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Portland General Electric Company and Subsidiaries Consolidated Balance Sheets (Unaudited)
				September 30,											December 31,
				2003											2002
						(In Millions)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $87 and $81)			$					3,806					$			3,706
	Accumulated depreciation								(1,848)								(1,768)
									1,958								1,938
Other Property and Investments
	Receivable from parent (less allowance for uncollectible accounts of $86 and $81)								-							-
	Nuclear decommissioning trust, at market value								26							31
	Non-qualified benefit plan trust								64							68
	Note receivable - Pelton Round Butte project sale								17							20
	Miscellaneous								40							28
									147							147
Current Assets
	Cash and cash equivalents					148											51
	Accounts and notes receivable (less allowance for uncollectible accounts of $54 and $28)					230											241
	Unbilled and accrued revenues					52											84
	Assets from price risk management activities					55											77
	Inventories, at average cost					47											45
	Prepayments and other					109											90
	Deferred income taxes					-											3
						641											591
Deferred Charges
	Unamortized regulatory assets					404											544
	Miscellaneous					35											30
						439											574
				$		3,185								$			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					517											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					-											27
	Limited voting junior preferred stock					-											-
	Long-term obligations					990											827
						2,145											1,983
Commitments and Contingencies (Notes 3-7, 12)
Current Liabilities
	Long-term debt due within one year					56											191
	Preferred stock maturing within one year					-											1
	Accounts payable and other accruals					233											244
	Liabilities from price risk management activities					46											80
	Customer deposits					5											5
	Accrued interest					17											15
	Dividends payable					-											1
	Accrued taxes					60											22
	Deferred income taxes					2											-
						419											559
Other
	Deferred income taxes					352											383
	Deferred investment tax credits					18											20
	Trojan asset retirement obligation and transition costs					108											186
	Accumulated asset retirement obligation					17											-
	Unamortized regulatory liabilities					23											16
	Non-qualified benefit plan liabilities					63											62
	Miscellaneous					40											41
						621											708
				$		3,185								$			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)
									Nine Months Ended
									September 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				$			30		$				60
	Non-cash items included in net income:
		Cumulative effect of a change in accounting principle, net of tax						(2)						-
		Depreciation and amortization						160						120
		Deferred income taxes						(23)						47
		Net assets from price risk management activities						(16)						(1)
		Power cost adjustment						37						(15)
		Other non-cash income and expenses (net)						26						(27)
	Changes in working capital:
		Net margin deposit activity						(1)						89
		(Increase) Decrease in receivables						16						34
		Increase (Decrease) in payables						27						(12)
		Other working capital items - net						(18)						(24)
	Other - net							1						-
Net Cash Provided by Operating Activities								237						271
Cash Flows From Investing Activities:
	Capital expenditures							(99)						(117)
	Other - net							(33)						9
Net Cash Used in Investing Activities								(132)						(108)
Cash Flows From Financing Activities:
	Net decrease in short-term borrowings							-						(104)
	Repayment of long-term debt							(339)						(22)
	Issuance of long-term debt							342						-
	Debt issue costs							(7)						-
	Preferred stock retired							(3)						(2)
	Dividends paid							(1)						(2)
Net Cash Used in Financing Activities								(8)						(130)
Increase in Cash and Cash Equivalents								97						33
Cash and Cash Equivalents, Beginning of Period								51						8
Cash and Cash Equivalents, End of Period					$			148		$				41
Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized			$			53		$				46
		Income taxes						39						2
Supplemental disclosure of non-cash financing activity
			Non-cash dividend to parent	$			-				$				27
The accompanying notes are an integral part of these consolidated financial statements.

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 Repo rt 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.

PGE utilizes derivative instruments, including electricity forward, swap and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and endeavor to minimize net power costs for its retail customers, and in its trading activities to participate in electricity, natural gas, and crude oil markets. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), 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. As a result, PGE records unrealized and realized gains and losses from trading activities on a net basis as a component of Operating Revenues.

