenture securing the bonds. As of June 30, 2003, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.

Credit Ratings

PGE's secured and unsecured debt ratings continue to be investment grade from Moody's Investors Service (Moody's), Standard and Poor's (S&P). Fitch Ratings (Fitch) rates PGE's secured debt at investment grade and unsecured debt at below investment grade. PGE's current credit ratings are as follows:

	Moody's	S&P	Fitch

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

Outlook:	Negative	Developing	Positive

On June 4, 2003, Fitch upgraded its ratings of PGE senior secured, senior unsecured, and preferred stock to 'BBB-', 'BB', and 'B+' from 'BB+', 'BB-', and 'B', respectively. In addition, Fitch's Rating Outlook was revised from 'Rating Watch Positive' to 'Positive'.

Should Moody's and S&P reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On June 30, 2003, PGE had posted, in the form of letters of credit, approximately $3 million of collateral. Based on the Company's non-trading and trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of June 30, 2003, the approximate amount of additional collateral that could be requested upon such a downgrade event is $23 million and increases to approximately $26 million by year-end 2003. In addition to collateral calls, such a credit rating reduction could impact the terms and conditions of future long-term debt issuance. In addition, any such rating reductions could increase interest rates and fees on PGE's revolving credit facility, increasing the cost of funding its day-to-day working cap ital requirements.

Due to the Company's increased liquidity and financial flexibility, PGE has regained its ability to access the commercial paper market, to which it had temporarily lost access due to ratings reductions for commercial paper by Moody's and Fitch in May 2002. Management believes that its existing lines of credit and cash from operations provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

Although measures of PGE's financial performance, including financial ratios, remain strong, due to continuing uncertainty regarding the impact of Enron's bankruptcy on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, PGE management believes there are sufficient structural and regulatory mechanisms to protect the Company's assets from Enron and its creditors and there are no economic incentives for Enron to cause PGE to file for bankruptcy protection.

Financial and Operating Outlook

Retail Customer Growth and Energy Sales

Weather adjusted retail energy sales increased 0.7% for the six months ended June 30, 2003, compared to the same period last year, as residential, commercial, and industrial sector energy sales increased 0.8%, 0.4% and 1.0%, respectively. PGE forecasts a 1% decrease in energy sales from 2002 to 2003, due to reduced energy use by two large industrial customers, one of which has elected to obtain its electricity requirements through co-generation. Excluding such customers, PGE anticipates weather adjusted energy sales to increase by approximately 1% in the current year.

Power Supply

Hydro conditions in the region 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, currently project the January-to-July runoff at 83% of normal, compared to 97% of normal in 2002.

PGE generated 37% of its retail load requirement in the first half of 2003, with hydro generation comprising about 7% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers.

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

Enron Bankruptcy

Bankruptcy Proceeding and Chapter 11 Plan

Commencing in December 2001, Enron and certain of its subsidiaries 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. In August 2002, Enron commenced a formal sales process for its interests in certain of its major assets, including PGE, to maximize value and enhance recovery for its creditors. Enron reserved the right not to sell any of the assets if the bids are not deemed fully reflective of the value of the assets.

Liabilities and Impairments

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

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

1. Amounts Due from Enron and Enron-Supported Affiliates in Bankruptcy - As described in Note 4, Related Party Transactions, in the Notes to Financial Statements, PGE is owed approximately $84 million (including accrued interest) by Enron at June 30, 2003 (Merger Receivable). Such amount was to have been paid by Enron to PGE for price reductions granted to customers, as agreed to by Enron at the time it acquired PGE in 1997. Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy Court for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including $73 million for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. In addition, at June 30, 2003, PGE has outstanding accounts receivable of $7 million from other Enron subsidiary comp anies which are part of the bankruptcy proceedings, including $5 million due from Portland General Holdings, Inc. and $2 million due from EPMI. Based on management's assessment of the realizability of these balances, a reserve of $4 million has been established.

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

Pension Plans

Funding Status

The pension plan for the employees of PGE (the PGE Plan) is separate from the Enron Corp. Cash Balance Plan (the Enron Plan). Although at December 31, 2002 the total fair value of PGE Plan assets was $16 million lower than the projected benefit obligation on a SFAS No. 87 (Employers' Accounting for Pensions) basis, the PGE Plan was over-funded on an accumulated benefit obligation basis by about $30 million as of December 31, 2002. Enron's management has informed PGE that, as of December 31, 2002, the assets of the Enron Plan were less than the present value of all accrued benefits by approximately $52 million on a SFAS No. 87 basis and approximately $182 million on a plan termination basis. Further, Enron's management has informed PGE that the PBGC has filed claims in the Enron bankruptcy cases. The claims are duplicative in nature, representing unliquidated claims for PBGC insurance premiums (the Premium Claims) and unliquidated claims for due but unpaid minimum funding contributions (the Contribution Claims) under the Internal Revenue Code of 1986, as amended (the Tax Code) 29 U.S.C. Section 1082 and claims for unfunded benefit liabilities (the UBL Claims). Enron and the relevant sponsors of the defined benefit plans are current on their PBGC premiums and their contributions to the pension plans. Therefore, Enron has valued the Premium Claims and the Contribution Claims at $0. The total amount of the UBL Claims is $305.5 million (including $271 million for the Enron Plan, and $24.8 million for the PGE Plan). In addition, 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 provided no support (statutory or otherwise) for this assertion and Enron management disputes the validity of any such claim.

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

Enron cannot itself terminate the Enron Plan while it is underfunded unless it provides at least 60 days notice and the PBGC, in the case of solvent entities, or the Bankruptcy Court, in the case of insolvent entities, determines that each member of Enron's controlled group, including PGE, is in financial distress, as defined in ERISA. In the opinion of management, PGE is a solvent entity that does not meet the financial distress test. Consequently, management believes that it is unlikely that Enron can unilaterally terminate the Enron Plan while it is underfunded. However, Enron could, with consent of the PBGC (see discussion below), seek to terminate the Enron Plan while it is underfunded. Moreover, if it satisfies certain statutory requirements, Enron can commence a voluntary termination by fully funding the Enron Plan, in accordance with the Enron Plan terms, and terminating it in a "standard" termination in accordance with ERISA.

