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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 interim reporting requirements of the Securities and Exchange Commission (SEC), which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs are subject to year-end adjustment. It is management's opinion that, when the interim statements are r ead in conjunction with the 2004 Annual Report on Form 10-K and the other reports filed with the SEC since its 2004 Form 10-K was filed, the disclosures are adequate to make the information presented not misleading.

PGE sponsors a non-contributory defined benefit pension plan in which Portland General Holdings, Inc. (PGH) and its subsidiaries have participated. Substantially all pension plan members are current or former PGE employees. The pension plan assets are held in a trust.

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

PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" in the table). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions made to a Voluntary Employees' Beneficiary Association (VEBA) trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers. In 2004, PGE established Health Retirement Accounts (HRAs) for its employees under which the Company will make contributions to a trust to provide for claims by retirees for qualified medical costs.

The measurement date for these plans is December 31. PGE does not expect to make contributions to the pension plan, SERP, or post-retirement health and life insurance plans during 2005; contributions to the HRAs are not expected to be material.

The following tables indicate components of net periodic benefit cost for the first quarter of 2005 and 2004 (in millions):

PGE utilizes derivative instruments, including electricity forward, swap, and option contracts and natural gas forward, swap, option, and futures in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and to minimize net power costs for its retail customers, and in its trading activities to participate in electricity and natural gas markets. Under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), derivative instruments are recorded on the Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings, unless specific hedge accounting criteria are met.

Trojan Investment Recovery - In 1993, following the closure of the Trojan Nuclear Plant, PGE sought full recovery of and a rate of return on its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. The filing was a result of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order (1995 Order) which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals and requested reviews were subsequently filed in the Marion County, Oregon Circuit Court, the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of and a return on the Trojan investment. The primary plaintiffs in the litigation were the Citizens' Utility Board (CUB) and the Utility Reform Project (URP). The Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE and the OPUC requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision on the return on investment issue. In addition, URP requested the Oregon Supreme Court to review the Court of Appeals decision on the return of investment issue. PGE requested the Oregon Supreme Court to su spend its review of the 1998 Court of Appeals opinion pending resolution of URP's complaint with the OPUC challenging the accounting and ratemaking elements of the settlement agreements approved by the OPUC in September 2000 (discussed below). On November 19, 2002, the Oregon Supreme Court dismissed PGE's and URP's petitions for review of the 1998 Oregon Court of Appeals decision. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

While the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, in 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of, and return on, its investment in the Trojan plant. URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of the 1997 merger of Portland General Corporation (PGC) with Enron. The settlement also allows PGE recovery of approximately $ 47 million in income tax benefits related to the Trojan investment which had been flowed through to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five-year period, beginning in October 2000. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. Authorized collection of decommissioning costs of Trojan is unaffected by the settlement agreements or the OPUC orders.

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

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Plaintiff's claims. On December 14, 2004, the Judge granted the Plaintiff's motion for Class Certification and Partia l Summary Judgment and denied PGE's motion for Summary Judgment. PGE filed a proposed order certifying the issue for an interlocutory appeal. An order rejecting the proposed order was entered on February 1, 2005. On March 3, 2005, PGE filed a Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed. On March 29, 2005, PGE filed a second Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court, seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions. The parties will file briefs on both Petitions over the next few months. Oral argument before the Oregon Supreme Court is expected in the fall of 2005.

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

On August 31, 2004, the administrative law judge issued an Order (Scoping Order) defining the scope of the proceedings necessary to comply with the Marion County Circuit Court orders remanding this matter to the OPUC. On October 18, 2004, the OPUC affirmed the Scoping Order. On December 20, 2004, the URP and Class Action Plaintiffs filed an application with the OPUC for reconsideration of the Scoping Order. On February 11, 2005, the OPUC denied reconsideration. On April 18, 2005, URP and Linda K. Williams filed a complaint against the OPUC in Marion County Circuit Court challenging the OPUC's affirmation of the Scoping Order.

On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs) stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, the Company's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million.

Management cannot predict the ultimate outcome of the above matters. However, it believes these matters will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for a future reporting period. No reserves have been established by PGE for any amounts related to this issue.

Multnomah County Business Income Taxes - In January 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MBIT) after 1996. The plaintiffs allege that during the period 1997 through the third quarter 2004, PGE collected in excess of $6 million from its customers for MBIT that was never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As a member of Enron's consolidated income tax return, PGE paid the tax it collected to Enron. The plaintiffs seek a judgment against PGE for restitution of MBIT collected from customers. Plaintiffs also seek interest, recoverable costs, and reasonable attorney fees. The Plaintiffs filed an amended complaint on February 25, 2005, adding claims for fraud, unjus t enrichment, conversion, statutory violations, and seeking punitive damages. On February 24, 2005, PGE requested a declaratory ruling from the OPUC on this matter. On March 24, 2005, PGE filed in the Circuit Court a motion to abate or in the alternative to dismiss. Management cannot predict the ultimate outcome of this matter.

Union Grievances - In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which do not specify an amount of claim, seek binding arbitration. PGE filed for relief in Multnomah County Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Harborton - A 1997 investigation by the Environmental Protection Agency (EPA) of a 5.5 mile segment of the Willamette River known as the Portland Harbor revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund). In December 2000, PGE received a "Notice of Potential Liability" regarding its Harborton Substation facility and was included, along with sixty-eight other companies, on a list of Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

Also in 2000, PGE agreed with the Oregon Department of Environmental Quality (DEQ) to perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In February 2002, PGE submitted its final investigative report to the DEQ, indicating that the voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the final investigative report to the EPA and in a May 18, 2004 letter, the EPA stated that "Based on the summary information provided by DEQ and the limited data EPA has at this stag e in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river." Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

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

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. Management cannot predict the ultimate outcome of this matter or estimate any potential loss. However, it believes this matter will not have a material adverse impact on its financial statements.

