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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.

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 a $76 million reduction to previously reported amounts for both Operating Revenues and Purchased Power and Fuel expense for the first quarter of 2002.

PGE utilizes derivative instruments, including electricity forward and option, 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, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, 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.

In October 2002, the Emerging Issues Task Force reached a consensus to rescind Issue 98-10 (EITF 98-10), Accounting for Energy Trading and Risk Management Activities, effective for fiscal periods beginning after December 15, 2002. With the rescission of EITF 98-10, only energy trading contracts that qualify as derivatives under SFAS No. 133 are marked-to-market through earnings. All of PGE's energy trading activities currently qualify as derivatives under SFAS No. 133. Accordingly, the rescission of EITF 98-10 has had no effect on the Company.

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 2003, unrealized gains and losse s 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 three months of 2003, PGE recorded $22 million in net unrealized gains in earnings in its retail portfolio, which was partially offset by recording an $11 million SFAS No. 71 regulatory liability, calculated on the basis indicated above. In the first three months of 2002, PGE recorded $4 million in net unrealized losses in earnings in its retail portfolio, which was fully offset by the recording of a SFAS No. 71 regulatory asset as a result of the power cost mechanism then in effect.

Derivative activities recorded in OCI for the first quarter of 2003 from cash flow hedges consist of $5 million of net unrealized gains from new contracts and changes in fair value, $3 million in net gains reclassified to 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 transactions will not occur. In the first quarter of 2002, there were $7 million in net unrealized gains from new contracts and changes in fair values and $1 million in net losses for the discontinuance of cash flow hedges due to the probability that the original forecasted transactions will not occur; there were no gains or losses reclassified to earnings for contracts that settled during the period. In both years, the entire amount of OCI was fully offset by the recording of a SFAS No. 71 regulatory liability. No amounts were reclassified into earnings as a result of hedge ineffectiveness in the first quarter of 2003 or 2002. As of March 31, 2003, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 24 months. In addition, at March 31, 2003, the Company estimates that of the $6 million of net unrealized gains, $5 million will be reclassified into earnings within the next twelve months, and $1 million will reclassified over the remaining twelve months.

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-month periods ended March 31, 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 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.

While the petitions for review 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 allo ws 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. As discussed below, the URP filed a complaint challenging the settlement agreements and the OPUC's September 2000 order. Collection of decommissioning costs at Trojan is unaffected by the settlement agreements or the OPUC order.

PGE requested the Oregon Supreme Court to suspend its review of the 1998 Court of Appeals opinion pending resolution of URP's complaint with the OPUC challenging the accounting and ratemaking elements of the settlement agreements approved by the OPUC in September 2000. 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 not expected until mid-2003.

On July 1, 2002, PGE filed with the Oregon Supreme Court a Notice of Mootness and Motion to Dismiss and Vacate the case. On November 19, 2002, the Oregon Supreme Court denied PGE's Motion to Dismiss and Vacate and 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. On January 17, 2003, URP filed a petition with the Court of Appeals requesting that the Court remand the matter to the Marion County Circuit Court, and not to the OPUC as required in the Court of Appeal's 1998 ruling. PGE and the OPUC filed in opposition to this request. In March 2003, the Court denied URP's petition.

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 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 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, not 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.

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 March 31, 2003, Enron owed PGE approximately $82 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 $29 million income taxes payable balance at March 31, 2003 represents a net current income taxes payable of $22 million for the first quarter 2003 and $7 million of taxes payable at December 31, 2002 for income taxes owed up to May 7, 2001. On April 15, 2003, PGE made a payment to Enron of $21 million 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 and provides incidental services to Enron. In the first quarter of 2003, Enron billed PGE approximately $5 million for retirement savings plan matching and medical and dental benefits. In addition, PGE accrued $3 million for corporate overhead costs. For the same period in 2002, Enron billed PGE approximately $2 million for retirement savings plan matching, and medical and dental benefits, and $3 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 the first three months of 2003, PGE paid $21 million to Enron, consisting of $17 million for corporate overhead costs from January 2002 through March 2003 and $4 million for employee benefits. The $6 million payable to Enron at March 31, 2003 consisted of $3 million for corporate overheads and $3 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 March 31, 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. Under the settlement, PGE will retain a $200,000 deposit from EPMI related to the transmission contract, Enron's guaranty will terminate, and PGE will amend 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. The settlement agreement was approved by the Bankruptcy Court in May 2003, and is subject to acceptance by the FERC. For further information, see Note 7, Enron Bankruptcy.