As PGE's primary business is to serve its retail customers, it uses derivative instruments, including electricity forward and option, and natural gas forward, swap, and option 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 gain s 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 nine months of 2003, PGE recorded $14 million in net unrealized gains in earnings in its retail portfolio, including $9 million in net unrealized losses in the third quarter. The net unrealized gain in the first nine months of 2003 was partially offset by recording a $9 million SFAS No. 71 regulatory liability, calculated on the basis indicated above. In the first nine months of 2002, PGE recorded $5 million in net unrealized gains, including $4 million in net unrealized gains in the third 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 nine-month periods ended September 30, 2003 from cash flow hedges consist of $4 million of unrealized losses and $6 million of unrealized gains, respectively, from new contracts and changes in fair value. Also recorded in OCI in the first nine months of 2003 were $4 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 loss recorded in OCI in the first nine months of 2003 was partially offset by a $1 million SFAS No. 71 regulatory asset.

Derivative activities recorded in OCI for the three- and nine-month periods ended September 30, 2002 from cash flow hedges consisted of $5 million and $8 million of net unrealized gains, respectively, that were fully offset by the recording of SFAS No. 71 regulatory liabilities.

No amounts were reclassified into earnings as a result of hedge ineffectiveness in the first nine months of 2003 or 2002. As of September 30, 2003, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 17 months. The Company estimates that the entire $5 million of net unrealized gains at September 30, 2003 will be reclassified into earnings within the next twelve months.

PGE utilizes electricity forward, swap, and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts to participate in electricity, natural gas, and crude oil markets. Such activities are not reflected in PGE's retail prices. As indicated above, 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 for all periods presented.

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

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 ordering remand of the case to the OPUC. PGE and the OPUC requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision on the return on investment issue. In addition, URP requested the Oregon Supreme Court to review the Court of Appeals decision on the return of investment issue. PGE requested the Oregon Supreme Court to suspend its rev iew of the 1998 Court of Appeals opinion pending resolution of URP's complaint with the OPUC challenging the accounting and ratemaking elements of the settlement agreements approved by the OPUC in September 2000 (discussed below). On November 19, 2002, the Oregon Supreme Court dismissed PGE's and URP's petitions for review of the 1998 Oregon Court of Appeals decision. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

While the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, in 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of 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 /PGC 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. On November 7, 2003, the Marion County, Oregon Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE intends to appeal.

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. The plaintiffs have filed to withdraw the Multnomah County cases. 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, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which do not specify an amount of claim, seek binding arbitration. PGE filed for relief in Multnomah County Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. The IBEW has appealed the decision. 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 EPA investigation of a 5.5 mile segment of the Willamette River known as the Portland Harbor revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund). In December 2000, PGE received a "Notice of Potential Liability" regarding its Harborton Substation facility and was included, along with sixty-eight other companies, on a list of Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

Also in 2000, PGE agreed with the DEQ to perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In February 2002, PGE submitted its final investigative report to the DEQ, indicating that the voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimus Potentially Responsible Party.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign, nor has it signed, such an order.

In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund designated area.

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 cannot predict the ultimate outcome of this matter or estimate any potential loss.

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

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 September 30, 2003, Enron owed PGE approximately $86 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 $16 million income taxes payable balance at September 30, 2003 represents a net current income taxes payable of $9 million related to income taxes owed since December 24, 2002 and $7 million for income taxes owed up to May 7, 2001 (prepetition). In the first nine months of 2003, PGE paid $37 million to Enron for income taxes payable. 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 nine months of 2003, Enron billed PGE approximately $15 million for retirement savings plan matching and medical and dental benefits. In addition, PGE accrued $10 million for corporate overhead costs. For the same period in 2002, Enron billed PGE approximately $10 million for retirement savings plan matching and medical and dental benefits, and $10 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001, except for payments for employee benefit plans. 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 nine months of 2003, PGE paid $38 million to Enron, consisting of $23 million for corporate overhead costs from January 2002 through September 2003 and $15 million for employee benefits. The $6 million payable to Enron at September 30, 2003 consisted of $4 million for corporate overheads and $2 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 September 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. No PGH subsidiaries are included in the bankruptcy filing. At September 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), a telecommunications company, Microclimates, Inc., a project management company, and Portland Energy Solutions Company, LLC (PES), which provides cooling services to buildings in downtown Portland, Oregon.