Other - In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site. Sufficient information is currently not available to determine the total costs related to this matter. However, PGE believes this matter will not have a material adverse impact on its financial statements.

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

Income Taxes Receivable and Payable - As a member of Enron's consolidated income tax return, PGE made income tax payments to Enron for PGE's income tax liabilities. PGE and its subsidiaries ceased to be a member of Enron's consolidated tax group on May 7, 2001. On December 24, 2002, PGE and its subsidiaries again became a member of Enron's consolidated tax group. The $45 million income taxes payable to Enron at March 31, 2005 represents a net current income taxes payable for the first quarter of 2005 that was paid to Enron in April 2005. The $21 million income taxes payable to Enron at December 31, 2004 represents a net current income taxes payable for the fourth quarter of 2004 that was paid to Enron in January 2005.

Intercompany Receivables and Payable - As part of its continuing operations, PGE bills affiliates for various services provided by the Company. These include services provided by PGE employees, as well as other corporate services. In addition, Enron passes through PGE's share of costs related to certain insurance coverage. Transactions with affiliates are subject either to approval of, or confirmation filing requirements with, the OPUC and, as long as PGE is a subsidiary of a registered holding company under PUHCA, the SEC. Under OPUC regulations, services provided to affiliates by PGE are charged at the higher of cost or market, while affiliated services received by PGE are charged at the lower of cost or market. Under SEC regulations, both services provided to, and received from, affiliates are charged at cost. Services will be provided at cost unless there is a conflict between OPUC and SEC regulations, in which case PGE and Enron have agreed not to provide the serv ices until the matter can be resolved.

Enron - Beginning January 1, 2005, administration of the medical/dental benefit and retirement savings plans was returned to PGE from Enron; as a result, Enron no longer passes through costs to PGE for these services. In the first three months of 2005, Enron billed PGE approximately $1 million for insurance coverage and costs related to the resolution of certain employee benefit plan matters (see below). For the same period in 2004, Enron billed PGE approximately $6 million, consisting of $5 million for medical/dental benefits and retirement savings plan matching, and $1 million for insurance coverage.

Enron has continued to incur costs related to the resolution of issues associated with the bankruptcy and litigation with regards to certain employee benefit plans in which PGE employees previously participated. Enron billed PGE for a portion of these costs in 2004 and during the first three months of 2005, as the issues continue to be worked towards resolution. At March 31, 2005, PGE had $3 million payable to Enron related to these costs, including approximately $0.8 million for the first quarter of 2005.

Portland General Holdings, Inc. - in Bankruptcy - On June 27, 2003, PGH, a wholly owned subsidiary of Enron located in Portland, filed to initiate bankruptcy proceedings under the federal Bankruptcy Code. The PGH filing has been procedurally consolidated with the Enron bankruptcy proceeding. No PGH subsidiaries are included in the bankruptcy filing. At March 31, 2005 and December 31, 2004, PGE had outstanding accounts receivable from PGH of $5 million, comprised of $4 million related to employee benefit plans and $1 million for employee and other corporate governance services provided by PGE to PGH in 2002. During 2003, PGE submitted proofs of claim to the Bankruptcy Court for approximately $5 million for employee benefit and corporate governance services. Based on management's assessment of the realizability of the receivable from PGH, a reserve of $2 million was established in December 2002. In June 2004, PGE reduced the reserve by $1 million based on mana gement's then current assessment. PGE will continue to assess the collectibility of this receivable.

PGH II and its Subsidiary - not in Bankruptcy - PGH II, Inc. (PGH II), a wholly owned subsidiary of PGH, is the parent company of Portland General Distribution, LLC (PGDC), a telecommunications company which received services from PGE. PGH II and PGDC are not part of Enron's or PGH's bankruptcy proceedings. As of March 31, 2005 and December 31, 2004, PGE had outstanding accounts receivable from PGDC of $1 million for employee and other corporate governance services, offset by an approximate $0.9 million uncollectible reserve.

In September 2004, PGDC sold substantially all of its assets to an unrelated third party. The proceeds from the sale are expected to repay the unreserved amounts that PGDC owes to PGE.

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

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

As of March 31, 2005, PGE has net accounts receivable balances totaling approximately $63 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

Management continues to assess PGE's exposure relative to these receivables. Based upon FERC orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for federally-mandated wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and PX. The order established evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

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

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds, based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates its potential liability under the modified methodology at between $40 million and $50 million, of which $40 million has been established as a reserve, as discussed above.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order that denied further requests for rehearing of the October 16, 2003 order. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first will consider arguments regardin g jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. Briefing and oral argument have been completed on this first phase. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before FERC become final and are appealed.