Enron Subsidiaries not in Bankruptcy - Portland General Holdings and Subsidiaries - Portland General Holdings, Inc. (PGH) is a wholly owned subsidiary of Enron. PGH and its subsidiaries are not part of Enron's bankruptcy proceedings. Prior to Enron's bankruptcy, Enron had provided a portion of the funding for operations of PGH and its subsidiaries. With Enron's bankruptcy, any future funding from Enron will be subject to approval by Enron, and must be in compliance with the Order of the Bankruptcy Court Authorizing Continued Use Of Existing Bank Accounts, Cash Management System, Checks and Business Forms dated December 3, 2001, as amended on February 25, 2002 (the Cash Order). At December 31, 2002, PGE had outstanding accounts and notes receivable from PGH and its subsidiaries of $10 million, comprised of $2 million related to non-regulated asset sales, $4 million related to PGH employee benefit plans, $3 million for employee and other corporate governance services, and a $1 m illion loan to a PGH subsidiary. These balances remained outstanding at March 31, 2003. In June 2002, Enron loaned PGH $475,000 to fund current operating activities, in compliance with the Cash Order. No additional funds have been advanced from Enron to PGH, and the $475,000 remains outstanding as of March 31, 2003. Based on management's assessment of the realizability of the receivables from PGH and its subsidiaries, a reserve of $2 million was established in December 2002.

PGH2, a wholly owned subsidiary of PGH, is the parent company of various subsidiaries that receive services from PGE. These include Portland General Distribution, LLC and Portland General Broadband Wireless, LLC (telecommunications companies), Microclimates, Inc. (a project management company), and Portland Energy Solutions Company, LLC (PES), which provides cooling services to buildings in downtown Portland, Oregon. At December 31, 2002, PGE has a $2 million receivable balance from Portland General Distribution Company, LLC related to assets sold for a capital project and for employee services provided by PGE. This balance remained outstanding at March 31, 2003.

PGE entered into a one-year revolving credit agreement to loan PES $2 million. The agreement, approved by the OPUC, expired on April 1, 2003. However, PGE has filed an application with the OPUC for approval of an amendment to extend the agreement to April 1, 2004. The application also requests a reduction in the interest rate from 16% to 12% per annum. Under the original agreement, PGE advanced funds to PES to complete a district cooling system project, with advances accruing interest at 16% per annum. The OPUC order further provides that interest paid by PES to PGE in excess of PGE's authorized cost of capital (9.083%) be deferred for 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 March 31, 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.

As of March 31, 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.

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 February and March 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.

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. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a g uilty 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. 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.

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 additional evidence of market manipulation. In compliance with this order, the FERC authorized all parties to conduct further inquiry and to submit additional evidence of market manipulation. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.

On March 3, 2003, numerous parties filed documents 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.

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. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.

In December 2002, the FERC re-opened this case to allow parties to conduct further discovery. In coordination with the order in the California refund case (described above), the FERC authorized all parties to conduct further inquiry and to submit additional evidence. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.

On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the City of Tacoma. 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 adversely affected the market. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of these parties.

On March 26, 2003, the FERC indicated that it may issue an order to remand the case for a determination of refunds. The remand could include the appointment of a settlement judge or additional hearings to determine refund amounts, if any. At this time, the Company does not know what the order may require or what sanctions may be sought.