In July 2003, PGDC's 100% equity interest in Portland General Broadband Wireless, LLC was sold, and $3 million of the sales proceeds were used during the third quarter to reduce the outstanding accounts receivable balances owed by PGH2 and its subsidiaries to PGE.

For the first nine months of 2003, PGE billed PGH2 and its subsidiaries $1 million for employee and other corporate governance services. As of September 30, 2003, PGE had outstanding accounts and notes receivable from PGH2 and its subsidiaries of $3 million, comprised of $2 million for employee and other corporate governance services ($1 million each owed PGE by PGDC and PES) and a $1 million secured loan to PES.

PGE and PES have entered into a revolving credit agreement under which PGE has agreed to advance funds to PES to complete a district cooling system project. Advances accrue interest at 16% per annum. Interest paid by PES to PGE in excess of PGE's authorized cost of capital (9.083%) is deferred for future refund to PGE's customers. PGE also has a security interest in certain contracts and equipment related to the project. The agreement was to expire on April 1, 2003. In July 2003, the OPUC approved an amendment extending the agreement to March 31, 2004 and reducing the maximum loan amount from $2 million to $1.5 million. As of September 30, 2003, PES owed PGE $1.2 million, including accrued interest, under the agreement.

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

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

Interest Income and Expense - Interest 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.

As of September 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. Based on the FERC's orders on the methodology to be used to calculate potential refunds (see Note 6 - Refunds on Wholesale Transactions), PGE has established reserves totaling $40 million related to this receivable amount, including $11.5 million and $11 million recorded in the first and third quarters, respectively, 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.

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

On July 25, 2001, the FERC issued another order establishing the scope of and methodology for calculating the refunds and ordering evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

Also in August 2002, the FERC Staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in the Company's potential refund obligation.

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. 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 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 adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimated that the modified methodology could increase the amount of the potential refunds by approximately $20 million, with the Company's potential liability estimated at between $20 million and $50 million.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the pricing methodology. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. Several parties have now appealed the October 16, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds and is evaluating its options, including the possibility of an appeal to the courts.

In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. The FERC has granted the requests for rehearing solely for purposes of reconsideration.

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 $40 million related to the receivable amount. The FERC has also indicated that interest on both refunds and offsetting accounts receivable will be computed from either the actual collection date or the due date, as applicable; 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.

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 and on September 18, 2003, amended the Chapter 11 Plan and the Disclosure Statement. 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 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 ap proval. 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:

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 against t he 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 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 PGE's 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.

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 Income. Both a mounts 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 ratemaking 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 September 30, 2003, PGE has an estimated $234 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 $55 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 $121 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
		Nine Months Ended				Year Ended
		September 30, 2003				December 31, 2002
Beginning Balance		$	137			$	145
Activity
	AROs incurred		-				-
	Expenditures (Trojan)		(15)				(18)
	Accretion		4				6
	Revisions		(1)				4
Ending Balance		$	125			$	137

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.

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. Under the amendment, an electricity forward contract must be a capacity contract, among other criteria, to qualify for the normal purchase and normal sale exception. 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 15, 2003 are applied in accordance with their respective effective dates. The adoption of SFAS No. 149 did not 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. Reclassification of prior period amounts is not permitted. As required by SFAS No. 150, PGE's outstanding preferred stock that is mandatorily redeemable on fixed dates was reclassified to liabilities on July 1, 2003, and the Company began recording the related dividends as interest expense. The adoption of SFAS No. 150 did not have a material effect on the financial statements of the Company.