Also on May 12, 2004, the FERC issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liability. On September 24, 2004, the FERC issued an order that denied requests for rehearing of its May 12, 2004 fuel cost order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology of the September 24, 2004 order, PGE could be required to pay additional amounts in those hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect that this order will materially increase the Company's potential refund exposure. Partly as a means of limiting its exposure to add itional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. In December 2004, the FERC requested comments regarding the manner in which such studies should be conducted and the principles that should control. PGE and numerous other parties filed comments and reply comments. Comments in support of aspects of PGE's position were filed by the Oregon and Washington public utility commissions and by the Oregon and Washington senate delegations. A decision by the FERC to adopt PGE's approach to these studies could reduce the Company's ultimate refund liability.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). Interest has not yet been recorded by the Company. In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates during the period October 2, 2000 - June 4, 2002 should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals. On September 8, 2004, the Court issued an opinion upholding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. PGE cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

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

In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders and briefing is ongoing.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

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

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

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

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

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

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

1. Enron's consolidated tax returns through 1995 have been audited and are closed.
2. The IRS has completed an audit of Enron's consolidated tax returns for 1996-2001. For years 1996 through 1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron's 2001 consolidated tax return showed a substantial net operating loss, which was carried back to the tax year 2000, for which Enron seeks a tax refund for taxes paid in 2000. The 2001 loss is also expected to provide Enron and its subsidiaries with substantial NOLs which may be used to offset additional income tax liabilities that may result from future IRS audits for the taxable periods PGE was a member of Enron's consolidated federal income tax returns.
3. Enron's 2003 tax return was filed on September 14, 2004. As noted in paragraph B. above, Enron expects to have substantial NOLs from operations in years preceding 2003. Enron had 2003 NOLs sufficient to eliminate Enron's regular income tax and alternative minimum income tax liabilities for 2003. Enron expects to file its 2004 tax return on or before September 15, 2005 and expects to have sufficient NOLs to eliminate its regular income tax for 2004, but expects to pay alternative minimum tax with respect to that year. For calendar year 2005, Enron expects that it will have sufficient NOLs to eliminate regular income tax should it earn positive taxable income for the year. However, such taxable income, if realized, could be subject to the alternative minimum tax.

On April 6, 2005, Enron announced that it has reached an agreement with Oregon Electric to terminate the sale agreement for PGE following the OPUC's denial of Oregon Electric's application to buy PGE's common stock from Enron.

Enron announced that it intends to move forward with plans to issue PGE common stock to its creditors in accordance with the Chapter 11 Plan. As part of this process, current PGE common stock would be cancelled and new PGE common stock would be issued. Initially, at least 30 percent of the new PGE common stock would be issued to the Debtor's creditors that hold allowed claims, with the remainder issued to Steven Forbes Cooper, LLC as disbursing agent, and held in a reserve to be released to the Debtor's creditors that are determined to hold allowed claims in accordance with the Chapter 11 Plan.

Enron stated that the initial issuance of new PGE common stock is not expected to commence until April 2006, but could begin as soon as October 2005. Enron and PGE intend to apply for a listing of the new PGE common stock on a national securities exchange.

Pursuant to the Chapter 11 Plan, Enron's Board of Directors will oversee the process of issuing the new PGE common stock to the Debtor's creditors that hold allowed claims and to the disbursing agent. Such issuance of new PGE common stock is subject to certain conditions and regulatory approvals, including approval by the OPUC and the SEC. Under the Chapter 11 Plan, all shares of new PGE common stock held in reserve will be voted by the Disputed Claims Reserve Overseers (DCRO). Initially, the DCRO is comprised of the same individuals who currently serve on Enron's Board of Directors.

Enron has indicated that, in accordance with Enron's ongoing efforts to maximize the value of the Enron bankruptcy estate, Enron will continue to consider credible offers to purchase PGE's common stock.

On December 21, 2004, the Financial Accounting Standards Board issued FASB Staff Position No. 109-1 (FSP 109-1), Application of FAS 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004 (Act). For companies that pay federal income taxes on manufacturing activities in the United States, the Act provides a deduction from taxable income equal to a stipulated percentage of qualified income from domestic production activities (qualified production income or "QPI"). The deduction, which cannot exceed fifty percent of annual wages paid, is phased in as follows: three percent of QPI in 2005-2006, six percent in 2007-2009, and nine percent in 2010 and thereafter. Eligible activity, as defined in the Act, includes oil and gas extraction and electricity and water production (excluding transmission and distribution). Under FSP 109-1, tax deductions on QPI activities are to be treated as special deductions under FAS 109. The application of FSP 109-1 is required in financial statements of entities that have QPI and any effect to deferred tax assets from the reduction of future taxable income for periods ending after the December 21, 2004 effective date. The adoption of FSP 109-1 had no effect on PGE's deferred tax assets as of December 31, 2004. The adoption of FSP 109-1 did not have a material effect on the financial statements of the Company.

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

The timing of decommissioning activities at PGE's closed Trojan plant has changed from previous estimates, due primarily to a delay in the completion of a permanent storage facility for spent nuclear fuel and to the acceleration of the planned demolition of major structures at the plant. Spent nuclear fuel is currently maintained in an interim dry storage facility at the plant site until permanent storage becomes available. Due to various factors, completion of the U.S. Department of Energy's long-term repository for the nation's high-level radioactive waste at Yucca Mountain, Nevada, has been delayed. The previous decommissioning plan provided for the shipment of spent fuel to a permanent storage facility by 2018. The updated plan provides for the shipment of spent fuel by 2023, and completion of decommissioning of the interim dry storage facility in 2024. In addition, the Company has decided to accelerate the completion of major structure demolition at the plant from 2018, as pre viously estimated, to 2008. Such revisions resulted in a net $10 million increase in the Trojan asset retirement obligation, measured at estimated fair value, since the end of 2004. PGE continues to expect that any changes in estimated decommissioning costs will be incorporated in future revenues collected from customers.

The following table indicates balances and activities for the Trojan asset retirement obligation for the first quarter of 2005:

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

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

Enron and representatives of the plan participants reached a settlement that was approved by the Bankruptcy Court on February 24, 2005. As part of the settlement, three new non-qualified plans were adopted by PGE for certain PGH Plan participants. PGE also established a Non-Qualified Benefit Plan Trust for Transferred Liabilities (Trust). On April 4, 2005, PGE assumed the liabilities for these participants from PGH, totaling $6.9 million, on a present value basis. PGE received $8.4 million (net of tax) in compensation for assuming the liabilities, consisting of $7.4 million deposited into the Trust and $1 million paid directly to PGE for ongoing trustee and administrative fees and taxes.