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

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

If the proposal to fund and terminate the Enron Plan, as stated in the Disclosure Statement, 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. However, there can be no assurance that this proposal will remain in the Plan ultimately approved by the Debtors' creditors. In addition, as stated in the Disclosure Statement, there can be no assurance that the funding and termination will be approved by the Bankruptcy Court or that, upon such approval, Enron will have the ability to obtain funding on acceptable terms.

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

Minimum Funding Obligation

If the sponsor of a pension plan does not timely satisfy its minimum funding obligation to the pension plan, once the aggregate missed amounts exceed $1 million, a lien in the amount of the missed funding automatically 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 management understands that Enron has made all required contributions to date and the next contribution is not due until September 2003. PGE does not know if Enron will make contributions as they become due. Management is unable to predict if Enron will miss a payment and, if so, whether the PBGC would seek to have PGE make any or all of the payment. If the PBGC did look solely to PGE to pay the missed payment, PGE would exercise all legal rights, if any, available to it to defend against such a demand and to recover contributions from the other solvent members of the Enron controlled group. Until Enron 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 PG E for any amounts related to this issue.

Retiree Health Benefits

Income Taxes

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

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

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

Enron's 2002 tax return has not yet been filed. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2002. Enron expects that, in addition to offsetting its income tax liabilities for years before 2002, these NOLs will be sufficient to fully offset Enron's regular and alternative minimum income tax liabilities for 2002 and its regular income tax liability for all subsequent periods through the date of consummation of its plan of reorganization.

Enron believes that all of the requirements for re-consolidation of PGE with the Enron consolidated group have been met. The Disclosure Statement states that the Debtors intend to seek a determination from the IRS confirming that PGE did in fact become a member of the Enron consolidated group on December 24, 2002. However, because of the inherently factual nature of the determination of the re-consolidation, there can be no assurance that the IRS will agree to rule, or if it does agree to rule, to agree with this position. In the event that the IRS does not agree and the matter is not otherwise resolved in the bankruptcy proceeding, PGE will file an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax allocation agreement. Enron management believes that all administrative expense claims will be paid in full.

PGE management cannot predict with certainty what impact Enron's bankruptcy, including the chapter 11 Plan, may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Neither PGE nor Enron have guaranteed the obligations of the other. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and PGC in 1997 (Merger Conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the Merger Conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The Merger Conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis.

PGE management does not believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. As a solvent enterprise in bankruptcy, PGE would owe fiduciary obligations to its shareholders and creditors. If a bankruptcy were commenced, the United States Trustee would form a creditors' committee comprised of PGE's largest creditors, and any plan of reorganization would be subject to confirmation by the Bankruptcy Court. Prior to the effectiveness of such plan, no dividends could be paid to Enron, and no assets could be sold, or transfer of funds could be made, outside the ordinary course of business except with the approval of the Bankruptcy Court. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede sta te regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in litigation. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course. On September 30, 2002, the Company issued to an independent shareholder a single share of a new $1.00 par value class of Limited Voting Junior Preferred Stock which limits, subject to certain exceptions, PGE's right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceedings without the consent of the shareholder.

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

Enron Debtor in Possession Financing

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

Enron Auction Processes Related to PGE

Threatened Litigation - 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. In 1989, sponsorship of these arrangements was transferred to Portland General Corporation (which was subsequently merged into Enron in 1997) and in 1997 sponsorship was transferred to Portland General Holdings, Inc. Although plan sponsorship was transferred, PGE continued to participate in these plans as a participating employer for the benefit if its own employees. Portland General Corporation, Portland General Holdings, Inc., and certain of their subsidiary companies also had employees who participated in these plans. The plan documents specifically provide that: (1) a participating employer's obligation under the plans shall be that of an unfunded and unsecured promise to pay money in the future; and, (2) the payment of a participant's benefit pursuant to the plan shall be borne solely by the participating employe r that employs the participant and reports the participant as being on its payroll during the accrual or increase of the plan benefit, and no liability for the payment of any plan benefit shall be incurred by reason of plan sponsorship or participation except for the plan benefits of a participating employer's own employees. Upon the bankruptcy filing by Enron and certain of its affiliates, and the subsequent bankruptcy filing of Portland General Holdings, Inc., payment by those companies of participant benefits under these plans ceased. Since PGE is not in bankruptcy, benefit payments to participants due benefits from PGE have continued. Plan participants with benefits due from the bankrupt companies have sought to have the companies or the trusts commence payments without success. Certain of these Plan participants have recently been quoted in the press as stating their intention to commence a lawsuit against PGE and other parties if their benefit payments are not resumed. If any lawsuit is filed, PGE inte nds to vigorously defend that case.

Public Ownership Initiatives

The City Council of Portland, Oregon has passed resolutions, in August 2002 and June 2003, authorizing the expenditure of up to $850,000 for professional advice regarding the City's potential acquisition of PGE, including possible condemnation of the Company's assets. The City has signed a confidentiality agreement with Enron to permit it to participate in the Enron auction process relating to PGE which is continuing.

Initiative petitions circulated in Multnomah County obtained sufficient signatures to place a measure on an election ballot that, if passed, could result in the formation of a Peoples' Utility District (PUD) in Multnomah County. In June 2003, the Multnomah County Board of Commissioners determined the boundaries of a proposed PUD and set a PUD formation initiative on the November 4, 2003 ballot to be voted on by the county voters. In August 2003, initiative petitions circulated in Yamhill County also obtained sufficient signatures to place a measure on an election ballot. After a hearing, the Yamhill County Commissioners are required to determine the boundaries of the proposed PUD and set a date for voting on the formation initiative. The expressed intent of the PUD supporters is to have additional elections to expand the PUD boundaries to include all of PGE's service territory. If a PUD is formed, it would have the authority to condemn PGE's distribution assets within the boundaries of the district. Oregon law prohibits a PUD from condemning thermal generation plants. It is uncertain under Oregon law whether a PUD would be able to condemn PGE's hydro generation plants.