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. The adoption of EITF 01-8 did not have an impact on the financial statements of the Company.

FASB Interpretation No. 46 (FIN 46), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, was issued on January 17, 2003. FIN 46 provides guidance on the identification and consolidation of entities (termed "variable interest entities") for which control is achieved by means other than through voting rights. On October 9, 2003, the FASB issued a Staff Position to defer the application of FIN 46 for variable interest entities existing prior to February 1, 2003 until the end of the first interim or annual period ending after December 15, 2003. Management does not believe that the application of FIN 46 will have a material impact on the Company's financial statements.

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 were used to redeem in September 2003 the $25 million balance of the First Mortgage Bonds, 9.46% Series due August 12, 2021, $75 million of the First Mortgage Bonds, 7-3/4% Series due April 15, 2023, and $50 million of 8.25% Junior Subordinated Deferrable Interest Debentures, due December 31, 2035.

The July 1, 2003 balance of PGE's outstanding 7.75% Series Cumulative Preferred Stock was reclassified to long-term obligations on the balance sheet in accordance with SFAS No. 150.

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 was completed in early September 2003. The fuel is contained in thirty-four multi-purpose canisters, which have been loaded, sealed, and placed on the ISFSI pad. With the completion of the transfer of spent nuclear fuel to an on-site storage facility, transition activities associated with operating, maintaining, and securing the spent fuel pool have ceased. Also in connection with the completion of the spent nuclear fuel transfer to dry storage, decommissioning funding assurance is required by the Nuclear Regulatory Commission (NRC) for the amount by which the estimated amount of future radiological decommissioning costs exceed the actual balance in the external trust fund. PGE utilizes a letter of credit under its revolving credit facility to meet its current funding assurance requirement of $13 million as of September 30, 2003. The funding assurance requirement is expected to decrease through early 2005, as radiological decommissioning is completed. The Company does not expect the funding assurance requirement to have a material effect on its financing requirements.

On September 26, 2003, PGE filed a settlement agreement (Settlement) between and among itself, the Trial Staff of the FERC, the California Attorney General, the California Public Utilities Commission, the City of Tacoma, Washington, the OPUC, and several other parties resolving certain cases and investigations related to electricity prices in California in 2000 - 2001. The Settlement resolves all alleged violations by the Company in the FERC's investigation under Docket No. EL02-114-000 of Enron trading strategies in the California wholesale power markets. The Settlement also resolves People of the State of California ex rel. Bill Lockyer, Attorney General v. Portland General Electric Company and Does 1 through 100 and related non-public investigations by the California Attorney General, except that the California Attorney General is not precluded from pursuing any willfully fraudulent acts or omissions not known at the time of the Settlement or any criminal acts or omissi ons. Finally, the Settlement resolves, as to PGE, the investigation proposed in the OPUC draft staff report on "Trading Activities by Portland General Electric Company, PacifiCorp, and Idaho Power Company during the Western Electricity Crisis of 2000-2001."

Under the Settlement, PGE will pay a Settlement Amount of $8.5 million. PGE also will file an amendment to its FERC market-based rates tariff that imposes a cost-based cap on prices charged for new wholesale electricity sales transactions for a prospective period of twelve months. In addition, PGE agreed to conduct annual training for its trading floor employees on code of conduct, standards of conduct, antitrust and ethics, and to retain for five years recordings of affiliate trading transactions, affiliate postings, and related accounting records. The Settlement provides that it will not be deemed an admission of fault or liability by PGE for any reason and implies no admission or fault by PGE. The Settlement, which is uncontested, is subject to approval of the FERC.

PGE established an $8.5 million reserve for the Settlement in September 2003 (included within "Other Income (Deductions)" on the Consolidated Statements of Income herein).

Management does not believe that the cost-based cap on prices charged for new wholesale electricity sales transactions will have a material adverse impact on the financial condition or results of operations of the Company.