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 and the Pacific Northwest 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 filings.

In connection with its proposed restructuring, Enron has stated that it believes that the total amount of the liquidated, undisputed claims against Enron and its subsidiaries exceeds and will exceed the current fair market value of the consolidated operations and assets of Enron and its subsidiaries. Accordingly, Enron has stated that it believes its existing equity has and will have no value and that any Chapter 11 plan confirmed by the Bankruptcy Court will not provide Enron's existing equity holders with any interest in the reorganized debtor. Any and all Chapter 11 plans are subject to creditor approval and judicial determination of confirmability.

Management cannot predict with certainty what impact Enron's bankruptcy 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 approval. The Merger Conditions a lso 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. 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 share s 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.

PGE has been informed by Enron management that the proposal Enron presented to its Unsecured Creditors' Committee on May 3, 2002 to separate certain of Enron's core energy assets, including PGE, from Enron's bankruptcy estate and operate them prospectively as a new integrated power and pipeline company has been withdrawn. 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.

Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until resolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.

Enron has filed a motion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to Enron's 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 Inc ome. 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 March 31, 2003, PGE has an estimated $212 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:

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.

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's net income in the first quarter of 2003 was $21 million, compared to $36 million in the first quarter of 2002. Earnings were unfavorably impacted by a 4% decline in retail energy sales, resulting from both warmer weather in the first quarter of 2003 and 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 last year's first quarter. 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. Results for the first quarter 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 first quarter of 2003 and 2002:

The decrease in Retail Revenues was caused primarily by 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 quarter as a result of both warmer temperatures and increased conservation efforts, with average use for residential and commercial customers declining about 8% and 3%, respectively. Such decreases more than offset an approximate 6,400 increase in total customers during the last year. Increased Wholesale (Non-Trading) Revenues resulted from both higher energy sales and higher market prices. Sales volume increased significantly as energy marketing activity returned from lower levels in last year's first quarter caused by price volatility and uncertainty related to the cost and availa bility of power in western markets. Average wholesale power prices increased 24%, 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 first quarter of 2003 resulted in a $6 million gain, compared to a loss of $8 million in the first quarter of 2002.

Purchased Power and Fuel expense increased $27 million (11%). The economic displacement of combustion turbine generation with lower cost power purchases during the first quarter of 2003 resulted in an 11% decrease in PGE's average variable power cost from the first quarter of 2002. PGE reduced output from its combustion turbine plants by 35% and replaced it with power purchases that cost an average of 20% less than in the first quarter of 2002; this more than offset a 10% increase in total system load resulting from higher wholesale energy sales. Purchased Power and Fuel expense in the first quarter of 2002 included a $27 million credit related to the Company's power cost mechanism then in effect, while the first quarter of 2003 includes a $16 million charge for the amortization of costs deferred under the mechanism in 2001 and 2002 which were recovered from customers in the first quarter of 2003. There is currently no power cost adjustment mechanism in place for 2003. Also included i n first quarter 2003 expense is an $11.5 million provision for uncollectible accounts receivable for wholesale electricity sales in the California market. (For further information, see Note 5, Receivables - California Wholesale Market, in the Notes to Financial Statements).

Due to expected adverse hydro conditions in the region, PGE has 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 quarter of 2003 do not reflect the deferral of such costs, pending OPUC consideration of the Company's application. See "Hydro Replacement Power Costs" in the Financial and Operating Outlook section for further information.

Company generation approximated that of last year's first quarter, as a 17% increase in coal-fired generation and a 6% increase in production from PGE's hydro plants largely offset the reduction in combustion turbine generation. Total generation met approximately 44% of PGE's retail load during the first quarter of 2003, compared to 43% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the first quarter of 2003 and 2002. Average variable power costs exclude the effect of credits to purchased power and fuel costs related to PGE's power cost mechanisms, as discussed above.