PGE opposes the formation of PUDs in its service territory and will oppose any efforts to condemn the Company's assets.

Complaints to OPUC

Income Taxes

On March 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) filed a petition to open an investigation and a complaint with the OPUC with respect to the amount of federal, state, and local income taxes paid by PGE since 1997. On March 31, 2003, the OPUC rejected the request for an investigation and on July 9, 2003 issued an order that dismissed the complaint.

Limited Voting Junior Preferred Stock

On May 7, 2003, the Utility Reform Project and Linda K. Williams (Complainants) served the OPUC with a complaint filed in Marion County Circuit Court on March 17, 2003 seeking to vacate OPUC Order 02-674 in which the OPUC granted authority to the Company to issue a share of Limited Voting Junior Preferred Stock. The complaint alleges that the OPUC did not follow the proper procedure in issuing the Order. The complaint seeks to have the matter remanded to the OPUC for further proceedings. PGE has intervened in the case and will oppose the relief sought by the Complainants. For further information, see Note 4, Common and Preferred Stock, in PGE's report on Form 10-K for the year ended December 31, 2002.

Retail Rate Changes

Power Cost Price Decrease - 2003

The OPUC's 2001 general rate order contains a Power Cost Stipulation 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 of Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, a Resource Valuation Mechanism (RVM) utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM process requires that PGE adjust its rates if its projected power costs change from those included in the previous RVM rate process. It provides for an adjustment, filed annually and finalized in mid-November, which is effective January 1 of the following year.

PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the cost of power from that utilized in the Company's 2001 general rate case. Accordingly, the OPUC authorized reductions in the Company's retail prices, effective January 1, 2003. Price decreases range from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased in the 2003 forecast. The smaller decrease in residential rates reflects the cost of electricity from BPA, which increased its rates in October 2002, as well as PGE's cost of generation. Based upon projected energy sales, it is estimated that such price decreases will reduce PGE's 2003 revenues by approximately $100 million.

Included in the price reduction is the effect of the OPUC's disallowance, based upon a prudence review, of approximately $15 million related to four power purchase contracts, entered into in the first half of 2001, providing 125 megawatts of on-peak delivery in 2003.

The new prices also reflect both a resolution regarding the recovery period for PGE's power cost mechanism covering the period October 2001 through December 2002 and the effect of a settlement stipulation related to estimated 2003 power costs. Under such settlement, PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million, which was reflected as a reduction to the Company's earnings for 2002.

Power Cost Adjustment Mechanisms

As actual power costs in any year may differ substantially from those costs used in rate determination, the OPUC in 2001 authorized power cost adjustment mechanisms that allowed the Company to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts. Under the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received 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, 2003, the remaining balance to be collected was approximately $61 million.

In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount, subject to a prudence review and audit currently being conducted by the OPUC, is being collected from large industrial customers over a one-year period (2003) and over a two-year period (2003-2004) from all other customer classes. At June 30, 2003, the balance to be collected was approximately $26 million.

Although PGE does not have a power cost adjustment mechanism in place for 2003, the Company has filed with the OPUC an application to defer for later ratemaking treatment increases in power costs related to expected adverse hydro conditions (see "Hydro Replacement Power Costs" below for further information).

Hydro Replacement Power Costs - 2003

A region-wide drought throughout the Pacific Northwest has resulted in adverse hydro conditions for PGE and other utilities, with early forecasts indicating hydro conditions significantly below normal. In anticipation of the effects of such conditions, PGE began to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those contained in the Company's current rates.

On February 11, 2003, PGE filed with the OPUC an Application for Deferral of Hydro Replacement Power Costs, in which the Company requests authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requests authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates, with interest accrued at PGE's authorized rate of return. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Although the amount of the deferral would be determined over the course of the year, PGE estimates that the amount could range from $20 million to $60 million. The application is currently pending before the OPUC.

Under the Company's proposed methodology, approximately $12 million in power costs would have been deferred for future ratemaking treatment in the first half of 2003, of which $8 million is applicable to the second quarter. Such amount was recorded in the first half of 2003 and fully reserved, pending future disposition by the OPUC.

Preliminary Power Cost Filing - 2004

On April 1, 2003, PGE submitted a Resource Valuation Mechanism filing with the OPUC containing an estimate of 2004 power costs based upon preliminary information. The filing also included a proposed power cost adjustment mechanism for 2004 and beyond.

On August 6, 2003, following filed testimony and settlement conferences between the Company, OPUC staff, and intervenors, the participating parties entered into a Stipulation that provides for certain reductions in PGE's forecast of 2004 net variable power costs. The Stipulation is subject to approval by the OPUC. The reductions are based upon an adjustment in the price of certain wholesale power purchase contracts, reflecting recent electricity forward prices, as well as certain other modifications and adjustments to estimated variable power and fuel costs. Final adjustments to 2004 retail prices will be determined in November 2003.

The Stipulation also provides that PGE withdraw its proposed power cost adjustment mechanism for 2004 and participate in a process to address the need for, and structure of, a cost recovery mechanism for variances in power costs from forecasted levels, with an objective to complete such process by year-end 2003.

Electric Power Industry Restructuring

Oregon's electric energy industry restructuring plan, implemented on March 1, 2002, provides all of PGE's commercial and industrial customers direct access to competing energy suppliers. The RVM document filed by the Company with the OPUC on April 1, 2003 includes proposed changes that will facilitate the ability of such customers to make decisions related to direct access service and electricity pricing options. Residential and small business customers can continue to purchase electricity from a "portfolio" of rate options that include a basic service rate, a time of use rate, and renewable resource rates.