Under terms of an agreement approved by the OPUC in 2000, PGE sold a 33.33% undivided interest in its Pelton Round Butte hydroelectric project to the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes) on January 1, 2002. As part of the sale, PGE received a five-year $24.2 million interest-bearing note from the Tribes, of which $17 million remained outstanding on September 30, 2003. On October 10, 2003, the Tribes paid off the $17 million balance on the note.

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.

PGE had a net loss of $4 million in the third quarter of 2003 compared to net income of $8 million in the third quarter of 2002. The decrease in earnings was due primarily to third quarter 2003 after tax provisions totaling approximately $12 million related to investigations into wholesale power market activities during 2000 and 2001, consisting of $7 million related to amounts due the Company for wholesale electricity sales made in California and $5 million related to a settlement agreement between PGE, the FERC, and other parties. Increased margins on total energy sales and income from non-qualified benefit plan trust assets were offset by increased customer support expenses, pension costs, and higher interest charges.

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

The decrease in Retail Revenues resulted from both lower prices and energy sales. 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). A decrease in retail energy sales from last year's third quarter also contributed to lower revenues. Industrial energy sales declined 20%, with approximately half of such decline attributable to a single large customer which began generating its own power requirements in the second quarter of 2003; such customer had previously purchased energy from the Company under a market-based pricing option. The decline in industrial energy sales was partially offset by a 6% increase in Residential energy use and a 2% increase in Commercial energy use due to warmer summer temperatures and an increase in the number of customers serve d. Increased Wholesale (Non-Trading) Revenues resulted primarily from a 43% increase in average wholesale power prices, reflecting higher summer temperatures as well as increased natural gas prices and adverse hydro conditions in the region. Higher wholesale energy sales were attributable to warmer regional summer temperatures and a reduction in the Company's retail load requirements. 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 third quarter of 2003 resulted in a $2 million gain, compared to an $8 million loss in the third quarter of 2002 resulting from low natural gas prices.

Purchased Power and Fuel expense increased $26 million (8%) due to increases in both total system load and average power prices. Total system load increased 2%, with a 26% increase in thermal generation largely offset by decreases in both power purchases and hydro generation. Total generation met approximately 45% of PGE's retail load during the third quarter of 2003, compared to 37% last year. PGE's average variable power cost increased about 1% from the third quarter of 2002, due primarily to an increase in the average cost of purchased power. Purchased Power and Fuel expense in the third quarter of 2002 included a $5 million charge related to an adjustment of power costs deferred under the Company's power cost adjustment mechanism then in effect. The third quarter of 2003 includes an $8 million charge for the amortization of costs deferred under the mechanism in prior years, which were recovered from customers during the quarter. There is currently no power cost adjustment mechani sm in place for 2003. Also included in third quarter 2003 expense is an $11 million provision for uncollectible accounts receivable for wholesale electricity sales in the California market during 2000 and 2001. (For further information, see "Receivables - California Wholesale Market" in Item 2. - "Management's Discussion and Analysis of Financial Condition and Results of Operations").

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the third quarter of 2003 and 2002. Average variable power costs exclude the effect of PGE's power cost mechanisms and provisions for uncollectible accounts receivable, discussed above, on purchased power and fuel costs.

Operating Expenses (excluding Purchased Power and Fuel, Depreciation and Amortization, and taxes) increased $4 million (7%), due primarily to increased customer support and employee benefit expenses, including higher pension cost provisions resulting from the effects of prior years' declines in the fair market value of plan assets and a lower discount rate for estimating the pension benefit obligation.

Depreciation and Amortization expense increased $13 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 third quarter of 2002 related to a distribution received by PGE in 2000 from Nuclear Electric Insurance Limited. Other reductions in regulatory liabilities include $4 million in credits related to merger-related cost savings and gains on certain major property sales, which were provided to customers in the third quarter of 2002. The remaining increase consists primarily of increased amortization of computer software, including the Company's new customer information and billing system.

Income taxes decreased $3 million due to lower taxable income.