(*includes wheeling costs)

Operating Expenses (excluding Purchased Power and Fuel, Depreciation and Amortization, and taxes) decreased $2 million (3%). Effective with the March 1, 2002 implementation of Oregon's energy restructuring law, PGE no longer directly provides energy efficiency measures to its retail customers, with such services now administered by the non-profit Energy Trust of Oregon. The resulting decrease in energy efficiency expenses was partially offset by increased corporate overhead expenses (including certain employee benefit costs), increased provisions for uncollectible customer accounts, and certain customer support expenses.

Depreciation and Amortization expense increased $13 million (31%) due to decreased amortization of regulatory liabilities, including credits given to customers in 2002 for gains on certain nonrecurring property sales, and increased amortization of computer software, including the Company's new customer information and billing system. In addition, last year's first quarter amortization expense included credits to establish regulatory assets related to the sale of the Pelton Round Butte hydroelectric project and the deferral, for future recovery from customers, of costs related to implementation of Oregon's electricity restructuring law.

Income taxes decreased $13 million primarily due to lower taxable income.

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 $81 million in this year's first quarter compared to $76 million in the same period last year. The increase is due primarily to increased payments received from sales to retail electricity customers.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. A $4 million increase in capital expenditures in the first quarter of 2003 is primarily attributable to improvements and expansion of the PGE's distribution system to support both new and existing customers within the Company's service territory.

Financing Activities provide supplemental cash for both day-to-day operations and capital requirements as needed. PGE relies on cash from operations, revolving credit facilities, and long-term financing activities to support such requirements. Although PGE has traditionally utilized commercial paper borrowings in meeting its day-to-day cash requirements, the Company has been unable to access the commercial paper market due to ratings reductions by credit rating agencies.

During the first quarter of 2003, PGE repurchased $39 million of the $142 million in Pollution Control Bonds that were remarketed on May 1, 2003 (see below). In addition, the Company repaid $2 million of conservation bonds and paid $1 million in preferred stock dividends during the first quarter of 2003. No common stock cash dividends were declared in 2002 or in the first quarter of 2003. In July 2002, upon approval of the Company's board of directors, PGE made a non-cash dividend of $27 million to Enron related to the transfer of a receivable balance due from PGH.

On April 8, 2003, PGE issued $50 million of 5.279% First Mortgage Bonds, maturing April 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. Net proceeds from this issue will be 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.

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 March 31, 2003, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.

PGE is evaluating alternatives for the replacement of its existing revolving credit lines, consisting of a $72 million facility expiring in June 2003 and a $150 million facility expiring in July 2003. Such alternatives include their replacement by a new revolving credit facility and/or issuance of First Mortgage Bonds. The Company's existing revolving credit facilities contain a material adverse change clause and financial covenants that limit consolidated indebtedness, as such term is defined in the facilities, to 60% of total capitalization, and require a minimum 2.25:1 ratio of earnings before interest and taxes to consolidated interest expense. PGE's indebtedness to total capitalization and interest coverage ratios at March 31, 2003 were 44.2% and 2.32:1, respectively. Both facilities are secured by First Mortgage Bonds. In addition, the revolving credit facilities prohibit the payment of any cash dividends by PGE to Enron.

PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's Investors Service (Moody's) and Standard and Poor's (S&P), with Fitch Ratings (Fitch) currently carrying a below investment grade rating on the Company. PGE 's current credit ratings are as follows:

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 March 31, 2003, PGE had posted, in the form of letters of credit, $22 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 March 31, 2003, the approximate amount of additional collateral that could be requested upon such a downgrade event is $50 million and decreases to approximately $44 million by year-end 2003. In addition to collateral calls, such a credit rating reduction would likely have an adverse effect on the terms and conditions of future long-term debt. In addition, any such rating reductions would increase interest rates and fees on PGE's two revolving credit facilities, increasing the cost of funding its day-to- day working capital requirements.