Integrated Resource Plan

In August 2002, PGE filed a new Integrated Resource Plan, with a supplement filed in February 2003. In its Plan, PGE describes its strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. The Plan, which considers resource actions over the next two to three years, includes reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. It also considers future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, long-term power purchases, and meeting seasonal peaking requirements through seasonal exchanges, demand-side management, capacity tolling contracts, and combustion turbine development. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by late-2003.

On June 18, 2003, pursuant to approval by the OPUC, PGE issued a request for proposals (RFP) to prospective suppliers (including power generators, wholesalers, and developers) to acquire up to 600 average megawatts of energy products by October 2006 and 400 megawatts of capacity resources by December 2005. By the July 23, 2003 response due date, more than 40 entities had responded with more than 90 proposals, involving energy solutions ranging from wind and geothermal resources, as well as those fueled by coal and natural gas. PGE intends to identify specific parties and initiate negotiations in August 2003. Based upon results of this process, PGE plans to update its resource action plan with specific recommendations, scheduled for announcement in October 2003. PGE will then request acknowledgement that the Company's final plan is consistent with least cost planning principles established by the OPUC.

On July 22, 2003, PGE issued a request for qualifications (RFQ) to approximately 150 of the Company's largest business customers, seeking interest in voluntary demand management programs. Such programs generally consist of an agreement between PGE and the customer to either reduce, or adjust the timing of, electricity consumption during periods of peak usage or critical power shortage. The objective of the RFQ process is to encourage efficient use of resources, thereby enabling PGE to minimize resource costs. Responses to the RFQ are due from customers by August 18, 2003, with qualifying plans identified and included in the Company's resource action plan scheduled for announcement in October 2003.

PGE will continue to evaluate its options with regard to the construction of additional generation, including a two-unit 600-MW gas turbine plant adjacent to its Beaver plant site (Port Westward Generating Project), considering the availability of reasonably priced medium to long-term power purchases from the market. The Company will continue to monitor changes in economic conditions and the effect of restructuring legislation that allows large customers to purchase power directly from electricity service suppliers.

Receivables - California Wholesale Market

On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code.

Refunds on Wholesale Transactions

California

Pacific Northwest

Potential Refund Mitigation

FERC Orders on Gaming and Anomalous Market Behaviors

On June 25, 2003, the FERC ordered over 50 entities, including PGE, that participated in the Western wholesale power market between January 1, 2000 and June 20, 2001 to show cause why their participation in specific behaviors and activities during that time period did not constitute gaming in violation of tariffs issued by the ISO and the PX. The ISO was ordered to provide data on each entity's behaviors and activities within 21 days from the date of the order. Within 45 days from the receipt of the data, each entity must respond, explaining the alleged participation in the identified activities or behaviors.

Also on June 25, 2003, the FERC initiated a generic investigation into bids by market participants in ISO and PX markets between May 1, 2000 and October 2, 2000 at levels above $250/Mwh. The FERC determined that such bids were legally sufficient evidence of anomalous market behavior under the ISO and PX Market Monitoring and Information Protocols. Entities submitting such bids will be required to demonstrate why such bids did not constitute anomalous market behavior and the extent to which they constituted legitimate business behavior. During the indicated time period, PGE made bids that exceeded $250/Mwh in both the ISO and PX markets. PGE submitted responses to the FERC on July 24, 2003 and August 1, 2003 and is continuing to analyze the Company's bid data.

The FERC indicated that monetary remedies under these orders will be the disgorging of unjust profits associated with the violations, and that non-monetary remedies, such as revocation of market-based rates or revisions to codes of conduct, will also be considered. PGE will assess the data produced by the ISO and the FERC staff and make appropriate responses to the FERC.

Wholesale Price Mitigation

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

Under the program, a ceiling price was set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator (ISO) and in markets in the other Western states. Such price, initially set at $91.87/MWh, reflected specified fuel, operations, and maintenance costs, and was based upon the bid submitted by the highest cost gas-fired generating unit supplying power during a Stage 1 supply emergency.

In December 2001, the FERC temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the ISO, recognizing differences between Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. The changes, including a ceiling price of $108/MWh, were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.

In July 2002, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 31, 2002. The new ceiling price applies to all sales of electricity in the WECC. In addition to the new price ceiling, the FERC order established conditions and rules guiding participation in Western wholesale electricity markets, including automatic price mitigation procedures to be implemented during periods of tight supplies.

FERC Investigations - Wholesale Power Markets

On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WECC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. In April 2002, the Company submitted the requested information. Additionally, on March 15, 2002 the FERC enforcement staff issued a subpoena to Enron, which Enron then forwarded to the Company. In response to this subpoena, the Company provided information related to its trading organization, its trading policies and procedures, its price curves and their derivation, and its trading position reports.

As a result of an internal investigation, PGE discovered that it had failed to properly post on a public web site information about some of its energy transactions with an affiliate, Enron Power Marketing, Inc. The preliminary results of this investigation were disclosed to FERC Staff on April 15, 2002 and final results on August 1, 2002. This issue was subsequently included in the investigation in Docket No. EL02-114-000 described below.

Enron Trading Strategies

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

On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. The order stated that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. On June 14, 2002, PGE filed a response indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE. PGE reaffirmed its belief that it had fully cooperated with the FERC's inquiry.