Operations - PGE continues to serve its customers effectively and operate well. Despite the challenges of continued poor hydro conditions, the lack of any power cost adjustment mechanism, and unseasonably warm weather, the Company posted first quarter earnings that exceeded that of each of the last three years. However, an improving local economy is expected to only partially offset the adverse effect of continued poor regional hydro conditions on PGE's financial performance during the remainder of the year. The Company continues to maintain investment-grade ratings on its debt (Fitch raised its ratings on PGE's secured and unsecured debt in March 2005), and has adequate liquidity and stable operating cash flow. PGE recently received high regional and national rankings for power quality and reliability in a major business customer satisfaction study released in this year's first quarter, and the Company continues to pursue improvements in response to the needs and expectations o f its customers.

Retail loads during the first quarter of 2005 fell somewhat below both current year projections and last year's first quarter due to warmer-than-normal weather. On a weather-adjusted basis, however, total retail energy sales increased by about 2% from last year's first quarter. Growth in the number of customers served within PGE's service territory partially offset the effect of the first quarter's mild weather.

PGE is continuing its decommissioning activities at the closed Trojan Plant. All large radioactive components have been removed from the site and spent fuel has been safely moved to interim dry storage. The Company has also decided to accelerate the demolition of major structures at the plant, including the cooling tower and those buildings that once housed the plant's turbine, reactor, and spent fuel pool. Termination of the plant's operating license by the NRC, which is pending, will remove the plant from NRC regulation, including on-site inspection and annual fee requirements. However, spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site, storage facility decontamination is completed, and the storage installation is fully decommissioned.

Economy - Oregon's economy continues to improve, with 2.1% annual average non-farm payroll growth for the 2003-04 period, twice the national growth rate. The state ranked 11th in employment growth among all 50 states in 2004, moving up to 3rd in January and to 2nd in February this year. This momentum has continued through the year's first quarter, when Oregon employers added almost 22,000 new jobs, a 4% year-over-year gain. These job gains helped cut Oregon's unemployment rate from a high of 8.5% in July 2003 to 7% in December 2004 to 6.2% in March 2005. PGE continues to experience customer growth, adding over 3,600 retail customers in this year's first quarter, and is working proactively to promote economic growth and business development within the Company's service territory.

Power Supply - Regional hydro conditions have remained significantly below normal during the first quarter of 2005, with current projections indicating continued deterioration from levels of recent years. Both the Clackamas and Deschutes river systems, where PGE's hydro generation facilities are located, are projected to remain significantly below last year's levels. During the first quarter of 2005, PGE effectively utilized its mix of generating assets, presence in the wholesale marketplace, and operational expertise to meet load requirements and partially offset the adverse financial effects of the region's dry weather. To the extent that hydro conditions utilized in power cost projections for setting customer rates are not realized, PGE's power costs will increase, as higher power purchase and thermal generating plant costs, driven by rising demand and prices for natural gas and other fuel, will be incurred as the Company continues to meet its load requirements.

Under the Resource Valuation Mechanism process, by which retail rates are adjusted annually for changes in projected power costs, PGE has submitted a preliminary filing to the OPUC of its estimated 2006 power costs. Current projections, which will be finalized in November, indicate an approximate 3% to 4% average retail price increase (including the effect of all credits and adjustments), beginning next year. In addition, the Company has requested OPUC consideration of a Hydro Generation Adjustment tariff that would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions, and currently has a hydro cost deferral application for 2005 pending with the Commission.

PGE continues to implement its Integrated Resource Final Action Plan, which received formal acknowledgement from the OPUC in 2004. The plan contains specific resource actions to meet the future electricity needs of customers, including construction of the 350 MWa natural gas-fired plant at Port Westward in Columbia County, Oregon, long-term power purchase agreements, and increased use of renewable energy resources. These actions provide competitive and reliable sources of supply for PGE customers.

Proposed Sale of PGE - Enron's proposed sale of PGE to Oregon Electric was denied by the OPUC and the parties have terminated their sale agreement. Enron has announced its intent to move forward with the issuance of PGE common stock to the Debtor's creditors that hold allowed claims, in accordance with Enron's bankruptcy plan. The initial distribution is not expected to commence until April 2006, although it may begin as soon as October 2005. Enron has also indicated that it will continue to consider credible offers to purchase PGE's common stock. For further information, see "Enron Bankruptcy - Future Ownership of PGE" in "Financial and Operating Outlook" of this Item 2.

The following review of PGE's results of operations should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this report. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2005.

PGE's net income in the first quarter of 2005 was $38 million, compared to $32 million in the first quarter of 2004. The increase was due primarily to improved margins on energy sales resulting from economic decisions related to the utilization of the Company's thermal generating assets and activities in the wholesale marketplace, which more than offset the adverse effect of continued poor regional hydro conditions and the impact of mild weather on retail energy sales during the first quarter of 2005.

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

Retail revenues decreased by approximately 2.6% from the first quarter of last year, primarily as the result of lower energy sales. The decline in energy sales was attributable to warmer weather in the first quarter of 2005 as well as to an increase in the number of commercial and industrial customers (Direct Access Customers) who chose to purchase their energy requirements from ESSs, as provided by Oregon's electricity restructuring law. Retail energy sales decreased about 2.3%, as residential sales declined about 4% and commercial and industrial sales declined by about 0.8% and 1.2%, respectively. An approximate 13,000 increase in customers served since the end of last year's first quarter, along with a 1.4% average rate increase for 2005, partially offset the effect of the above reductions in energy sales during this year's first quarter. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2. for further information).