PGE's does not have the ability to access the commercial paper market due to the May 2002 ratings reduction for commercial paper by Moody's and Fitch. Management believes that it has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

On May 5, 2003, Fitch issued a press release to announce that PGE's Rating Watch status has been revised from Negative to Positive and that, upon finalization of bank revolver financing, expected to occur by the end of May 2003, it would likely upgrade PGE's secured debt to investment grade.

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, it does believe 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.

Weather adjusted retail energy sales decreased 1.1% for the three months ended March 31, 2003, compared to the same period last year. Industrial sector energy sales were flat, with commercial and residential sales down 0.4% and 2.2%, respectively. PGE forecasts continued flat retail energy sales in 2003, with no growth from 2002 due to Oregon's continued slow economy.

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 84% of normal, compared to 97% of normal in 2002.

PGE generated 51% of its retail load requirement in the first quarter 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 as well as other fuels, and the availability and pricing of electric and gas transmission all contributed to and 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.

Commencing in December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. 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. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.

Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. In addition, PGE was included among those Enron entities suspended from contracting with the federal government. The suspension, which expired in March 2003, had no material adverse effect on PGE business or operations.

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:

2. 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.
3. 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.
4. Enron believes that all of the requirements for re-consolidation of PGE with the Enron consolidated group have been met. However, because of the inherently factual nature of the determination of the re-consolidation, there can be no assurance that the IRS will agree with this position. In the event that the IRS does not agree and the matter is not resolved in the bankruptcy proceeding (or otherwise), PGE will have an administrative expense claim against Enron for any amounts paid by PGE to Enron under the tax sharing agreement. Enron management believes that all administrative expense claims will be paid in full.

PGE management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy.

PGE management cannot predict with certainty what impact Enron's bankruptcy 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. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other tr ansfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. 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 state 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 years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. 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.

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 ov er PGE unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

PGE has been informed by Enron management that the proposal Enron presented to its Unsecured Creditors' Committee on May 3, 2002 to separate certain of Enron's core energy assets, including PGE, from Enron's bankruptcy estate and operate them prospectively as a new integrated power and pipeline company has been withdrawn. 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.

Enron management has informed PGE that if PGE is not sold in the auction process, it is anticipated that the shares of PGE stock owned by Enron would be distributed over time to creditors of Enron in connection with Enron's plan of reorganization. It is also anticipated that PGE's stock would be listed on a national stock exchange and would be publicly traded. In connection with the distribution to creditors, it is expected that PGE would be governed by an independent Board of Directors. Until resolution of the bankruptcy case and distribution of the PGE shares, Enron will retain the right to sell PGE if it is determined that a sale would be in the best interest of Enron's stakeholders.

Enron has filed a motion with the Bankruptcy Court to extend the time to file its plan of reorganization to June 30, 2003. Until the plan of reorganization or another filing related to the sale of PGE is filed with the Bankruptcy Court and approved, management cannot assess the impact on PGE's business and operations of a sale or the distribution of PGE's stock to Enron's creditors.

In August 2002, the City Council of Portland, Oregon passed a resolution authorizing the expenditure of up to $500,000 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.

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 its 2001 general rate case. It provides for an adjustment, filed annually on November 15, 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 a resolution regarding the recovery period for PGE's power cost mechanism covering the period October 2001 through December 2002. This amount includes the effect of a settlement stipulation related to estimated 2003 power costs, in which PGE agreed to reduce its recovery under the power cost mechanism by approximately $4.6 million; such reduction was recorded by the Company in 2002.

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 March 31, 2003, the remaining balance to be collected was approximately $67 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 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 March 31, 2003, the balance to be collected was approximately $31 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).

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 has begun 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.

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 that will be updated later in 2003. The filing forecasts retail price increases for both residential and nonresidential customers ranging from 2.5 percent to 5 percent, based upon the effect of higher wholesale power, coal, and natural gas prices on PGE's costs. Final adjustments will be determined in November 2003.