On August 13, 2002, the FERC issued two orders initiating investigations into instances of possible misconduct by PGE and certain other companies. In the first order (Docket No. EL02-114-000), the FERC ordered investigation of PGE and EPMI related to possible violations of their codes of conduct, the FERC's standards of conduct, and the companies' market-based rate tariffs, and whether PGE has cooperated by providing all relevant information related to the FERC's May 8, 2002 data request and June 4 Show Cause Order. In the second order (Docket No. EL02-115-000), the FERC ordered investigation of Avista Corporation and Avista Energy, Inc. (collectively, Avista) with respect to, among other things, transactions in which Avista engaged in or facilitated the trading strategies identified in the Enron memoranda or acted as a middleman with respect to sales of electric energy between PGE and EPMI. PGE and EPMI were included as parties in that Docket. In the orders, the FERC established October 1 5, 2002 as the "refund effective date." Issues involving PGE and EPMI in Docket No. EL02-115-000 have now been consolidated into Docket No. EL02-114-000. If PGE were to lose its market-based rate authority, purchasers of electric energy from PGE at market-based rates after the refund effective date could be entitled to a refund of the difference between the market-based rates and cost-based rates deemed just and reasonable by the FERC.

On December 10, 2002, the FERC trial staff released a Revised Statement of Asserted Violations (Revised Statement) and its initial testimony in its investigation of PGE (Docket No. EL02-114-000). The assertions in the Revised Statement and testimony are limited to PGE's self-reported failure to properly post information about some of its energy transactions with EPMI, and alleged violations for affiliate dealings with EPMI relating to a series of transactions that occurred on certain days in April-June 2000, involving PGE, EPMI, and Avista Corporation. The latter transactions were previously reported by PGE to FERC on May 22, 2002 in response to the FERC's May 8, 2002 data request. The trial staff recommended a remedy of revocation of PGE's market-based rate authority for two years, and a requirement that PGE's application for reinstatement of market-based rates include documentation supporting revised procedures to ensure that posting errors and violations of affiliate rules do not occur again. The City of Tacoma, Washington filed testimony seeking a refund from PGE of $3.2 million. The California Attorney General and the California Public Utilities Commission have filed testimony that PGE should refund amounts to compensate market participants for PGE's alleged unlawful conduct, but the testimony specifies no amount of refunds.

PGE's initial response testimony in Docket No. EL02-114-000 was filed on February 24, 2003. In its testimony, PGE describes the posting errors it self-reported, most of which were technical in nature and may in fact not have been in error. The Company also described the cooperation it has extended to the FERC, the investigative staff, and the trial staff in providing all requested information to aid the investigation. PGE also provided testimony that the April-June 2000 transactions with EPMI did not involve violations of affiliate rules, except for certain posting errors. Trial staff and other parties filed response testimony on May 12, 2003.

The hearing in Docket No. EL02-114-000 is scheduled to begin on October 21, 2003, and is expected to last two weeks. Staff and the intervenors had an opportunity to file additional testimony on August 4, 2003, but declined to do so. PGE may respond with additional testimony on September 12, 2003, and Staff and intervenors may file rebuttal testimony on September 29, 2003. The initial decision from the presiding FERC judge is due on December 19, 2003.

PGE will continue to cooperate with the investigations. PGE continues to believe that it has fully complied with the FERC investigation initiated on February 13, 2002, and that it has not engaged in deception or market manipulation. The Company and certain of the parties in the process have been engaged in settlement discussions related to these matters. At this time, management is unable to predict the ultimate outcome of these matters.

Wash Sales - Electricity

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

Wash Sales - Natural Gas

On May 22, 2002, the FERC issued a data request and request for admissions to all sellers of natural gas in the U.S. portion of the WECC and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. PGE denies that it engaged in trading activities described in the FERC data request. There have been no further inquiries or orders received from the FERC related to PGE's participation in these activities.

Challenge of the California Attorney General to Market-Based Rates

On March 20, 2002, the California Attorney General filed a complaint with FERC against various sellers in the wholesale power market, alleging that the FERC's market-based rates violate the Federal Power Act ("FPA"), and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do 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 should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to refile their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals.

Other

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

Antitrust Litigation

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

The Duke Parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. The Reliant Parties have filed a cross complaint against PGE and the other utilities, generators, traders and other entities similar to the cross complaint filed by the Duke Parties. The cases were remanded to Federal Court by certain parties. The parties have stipulated to place the cross complaints in abeyance until 30 days after a ruling on the motions to dismiss the Master Complaint.

On December 13, 2002, a United States District Court signed an order granting the plaintiff's motions to remand the cases to the California state court, but the order was not immediately implemented. The Duke and Reliant Parties filed an appeal to the United States Ninth Circuit Court of Appeals and applied to the District Court for a stay of the remand to the California state court. On January 24, 2003, the District Court denied the application for a stay and set for hearing certain motions for reconsideration. On February 20, 2003, the United States Court of Appeals for the Ninth Circuit issued an Order deciding it had jurisdiction to hear the appeals from the District Court's December 13, 2002 remand order. The Ninth Circuit also issued a stay of the remand order pending the outcome of the appeals and set a briefing schedule that will not be completed until mid-September 2003. As stated above, the cross complaint against PGE will be continued in abeyance until 30 days after a ruling is entered on the motions to dismiss the Master Complaint.

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

California Attorney General Complaint

In May 2002, the Attorney General of California filed a complaint in state court alleging failure of PGE to comply with the Federal Power Act (FPA) and with the FERC requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price" or a reasonable price and for each alleged regulatory violation. No specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to U.S. District Court and a Motion to Dismiss on preemptive grounds. The Attorney General moved to remand to state court, which was denied. The Attorney General filed an appeal to the Ninth Circuit Court of Appeals of the denial of the motion to remand, and moved to stay action in the District Court pending the outcome of the appeal. The District Court, finding the appeal frivolous, refused to stay the case. Motions to dismiss the case were argued on September 26, 2002. On March 25, 2003, the judge dismissed the complaint against PGE. On March 28, 2003, the Attorney General filed a Notice of Appeal with the Ninth Circuit.

Oregon Public Utility Commission Staff Report on Trading Activities

On April 29, 2003, the Staff of the OPUC issued a draft report entitled "Trading Activities by Portland General Electric, PacifiCorp, and Idaho Power Company during the Western Electricity Crisis of 2000-01: Did They Violate Any Oregon Statutes, Rules, or Orders" (Draft Report).