Direct Access Customer Revenues consist of service charges for energy delivered to commercial and industrial customers who have selected direct access and energy supply from ESSs. The decrease in Direct Access Customer Revenues in this year's first quarter was attributable to "transition adjustment" credits for ESS customers, related to the difference between the cost and market value of energy delivered, as provided by the restructuring law. The increase in related energy deliveries was due to an increase in the number of commercial and industrial customers who purchase their electricity from ESSs, including a single large industrial customer that accounted for about 20% of the increase.

Wholesale revenues decreased by about 31% from last year's first quarter due to an approximate 34% reduction in wholesale electricity sales. This was partially offset by a 6% increase in average prices, resulting from both higher natural gas prices and a reduction in regional hydro availability.

The decrease in Other Operating Revenues from last year's first quarter was caused primarily by reduced margins on the sale of natural gas in excess of generating plant requirements, related to economic decisions that resulted in increased combustion turbine generation in this year's first quarter. This was partially offset by increased revenue from the sale of transmission capacity not currently required to serve existing load.

Purchased Power and Fuel expense decreased $36 million (20%) from last year's first quarter. The decrease was due primarily to a reduction in wholesale power purchased to meet a lower total system load requirement and higher unrealized gains from derivative instruments (for further information, see "Power and Fuel Supply - Price Risk Management" in "Financial and Operating Outlook" of this Item 2). Partially offsetting the effect of a decrease in system load was an approximate 1% increase in PGE's average variable power cost for the quarter due to increases in the average price of both term and spot market purchases. Company generation decreased about 7% from that of last year's first quarter. A 30% decrease in PGE hydro production (due to lower stream flows) and a 3% decrease in coal-fired generation were partially offset by an increase in combustion turbine generation. Total generation met approximately 45% of PGE's retail load during the first quarter of 2005, compared to 48% 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 2005 and 2004.

(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $2 million (3%) from the first quarter of 2004 primarily due to increased employee benefit expenses, including medical and pension costs. This was partially offset by a reduction in service restoration costs related to the five-day snow and ice storm in January 2004.

Depreciation and Amortization expense increased $1 million due to increased depreciation of utility plant, due to normal property additions, and to increased amortization of regulatory assets.

Income taxes increased $4 million primarily due to higher 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 consists of charges that are recovered in customer revenues for depreciation and amortization of utility plant that require no current period cash outlay. The recovery from customers of prior capital expenditures through depreciation and amortization provides a source of funding for current and future cash requirements. Cash flows from operations can also be affected by changes in the price of power and fuel as well as by weather conditions, as temperatures outside the normal range can affect electricity usage and resultant cash flow.

Cash provided by operating activities totaled $168 million in the first quarter of 2005 compared to $99 million in the same period last year. The increase was due primarily to a $43 million increase in cash collateral deposits received from certain wholesale customers, a $17 million increase in amounts received for electricity sales, the liquidation of a $10 million investment in debt securities, a $7 million decrease in income tax payments to Enron, and a $2 million decrease in interest payments. These items were partially offset by a $10 million increase in payments for power and fuel purchases.

Cash from operations was invested primarily in government money market funds and short-term commercial paper at March 31, 2005. Such investments are consistent with PGE's investment objectives to preserve principal, maintain liquidity, and diversify risk. Company investments are limited to investment grade securities (primarily short term) within guidelines approved by PGE's Board of Directors.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. The $16 million increase in capital expenditures in the first three months of 2005 is primarily attributable to improvements and expansion of PGE's distribution system to support both new and existing customers within the Company's service territory, relicensing expenditures, and initial construction costs of Port Westward.

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

During the first quarter of 2005, PGE repaid $3 million of conservation bonds. No cash dividends on common stock were declared or paid in the first three months of 2005 or 2004.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Company's Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. As of March 31, 2005, PGE has the capability to issue additional preferred stock and First Mortgage Bonds in amounts sufficient to meet its anticipated capital and operating requirements.

PGE has two revolving credit facilities with a group of commercial banks totaling $150 million, consisting of a $50 million 364-day facility and a $100 million three-year facility. The facilities, both of which are unsecured, each contain material adverse effect clauses and financial covenants that limit consolidated indebtedness, as defined in the facilities, to 60% of total capitalization. In addition, the three-year facility requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less that 3.00:1. At March 31, 2005, the Company's indebtedness to total capitalization and interest coverage ratios, as calculated under the facilities, were 40.1% and 6.69:1, respectively. The 364-day facility contains a "term out" option that would allow the Company to extend the final maturity of amounts outstanding at the facility expiration date for up to one additional year. Under the three-year credit facility, PGE has the option to issue letters of credit, in addi tion to borrowings, totaling up to the $100 million. At March 31, 2005, the Company had utilized approximately $23 million in letters of credit, $14 million related to wholesale trading activities and $9 million related to Port Westward. The agreements provide for borrowings at a variable interest rate and require quarterly facility fees based on the Company's unsecured credit rating. In addition, the agreements provide for termination of the banks' obligation, and the full repayment of any outstanding balances, in the event of the sale of the Company's common stock or other changes in control, as defined in the agreements. The facilities allow PGE to pay cash dividends on common stock, subject to certain restrictions. PGE expects to replace its current revolving credit facilities in the second quarter of 2005.