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.

In August 2002, PGE filed a new Integrated Resource Plan. 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.

PGE filed a supplement to the Plan on February 28, 2003. The OPUC has initiated a schedule for input and review, with an acknowledgement of the Company's Plan, as supplemented, anticipated by mid-2003. PGE then anticipates issuing a request for proposals (RFP) to acquire energy and capacity resources. The Company will continue to evaluate its options with regard to the construction of additional generation, including a 650-MW gas turbine plant adjacent to it's Beaver plant site (Port Westward Generating Project), considering the availability of reasonably priced medium to long-term power purchases from the market. PGE 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.

Based upon results of the RFP process, PGE will update its action plan with specific resource recommendations and request acknowledgement that the Company's final action plan is consistent with least cost planning principles established by the OPUC.

As of March 31, 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.

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 February and March 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.

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. The FERC asked for comments on the staff's recommendation, and on October 15, 2002, PGE, along with several other utilities, filed comments with the FERC objecting to the FERC staff's recommendations. Subsequent to the issuance of the FERC's August 13, 2002 report, several companies disclosed that some of their gas traders reported incorrect prices to the firms that report gas indices. In addition, on September 23, 2002, a FERC administrative law judge issued an order in a complaint case against El Paso Natural Gas Company, finding that El Paso had manipulated the gas market by withholding capacity. Also, in October 2002, a former Vice President and Managing Director of Enron's West Power Trading Division entered a g uilty 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. 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.

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 additional evidence of market manipulation. In compliance with this order, the FERC authorized all parties to conduct further inquiry and to submit additional evidence of market manipulation. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.

On March 3, 2003, numerous parties filed documents 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.

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. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.

In December 2002, the FERC re-opened this case to allow parties to conduct further discovery. In coordination with the order in the California refund case (described above), the FERC authorized all parties to conduct further inquiry and to submit additional evidence. PGE responded to data requests from other parties and, in conjunction with other affected utilities, sought information from these parties.

On March 3, 2003, numerous parties filed documents addressing possible market manipulation. The most comprehensive filings were by the City of Tacoma. 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 adversely affected the market. On March 20, 2003, PGE, both individually and as part of a group of similar utilities, filed responses rebutting the claims of these parties.

On March 26, 2003, the FERC indicated that it might issue an order to remand the case for a determination of refunds. The remand could include the appointment of a settlement judge or additional hearings to determine refund amounts, if any. At this time, the Company does not know what the order may require or what sanctions may be sought.

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 and the Pacific Northwest 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.

Pursuant to the FERC Staff's Final Report on Price Manipulation in Western Markets, issued in Docket No. PA02-2-000, the FERC indicated, in a press release issued on March 26, 2003, that it intends to issue orders to PGE and 36 other entities that participated in the California wholesale market in 2000 and 2001, requiring that each entity show cause why their behaviors during that time period did not constitute gaming in violation of tariffs issued by the California Independent System Operator (ISO) and the California Power Exchange (PX). The FERC indicated that possible sanctions for any entity found to have violated the tariffs include disgorging unjust profits associated with the violations, or other appropriate remedies. Based on its internal investigations to date, PGE does not believe that it violated ISO or PX tariff provisions.

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.

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.

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 i t was 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. The services provided by PGE 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 believes that it has 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 are included as parties in that Docket. In the orders, the FERC established Octobe r 15, 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 occu r 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 (California Parties) 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.

The hearing in Docket No. EL02-114-000 is scheduled to begin on June 2, 2003, with an initial decision from the presiding FERC judge scheduled for July 17, 2003. The procedural schedule in Docket No. EL02-115-000 is currently suspended pending further revisions to a settlement proposal submitted between Avista and FERC trial staff.

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.

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 generat ion and purchase contracts to the extent that available supply exceeds the needs of the Company's firm customers.

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.

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.

On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC), 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.

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, inte rest, 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.