In the Draft Report, the Staff makes two recommendations applicable to PGE: First, that the OPUC affirm that it will hold harmless the customers of PGE, PacifiCorp, and Idaho Power (the Utilities) in the event any penalties are imposed by the FERC or any other authority investigating the trading activities of the Utilities; and second, that the OPUC open a formal investigation of PGE's trading activity in 2000-01. The Staff recommended a two-stage proceeding, with the first stage to address whether PGE mismanaged its trading activities during that period. In the event that the OPUC determined that PGE mismanaged its trading activities, the second stage would address the appropriate relief.

With respect to possible misconduct, the Staff stated that there has been no ruling that any trading activities by PGE broke any federal laws or requirements, and that the effect on the wholesale market of PGE's trading activities currently under investigation by the FERC apparently was small. With respect to possible mismanagement, the Staff stated that it believes that there is a prima facie case that PGE mismanaged certain of its trading activities with an affiliate, EPMI, but acknowledged the case is "not open and shut."

On June 12, 2003, the OPUC delayed any decision on commencing an investigation of PGE's trading activities until after the FERC has substantially completed its inquiry of PGE trading activities. The hearing on the FERC investigation has been set for October 21, 2003, with an initial decision scheduled on or before December 19, 2003.

Management does not believe that PGE engaged in any misconduct. In addition, although PGE self-reported to the FERC more than a year ago the failure to post information about certain energy transactions with EPMI, management does not believe that PGE's trading activities with EPMI rise to the level of mismanagement suggested by the Staff. Management cannot at this time predict if the OPUC will conduct an investigation or the possible outcome if an investigation is commenced. However, it believes this matter will not have a material adverse impact on the financial condition or results of operations of the Company.

Montana Attorney General Complaint

On June 30, 2003, the Montana Attorney General filed a complaint in Montana state court against PGE and numerous named and unnamed generators, suppliers, traders, and marketers of electricity and natural gas in Montana. The complaint alleges unfair and deceptive trade practices in violation of the Montana Unfair Trade and Practices and Consumer Protection Act, deception, fraud and intentional infliction of harm arising from various actions alleged to have been undertaken in the western wholesale electricity and natural gas markets during 2000 and 2001. The relief sought includes injunctive relief to prohibit the unlawful practices alleged, treble damages, general damages, interest, and attorney fees. No monetary amount is specified.

Port of Seattle, Washington Complaint

On May 21, 2003, the Port of Seattle, Washington (Port) filed a complaint in the United States District Court for the Western District of Washington against PGE and sixteen other companies (Defendants) alleging violation of both the Sherman Act and the Racketeer Influenced and Corrupt Organization Act, fraud, and, with respect to Puget Energy, Inc. and Puget Sound Energy, Inc., breach of contract. The complaint alleges that the price of electric energy purchased by the Port between November 1997 and June 2001 under a contract with Puget Sound Energy, Inc. was unlawfully fixed and artificially increased through various actions alleged to have been undertaken in the Pacific Northwest power markets among Defendants and Enron, Enron Energy Services, Inc., Enron North America Corp., Enron Power Marketing, Inc., and others. The complaint alleges actual damages of $30.5 million suffered by the Port and seeks recovery of that amount, plus punitive damages and reasonable attorney fees.

Trojan Investment Recovery

Due to the closure of the Trojan Nuclear Plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals, and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant.

Although management cannot predict the ultimate outcome of the related legal challenges, it believes that they 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. For further information, see Note 3, Legal and Environmental Matters, in the Notes to Financial Statements.

Nuclear Decommissioning

Activities related to the decommissioning of Trojan are proceeding satisfactorily in accordance with PGE's Trojan Decommissioning Plan. A license amendment for the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that will house the nuclear fuel until permanent storage is available, was approved by the NRC in 2002. Fuel loading began in late 2002 and is expected to be completed by the end of August 2003. The fuel will be contained in thirty-four multi-purpose canisters, thirty-two of which have been loaded, sealed, and placed on the ISFSI pad as of July 29, 2003.

Union Grievances

Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. For further information, see Note 3, Legal and Environmental Matters, in the Notes to Financial Statements.

Environmental Matter

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

Colstrip Project Litigation

On May 5, 2003, Robert & Julie Remington and forty-eight other individuals, unions and businesses filed a suit against PGE and the other owners, designers and operators of the Colstrip coal-fired electric generation plants (Colstrip Project) in Montana alleging that holding and settling ponds at the Colstrip Project have leaked and contaminated groundwater. The plaintiffs allege nuisance, trespass, unjust enrichment, fraud, and negligence, and seek a declaratory judgment of nuisance and trespass, an order that the nuisance be abated, and an unspecified amount for damages, disgorgement of profits, and punitive damages.

Public Utility Holding Company Act of 1935

All of the common stock of PGE is owned by Enron. As the owner of PGE's common stock, Enron is a holding company for purposes of PUHCA. Following Enron's acquisition of PGE in 1997, Enron annually filed on Form U-3A-2 for an exemption from all provisions of PUHCA (except Section 9(a)(2) thereof) under Section 3(a)(1), in accordance with Rule 2 promulgated thereunder. Due to Enron's bankruptcy filing in December 2001, Enron is no longer able to provide necessary financial information needed to file on Form U-3A-2. As a result, in February 2002, Enron filed an application on Form U-1 seeking exemption under Section 3(a)(1). To be eligible for the Section 3(a)(1) exemption it is necessary, among other things, that PGE's utility activities be predominantly intrastate in character.