Access to short-term debt markets provides necessary liquidity to support PGE's current operating activities, including the purchase of electricity and fuel. Long-term capital requirements are driven largely by debt refinancing activities and capital expenditures for distribution, transmission, and generation facilities supporting both new and existing customers.

PGE's liquidity and capital requirements can be significantly affected by operating, capital expenditure, debt service, and working capital needs, including margin deposits related to wholesale trading activity. PGE's revolving credit facilities supplement operating cash flow and provide a primary source of liquidity. PGE's ability to secure sufficient long-term capital at reasonable cost is determined by its financial performance and outlook, capital expenditure requirements (including the effects of these factors on the Company's credit ratings), and alternatives available to investors. The Company's ability to obtain and renew such financing depends on its credit ratings as well as on bank credit markets, both generally and for electric utilities in particular.

PGE's financial objectives have been established by the Company's management and approved by its Board of Directors. Such objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company's financial obligations. PGE's objective is to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow are necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 58.8% and 58.2% at March 31, 2005 and December 31, 2004, respectively.

As previously indicated, a significant portion of cash provided by operations consists of depreciation and amortization of utility plant which is recovered in rates. PGE estimates recovery of such charges to approximate $210 million to $230 million annually over the period 2005-2007. Combined with all other sources, total cash provided by operations is estimated to range from $265 million to $310 million annually during the 2005-2007 period.

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

Cash flow from operations in excess of cash requirements may be used to fund costs associated with securing new energy resources. Additional liquidity is available under the Company's revolving credit facilities. Declaration and payment of common stock dividends in 2005 is also being considered.

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

PGE 's current credit ratings are as follows:

In March 2005, following the OPUC's denial of Oregon Electric's application to purchase PGE, S&P affirmed its credit ratings on PGE and changed the Outlook from CreditWatch with negative implications to Developing. Also in March 2005, Fitch raised the ratings of PGE's senior secured and unsecured debt and preferred stock and assigned a rating on PGE's short-term debt. In addition, the Outlook was changed to Stable. The preferred stock rating was withdrawn based on the minimal amount of securities outstanding.

Should Moody's and S&P (or both) reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On March 31, 2005, PGE had posted approximately $15 million of collateral, consisting of $14 million in letters of credit and $1 million in cash. Based on the Company's non-trading and trading portfolios, estimates of current energy market prices, and the current level of collateral outstanding, as of March 31, 2005, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $19 million and decreases to approximately $1 million by year-end 2005. The approximate amount of additional collateral that could be requested upon a dual agency downgrade event to below investment grade is approximately $26 million and decreases to approximately $2 milli on by year-end 2005.

In addition to collateral calls, a credit rating reduction could impact the terms and conditions of long-term debt issued in the future. Any rating reductions could also increase interest rates and fees on PGE's revolving credit facilities, increasing the cost of funding the Company's day-to-day working capital requirements. Management believes that the Company's existing lines of credit, access to the commercial paper market, and cash from operations provide it with sufficient liquidity to meet its day-to-day cash requirements.

In order to increase the degree of insulation between PGE and Enron, in September 2002 PGE created a new class of Limited Voting Junior Preferred Stock and issued a single share of such stock to an independent party. The stock has voting rights which limit PGE's right to commence a voluntary bankruptcy proceeding without the consent of the holder of the share.

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

Weather adjusted retail energy deliveries to PGE and ESS customers increased approximately 2% for the three months ended March 31, 2005, compared to the same period last year. The increase was due primarily to 2.3% and 6.5% increases, respectively, for commercial and industrial customers. Increased industrial usage was largely attributable to a single large customer that normally generates its own power requirements. Weather adjusted residential energy sales were flat compared to the first quarter of 2004, as an approximate 13,600 increase in the average number of customers served during this year's first quarter was offset by a decrease in average energy use. PGE forecasts total weather adjusted energy deliveries to PGE and ESS customers in 2005 to increase by approximately 2% from last year.

Power and Fuel Supply

Hydro conditions in the region during the first quarter of 2005 remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicate the January-to-July runoff (as measured at The Dalles, Oregon) at 69% of normal, compared to actual runoffs of 77% in 2004 and 83% in 2003. In 2005, hydro conditions in the Clackamas and Deschutes river systems, where PGE's facilities are located, are projected to be 51% and 74% of normal, respectively, compared to actual runoffs of approximately 82% and 87% of normal, respectively, in 2004.

PGE generated 45% of its retail load requirement in the first quarter of 2005, with 37% met with thermal generation and the remaining 8% with hydro generation; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers.

Additional factors that could affect the availability and price of purchased power and fuel include weather conditions in the Northwest during winter months and in the Southwest during summer months, as well as the performance of major generating facilities in both regions.

Price Risk Management - As PGE's primary business is to serve its retail customers, it uses derivative instruments to manage its exposure to commodity price risk and to minimize net power costs for customers. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, PGE records unrealized gains and losses in earnings in the current period for derivative instruments that do not qualify for either the normal purchases and normal sales exception or cash flow hedge accounting. Derivative instruments that qualify for the normal purchases and normal sales exception are recorded in earnings on a settlement basis, and cash flow hedges are recorded in OCI until they can offset the related results on the hedged item in the income statement.

From the time rates are set in the RVM process until the end of the RVM period, any changes to electricity and natural gas prices used in the RVM will result in unrealized gains and losses to be recorded in earnings in the current period on existing and new derivative instruments that do not qualify for the normal purchases and normal sales exception or cash flow hedges. Price movements in electricity and natural gas markets cause PGE to make power and natural gas purchases and sales decisions around the economic dispatch of its own generation. Derivative instruments that qualify for the normal purchases and normal sales exception or cash flow hedges, and forecasted transactions related to these decisions are not recorded in earnings in the current period, but are recognized in earnings when the contracts are settled in future periods. As a result, this timing difference may create earnings volatility between reporting periods.