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 Septembe r 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.

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. 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.

In addition, the Staff recommended that the OPUC delay any decision on an investigation of whether PGE engaged in misconduct with respect to its trading activities until after the FERC issues its decision in its proceeding related to the possible violation by PGE of PGE's code of conduct, the FERC's standards of conduct, and PGE's market-based rate tariffs (Docket No. EL02-114-000). For further information, see "Federal Investigations - Wholesale Power Markets" and "Show Cause Order".

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."

The Draft Report included two other options to the Staff's recommendation. The first option would be to commence a proceeding to determine whether PGE engaged in misconduct and/or mismanagement, with a second proceeding, if needed, to determine what relief, if any, is appropriate. The other option would be to delay any investigation until after the FERC has completed its proceedings.

The Staff requested written comments on the Draft Report by May 21, 2003. The Staff intends to issue its final report in early June 2003 and present its recommendation to the OPUC at that time.

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.

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.

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.

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.

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.

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 Initial 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.

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.

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

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

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

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

• events related to Enron's bankruptcy proceedings;

• 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

• 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.

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.

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 quarter of 2003 was $0.1 million, $0.2 million, and $0.1 million, respectively, and in the first quarter of 2002 was $0.3 mil lion, $0.4 million, and $0.1 million, respectively. The average, high, and low value at risk on the non-trading portfolio in the first quarter of 2003 was $2.3 million, $2.6 million, and $2.0 million, respectively. The value at risk on the non-trading portfolio was not meaningful in the first quarter 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.

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 March 31, 2003, a 10% change in the value of the Canadian dollar would result in a change in pre-tax income of approximately $0.5 million at the time the transactions settle over the next 21 months. That portion of such change applicable to the remainder of 2003 is not material. 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.

Although PGE has no short-term debt outstanding at March 31, 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.

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. Due to the settlement of power contracts in 2002, the Company's exposure to credit risk has decreased significantly.

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.

(a) Evaluation of Disclosure Controls and Procedures. The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective in recording, processing, summarizing and reporting, within the time periods specified in the Commission's rules and forms, the information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's reports filed or submitted under the Exchange Act.

(b) Changes in Internal Controls. Since the Evaluation Date, there have not been any significant changes in the Company's internal controls or in other factors that could significantly affect such controls.

For further information, see PGE's report on Form 10-K for the year ended December 31, 2002.

On March 25, 2003, the judge dismissed the complaint against PGE. The Attorney General of California has appealed the decision to the United States Court of Appeals for the Ninth Circuit.

On March 24, 2003, PGE was served with two class action suits seeking damages for the inclusion of a return on investment of Trojan in the rates PGE charges its customers. The suits are from the same parties and are identical to the Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company (Case No. 03C 10639) and Morgan v. Portland General Electric Company (Case No. 03C 10640) filed in Marion County Circuit Court on January 17, 2003.

On May 5, 2003, the plaintiffs voluntarily dismissed their complaint.

On March 13, 2003, the Oregon Court of Appeals denied URP's petition requesting that the Court remand the case to the Marion County Circuit Court.

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.

1. Exhibits

b. Reports on Form 8-K

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:	May 14, 2003		/s/ James J. Piro
			James J. Piro
			Executive Vice President, Finance Chief Financial Officer and Treasurer

I, Peggy Y. Fowler, Chief Executive Officer and President of Portland General Electric Company (the "Company"), hereby certify that the accompanying report on Form 10-Q for the quarterly period ended March 31, 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.

I further certify that the information contained in such report on Form 10-Q for the quarterly period ended March 31, 2003, fairly presents, in all material aspects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Portland General Electric Company and will be retained by Portland General Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

I, 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 March 31, 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.

I further certify that the information contained in such report on Form 10-Q for the quarterly period ended March 31, 2003, fairly presents, in all material aspects, the financial condition and results of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to Portland General Electric Company and will be retained by Portland General Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.