Other Income (Miscellaneous) decreased $5 million primarily due to an $8.5 million charge related to a September 2003 settlement agreement between PGE, the FERC, and other parties related to investigations into prior years' wholesale power market activities. (For further information, see "Investigations - Wholesale Power Markets" in Item 2. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). In addition, a $3 million credit reserve, related to income taxes receivable from Enron, was reversed in the third quarter of 2002. These decreases were partially offset by a $6 million increase in income from non-qualified benefit plan trust assets.

Interest Charges increased $4 million due primarily to an increase in outstanding long-term obligations, including first mortgage bonds issued from October 2002 through August 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.

PGE's net income in the first nine months of 2003 was $30 million, compared to $60 million in the first nine months of 2002. Earnings were unfavorably impacted by a decline in retail energy sales resulting from warmer weather in the first quarter of 2003, and higher interest charges. A power cost adjustment mechanism in place during 2002 partially offset the negative earnings impact of lower energy sales in the first nine months of 2002. In addition, PGE recorded after tax provisions totaling approximately $19 million in the first nine months of 2003 related to investigations into wholesale power market activities during 2000 and 2001, consisting of $14 million related to amounts due the Company for wholesale electricity sales made in California and $5 million related to a settlement agreement between PGE, the FERC, and other parties. Results for the first nine months of 2003 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 nine-month periods ending September 30, 2003 and 2002:

The decrease in Retail Revenues from the first nine months 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 decreased from the first nine months of 2002 due to an 8% decline in industrial sales. Approximately one-third of such decline was attributable to a single large customer which began generating its own power requirements in the second quarter of 2003. Combined residential and commercial energy sales approximated that of 2002, as an increase in the number of customers served was offset by warmer temperatures in the first quarter of 2003 and conservation efforts. Increased Wholesale (Non-Trading) Revenues resulted primarily from a 34% increase in average wholesale power prices, reflecting higher summer temperatures as well as increased natural gas prices and adverse hydro conditions in the region. Higher wholesale energy sales were attributable to warmer regional summer temperatures and a reduction in the Company's retail load requirements. 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 nine months of 2003 resulted in an $11 million gain, compared to a $19 million loss in the first nine months of 2002 resulting from low natural gas prices.

Purchased Power and Fuel expense increased $19 million (2%). The combined effects of the discontinuance of the Company's power cost adjustment mechanism and current year provisions for uncollectible accounts receivable for wholesale electricity sales were partially offset by lower average power costs in the first nine months of 2003. Total system load approximated that of the first nine months of 2002. Purchased Power and Fuel expense in the first nine months of 2002 included a net credit of $10 million related to the Company's power cost mechanism then in effect, consisting of a $26 million credit for the deferral of 2002 power costs and a $16 million charge for amortization of costs deferred in 2001. The first nine months of 2003 includes a $45 million charge for the amortization of costs deferred under the mechanism in 2001 and 2002, which were recovered from customers in 2003. There is currently no power cost adjustment mechanism in place for 2003. Also included in the first nine months of 2003 are $22.5 million of provisions for uncollectible accounts receivable for wholesale electricity sales related to sales made in the California market during 2000 and 2001. (For further information, see "Receivables - California Wholesale Market" in Item 2. - "Management's Discussion and Analysis of Financial Condition and Results of Operations"). PGE's average variable power cost decreased 6% from the first nine months of 2002, due primarily to lower purchased power prices in 2003. Total Company generation increased 5% from last year's first nine months, with increased coal-fired generation partially offset by both reduced hydro and combustion turbine generation, resulting from the forced outage of the Coyote Springs plant during the second quarter of 2003. Total generation met approximately 40% and 37%, respectively, of PGE's retail load in the first nine months of 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 nine months 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 $14 million in power costs would have been deferred for future ratemaking treatment in the first nine months of 2003, of which $2 million is applicable to the third quarter. 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 nine months of 2003 and 2002. Average variable power costs exclude the effect of PGE's power cost mechanisms and provisions for uncollectible accounts receivable, discussed above, on purchased power and fuel costs.