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

Following the termination of the agreement for the sale of PGE to Oregon Electric, the City of Portland publicly announced that it intends to actively pursue the acquisition of PGE.

The Oregon legislature is considering the creation of a public corporation (Oregon Community Power) to buy and operate PGE, to be financed by revenue bonds. In addition, the state's governor has put together a work group to examine the different roles the state might play in the future of PGE, and has outlined certain key principles for any new public or private plan to acquire the Company.

A group of customers and business leaders has recently formed Oregon Mutual Utility Development, Inc., which has proposed a plan to purchase the common stock of PGE and convert the Company to mutual ownership by the Company's ratepayers.

On March 7, 2003, the URP and Linda K. Williams (Complainants) filed a petition to open an investigation and a complaint with the OPUC with respect to the amount of federal, state, and local income taxes paid by PGE since 1997. On March 31, 2003, the OPUC rejected the request for an investigation and on July 9, 2003 issued an order that dismissed the complaint. On September 22, 2003, the OPUC denied the Complainants' request for reconsideration. On December 23, 2003, the URP appealed to the Marion County Circuit Court the OPUC decision not to investigate PGE's tax payments, and on June 4, 2004 the Court reversed the OPUC decision and remanded the matter to the OPUC to proceed on Complainants' allegation that the estimates included in rates for taxes was based on fraud and deceit. On April 5, 2005, the Complainants voluntarily withdrew their complaint, and on April 26, 2005 the OPUC entered an order dismissing the complaint and closing the matter.

On January 18, 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MBIT) after 1996. The plaintiffs allege that during the period 1997 through the third quarter 2004, PGE collected in excess of $6 million from its customers for MBIT that was never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As a member of Enron's consolidated income tax return, PGE paid the tax it collected to Enron. The plaintiffs seek a judgment against PGE for restitution of MBIT collected from customers. Plaintiffs also seek interest, recoverable costs, and reasonable attorney fees. The Plaintiffs filed an amended complaint on February 25, 2005, adding claims for fraud, unjust enrichment, conversion, statutory violati ons, and seeking punitive damages. On February 24, 2005, PGE requested a declaratory ruling from the OPUC on this matter. On March 24, 2005, PGE filed in the Circuit Court a motion to abate or in the alternative to dismiss. Management cannot predict the ultimate outcome of this matter.

A general rate order issued by the OPUC in 2001 approved a new Resource Valuation Mechanism (RVM) tariff that requires annual updates of PGE's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines for Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, the RVM utilizes a combination of market prices and the value of the Company's resources to establish power costs and set prices for energy services. It provides for an adjustment, filed annually in April and finalized in mid-November, which is effective January 1 of the following year.

Preliminary Power Cost Filing - 2006 On April 1, 2005, PGE submitted an RVM filing with the OPUC containing an estimate of 2006 power costs based upon preliminary information that will be updated later in 2005. Preliminary estimates indicate an approximate 3% to 4% average retail price increase (including the effect of all credits and adjustments), due largely to substantial increases in the cost of wholesale power and continued high prices for natural gas.

To address the impact of price volatility in the 2000-2001 wholesale power and natural gas markets, the OPUC authorized PGE to defer for later recovery from retail customers actual net variable power costs which differed from certain baseline amounts approved by the Commission. Under the power cost adjustment mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received OPUC approval to recover the approximate $91 million balance (including interest) over a 3 1/2-year period (April 2002 - September 2005). At March 31, 2005, the remaining balance to be collected was approximately $14 million. PGE did not have a power cost adjustment mechanism in place for 2004 and has none currently in place for 2005.

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

In anticipation of the effects of poor hydro conditions in 2005, the Company on December 30, 2004 filed with the OPUC an "Application for Deferral of Costs and Benefits due to Hydro Generation Variance" that would defer costs, beginning on January 1, 2005, for future amortization in prices.

On April 11, 2005, PGE and OPUC Staff entered into stipulations in both the Hydro Generation Adjustment and deferral application proceedings described above; other parties in the proceedings did not enter into the stipulations. The stipulations agree to and request that the OPUC adopt a temporary System Dispatch Power Cost Adjustment Mechanism to defer for future recovery in rates a portion of power cost changes caused by variations in hydro generation and natural gas plant operations in calendar years 2005 and 2006. A procedural schedule has been adopted for consideration of the stipulations by the Commission.

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

The timing of decommissioning activities at PGE's closed Trojan plant has changed from previous estimates, due primarily to a delay in the completion of a permanent storage facility for spent nuclear fuel and to the acceleration of the planned demolition of major structures at the plant. Spent nuclear fuel is currently maintained in an interim dry storage facility at the plant site until permanent storage becomes available. Due to various factors, completion of the U.S. Department of Energy's long-term repository for the nation's high-level radioactive waste at Yucca Mountain, Nevada, has been delayed. The previous decommissioning plan provided for the shipment of spent fuel to a permanent storage facility by 2018. The updated plan provides for the shipment of spent fuel by 2023, and completion of decommissioning of the interim dry storage facility in 2024. In addition, the Company has decided to accelerate the completion of major structure demolition at the plant from 2018, as pre viously estimated, to 2008. Such revisions resulted in a net $10 million increase in the Trojan asset retirement obligation, measured at estimated fair value, since the end of 2004. PGE continues to expect that any changes in estimated decommissioning costs will be incorporated in future revenues collected from customers.