Following the submission of testimony by the parties to the proceeding, a hearing on Enron's application was held on December 5, 2002. On February 6, 2003, the administrative law judge issued an Initial Decision holding that PGE does not meet the criteria to be predominantly intrastate in character, and denying Enron's application for exemption under 3(a)(1). On February 27, 2003, Enron filed a Petition for Review with the SEC requesting that the SEC review the administrative law judge's Initial Decision, reverse such Initial Decision, and find that Enron is entitled to exemption from PUHCA. Filing of the Petition for Review stays the effect of the Initial Decision until such time as the SEC may act on the Petition for Review. The SEC could act on the Petition for Review at any time. Possible responses of the SEC to the Petition for Review include setting the matter down for further hearings before the full Commission or summarily affirming the Initial Decision. In the event that the Initi al Decision is affirmed by the SEC, either summarily or after further hearings, Enron could be required to register as a holding company under PUHCA and PGE would become a subsidiary of a registered holding company.

PUHCA imposes a number of restrictions on the operations of a registered holding company and its subsidiaries, including SEC approval of securities issuances (including those by utility subsidiaries that have not been authorized by the relevant state utility commissions) and engaging directly or indirectly in non-utility businesses. PUHCA also regulates transactions between the affiliates within the holding company system, including the provision of services by holding company affiliates to the system's utilities. If PGE were to become a subsidiary of a registered holding company, it would become subject to regulation by the SEC not only with respect to the acquisition of the securities of other public utilities, but also with respect to, among other things, payment of dividends out of capital and surplus, certain affiliate transactions, issuance of securities, and the acquisition of assets and interests in any other business.

On June 11, 2003, the SEC issued an order granting Petitions for Review (Petitions) filed with the SEC by Enron and others on February 27, 2003. The Petitions request that the SEC review the February 6, 2003 Initial Decision of the administrative law judge that PGE does not meet the criteria to be predominantly intrastate in character and denying Enron's application for exemption under Section 3(a)(1) of the Public Utility Holding Company Act of 1935.

Briefs supporting the Petitions were filed on July 21, 2003. Briefs in opposition are to be filed by August 20, 2003, and any reply briefs are to be filed by September 3, 2003.

Although PGE is unable to predict whether Enron will retain its status as an exempt holding company, PGE does not believe that becoming a subsidiary of a registered holding company would have a material adverse affect on its financial condition or results of operations. However, the finding that PGE is not an intrastate utility could make it more difficult for any future owner of PGE to obtain a 3(a)(1) exemption from PUHCA.

New Accounting Standards

See Note 9, New Accounting Standards, in the Notes to Financial Statements for information regarding SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and EITF 01-8, Determining Whether an Arrangement Contains a Lease.

Information Regarding Forward-Looking Statements

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

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

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

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

events related to Enron's bankruptcy;

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

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

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

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

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

operational factors affecting PGE's power generation facilities;

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

and policies;

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

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

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

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

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

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

acquisition of PGE's assets by eminent domain or by a government entity;

legal and regulatory proceedings and issues;

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

general political, economic, and financial market conditions.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

PGE's primary business is to provide electricity to its retail customers. The Company uses both long- and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to seasonal 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 Operating Revenues. In addition, Company policy allows the use of these instruments for trading purposes, which may expose the Company to market risks resulting from adverse changes in commodity prices. Under EITF 02-3, gains and losses on such instruments are recognized on a net basis within Operating Revenues on PGE's Income Statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments.

PGE actively manages its risk to ensure compliance with its risk management policies. The Company monitors open commodity positions in its energy portfolios using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months including estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the trading portfolio in the first half of 2003 was $0.2 million, $0.5 million, and $0.1 million, respectively, and in the first half of 2002 was $0.2 million, $0. 4 million, and $0, respectively. The average, high, and low value at risk on the non-trading portfolio in the first half of 2003 was $2.1 million, $2.6 million, and $1.9 million, respectively. The value at risk on the non-trading portfolio was not meaningful in the first half of 2002 as the majority of the portfolio was effectively accounted for on an accrual or settlements basis. Additionally, PGE had power cost mechanisms in 2002 that allowed the Company to defer, for future ratemaking treatment, actual net variable power costs that differed from certain baseline amounts approved by the OPUC (see "Power Cost Mechanisms" in Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). In 2002, PGE did not reduce its non-trading value at risk by the amount of potential deferrals.

Foreign Currency Exchange Rate Risk

PGE faces exposure to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars, primarily in its non-trading portfolio. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy. Beginning in 2003, PGE implemented a strategy that utilizes forward contracts to acquire Canadian dollars in order to mitigate its currency exposure.

At June 30, 2003, 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 18 months. Foreign currency risk in PGE's trading portfolio is immaterial to the Company's consolidated financial statements and is not expected to change materially in the near future.

Interest Rate Risk

Although PGE has no short-term debt outstanding at June 30, 2003, 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, which it has recently been unable to issue due to reductions in its credit ratings. Although PGE currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

Credit Risk

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

Risk Management Committee

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

For further information on price risk management activities, see Note 2, Price Risk Management, in the Notes to Financial Statements.

Item 4. Controls and Procedures

Disclosure Controls and Procedures. Management of the Company, under the supervision and with 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.

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) 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 report on Form 10-K for the year ended December 31, 2002.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Multnomah County Circuit Court Case No. 0301 00779; and Morgan v. Portland General Electric Company, Multnomah County Circuit Court Case No. 03021 00778

Motions to Dismiss have been filed in both Multnomah County Circuit Court and in Marion County Circuit Court, where an identical suit was previously filed by the same parties. Marion County has deferred further action on the complaints until the Multnomah County acts. Arguments are scheduled in August 2003 on pending motions in Multnomah County.

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.

PGE filed a motion for summary judgment on May 28, 2003. Oral argument is scheduled for August 14, 2003 with a trial date set for September 8, 2003.

Port of Seattle vs. Avista Corporation, Avista Energy, Inc., El Paso Electric Company, Idacorp, Inc., Idaho Power Co., Pacificorp, Portland General Electric Company, Powerex Corporation, PPL Montana, LLC, Puget Energy, Inc., Puget Sound Energy, Inc., Scottish Power, PLC, Sempra Energy, Sempra Energy Resources, Sempra Energy Trading Corp., Transalta Corporation, Transalta Energy Marketing, Inc. United States District Court for the Western District of Washington

On May 21, 2003, the Port of Seattle, Washington (Port) filed a complaint in the United States District Court for the Western District of Washington against Portland General Electric Company (PGE, or the Company) and sixteen other companies (Defendants) alleging violation of both the Sherman Act and the Racketeer Influenced and Corrupt Organization Act, fraud, and, with respect to Puget Energy, Inc. and Puget Sound Energy, Inc., breach of contract. The complaint alleges that the price of electric energy purchased by the Port between November 1997 and June 2001 under a contract with Puget Sound Energy, Inc. was unlawfully fixed and artificially increased through various actions alleged to have been undertaken in the Pacific Northwest power markets among Defendants and Enron Corp., Enron Energy Services, Inc., Enron North America Corp., Enron Power Marketing, Inc., and others. The complaint alleges actual damages of $30.5 million suffered by the Port and seeks recovery of that amount, pl us punitive damages and reasonable attorney fees.

People of the State of Montana, ex rel. Mike McGrath, Attorney General of the State of Montana; Flathead Electric Cooperative, Inc., and Roes 1 through 100, inclusive v. Williams Energy Marketing and Trading Company; Reliant Energy Services, Inc; Duke Energy Trading and Marketing, LLC; Mirant Corporation; Enron Energy Services, Inc.; Enron Power Marketing, Inc., Morgan Stanley Capital Group, Inc.; Powerex; El Paso Merchant Energy; American Electric Power; Avista Corporation; Portland General Electric Company; BP Energy; Goldman Sachs Group, Inc. and Does1 through 100, Inclusive, Montana First Judicial District, Lewis and Clark County

On June 30, 2003, the Montana Attorney General filed a complaint in Montana state court against PGE and numerous named and unnamed generators, suppliers, traders, and marketers of electricity and natural gas in Montana. The Complaint alleges unfair and deceptive trade practices in violation of the Montana Unfair Trade and Practices and Consumer Protection Act, deception, fraud and intentional infliction of harm arising from various actions alleged to have been undertaken in the western wholesale electricity and natural gas markets during 2000 and 2001. The relief sought includes injunctive relief to prohibit the unlawful practices alleged, treble damages, general damages, interest, and attorney fees. No monetary amount is specified.

Item 6. Exhibits and Reports on Form 8-K

Exhibits

(3) Articles of Incorporation and Bylaws

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

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

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

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

3.5 * Amended and Restated Bylaws of Portland General Electric Company, as amended on December 31, 1999 (incorporated by reference to Exhibit (3) to Form 10-K for the fiscal year ended December 31, 2001).

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

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

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

31.1 Certification of Chief Executive Officer of Portland General Electric Company Pursuant to Securities Exchange Act Rule 13a-14(a) for report on Form 10-Q for the quarterly period ended June 30, 2003 (filed herewith)

31.2 Certification of Chief Financial Officer of Portland General Electric Company Pursuant to Securities Exchange Act Rule 13a-14(a) for report on Form 10-Q for the quarterly period ended June 30, 2003 (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, for report on Form 10-Q for the quarterly period ended June 30, 2003 (filed herewith)

* Incorporated by reference as indicated.

b. Reports on Form 8-K

April 8, 2003 - Item 5. Other Event: Financing Activities. Item 7. Financial Statements and Exhibits.

April 29, 2003 - Item 5. Other Event: Oregon Public Utility Commission Staff Report on Trading Activities by Portland General Electric, PacifiCorp, and Idaho Power Company during the Western Electricity Crisis of 2000-01.

May 21, 2003 - Item 5. Other Events: Legal Matter, FERC Investigations - Wholesale Power Markets, Financing Activities.

June 4, 2003 - Item 5. Other Events: PGE Credit Ratings, Public Utility Holding Company Act of 1935, Public Ownership Initiatives.

June 25, 2003 - Item 5. Other Events: Refunds on Wholesale Transactions, FERC Orders on Gaming and Anomalous Market Behaviors.

June 27, 2003 - Item 5. Other Events: Enron Plan of Reorganization, Portland General Holdings, Inc. Bankruptcy, Legal Proceedings.

August 4, 2003 - Item 5. Other Event: Financing Activities. Item 7. Financial Statements and Exhibits.

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 13, 2003

By:

/s/ James J. Piro

James J. Piro

Executive Vice President, Finance

Chief Financial Officer and Treasurer

Date:

August 13, 2003

By:

/s/ Kirk M. Stevens

Kirk M. Stevens

Controller and Assistant Treasurer

Exhibit 31.1 EXHIBIT 31.1
CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, Peggy Y. Fowler, certify that:

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

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

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

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

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

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

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

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

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

Date:	August 13, 2003		/s/ Peggy Y. Fowler
		Peggy Y. Fowler
		Chief Executive Officer and President

Exhibit 31.2 EXHIBIT 31.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

I, James J. Piro, certify that:

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

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

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

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

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

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

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

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

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

Date:

August 13, 2003

/s/ James J. Piro

James J. Piro

Executive Vice President, Finance

Chief Financial Officer and Treasurer

Exhibit 32 EXHIBIT 32

CERTIFICATIONS OF

CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

OF PORTLAND GENERAL ELECTRIC COMPANY

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

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

We, Peggy Y. Fowler, Chief Executive Officer and President, and James J. Piro, Chief Financial Officer, of Portland General Electric Company (the "Company"), hereby certify that the accompanying report on Form 10-Q for the quarterly period ended June 30, 2003, and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.

We further certify that the information contained in such report on Form 10-Q for the quarterly period ended June 30, 2003, fairly presents, in all material respects, the financial condition and results of operations of the Company.

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


Date:	August 13, 2003	Date:	August 13, 2003