As of December 31, 2004, PGE has net accounts receivable balances totaling approximately $63 million from the California ISO and the PX for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

Management continues to assess PGE's exposure relative to these receivables. Based upon FERC orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

California - On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for federally-mandated wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets operated by the ISO and PX. The order established evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

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

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds, based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates its potential liability under the modified methodology at between $40 million and $50 million, of which $40 million has been established as a reserve, as discussed above.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order that denied further requests for rehearing of the October 16, 2003 order. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first will consider argument s regarding jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. Briefing and oral argument have been completed on this first phase. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before FERC become final and are appealed.

Also on May 12, 2004, the FERC issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liability. On September 24, 2004, the FERC issued an order that denied requests for rehearing of its May 12, 2004 fuel cost order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology of the September 24, 2004 order, PGE could be required to pay additional amounts in those hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect that this order will materially increase the Company's potential refund exposure. Partly as a means of limiting its exposure to add itional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. In December 2004, the FERC requested comments regarding the manner in which such studies should be conducted and the principles that should control. PGE and numerous other parties filed comments and reply comments in January 2005. Additionally, late comments in support of aspects of PGE's position were filed by the Oregon and Washington public utility commissions and by the Oregon and Washington senate delegations in March, 2005. A decision by the FERC to adopt PGE's approach to these studies could reduce the Company's ultimate refund liability.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). Interest has not yet been recorded by the Company. In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

Challenge of the California Attorney General to Market Based Rates - On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates during the period October 2, 2000 - June 4, 2002 should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's de cision to the Ninth Circuit Court of Appeals. On September 8, 2004, the Court issued an opinion upholding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. PGE cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

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

Pacific Northwest - In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceedings and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders and briefing is ongoing.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

In 1993, following the closure of Trojan, PGE sought full recovery of, and a rate of return on, its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. The filing was a result of PGE's decision earlier in the year to cease commercial operation of Trojan as a part of its least cost planning process. In 1995, the OPUC issued a general rate order (1995 Order) which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals, and requested reviews were subsequently filed in the Marion County Circuit Court, the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

In 2000, while the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into settlement agreements with respect to litigation over recovery of, and return on, the Trojan investment. The settlement agreements, approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of URP's challenges and approving the accounting and rate making elements of the 2000 settlement. URP appealed the 2002 Order to the Marion County Circuit Court and on November 7, 2003, the Court issued an opinion remanding the case to the OPUC for action to red uce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appealed to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs (Class Action Plaintiffs) filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Clas s Action Plaintiffs' claims. On December 14, 2004, the Judge granted the Class Action Plaintiffs' motion for Class Certification and Partial Summary Judgment and denied PGE's motion for Summary Judgment. PGE filed a proposed order certifying the issue for an interlocutory appeal. An order rejecting the proposed order was entered on February 1, 2005. On March 3, 2005, PGE filed a Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed. On March 29, 2005, PGE filed a second Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions. The parties will file briefs on both Petitions over the next few months. Oral argument before the Oregon Supreme Court is expected in the fall of 2005.

On March 3, 2004, the OPUC re-opened three dockets in which it had addressed the issue of a return on PGE's investment in Trojan, including the 1995 Order and 2002 Order related to the settlement of 2000, and issued a notice of a consolidated procedural conference before an administrative law judge to determine what proceedings are necessary to comply with the court orders remanding this matter to the OPUC. On August 31, 2004, the administrative law judge issued an Order (Scoping Order) defining the scope of the proceedings necessary to comply with the Marion County Circuit Court orders remanding this matter to the OPUC. On October 18, 2004, the OPUC affirmed the Scoping Order. On December 20, 2004, the URP and Class Action Plaintiffs filed an application with the OPUC for reconsideration of the Scoping Order. On February 11, 2005, the OPUC denied reconsideration. On April 18, 2005, URP and Linda K. Williams filed a complaint against the OPUC in Marion County Cir cuit Court challenging the OPUC's affirmation of the Scoping Order.

Threatened Litigation - Class Action Lawsuit - On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs), stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, PGE's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million.

Management cannot predict the ultimate outcome of the above challenges. However, it believes that the resolution will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for a future reporting period. No reserves have been established by PGE for any amounts related to this issue.

In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which do not specify an amount of claim, seek binding arbitration. PGE filed for relief in Multnomah County, Oregon Circuit Court seeking a ruling that the grievances are not subject to arbitration. On August 14, 2003, the Court granted PGE's motion for summary judgment, finding that the grievances are not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

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

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

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

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

In March 2001, in accordance with the Voluntary Agreement, PGE submitted a final investigation plan to the DEQ for approval. DEQ approved the plan and in June 2001 PGE performed initial investigations and remedial activities based upon the approved investigation plan. The investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

In February 2002, PGE submitted its final investigative report to the DEQ summarizing its investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such voluntary investigation demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site. Further, the voluntary investigation demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the final investigative report to the EPA and in a May 18, 2004 letter, the EPA stated that "Based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river." Management believes that the Company's contribution to t he sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

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

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on its financial statements.

In October 2003, PGE agreed with the DEQ to provide cost recovery for oversight of a voluntary investigation and/or potential cleanup of petroleum products at another Company site that is upland from the Portland Harbor Superfund Site. Management cannot predict the ultimate outcome of this matter. However, PGE believes this matter will not have a material adverse impact on its financial statements.

In December 2003, PPL Montana, LLC (PPL Montana), the operator of the Colstrip coal-fired generating plants, received an Administrative Compliance Order (ACO) from the EPA pursuant to the Clean Air Act (CAA). The EPA alleges that since 1980, Colstrip Units 3 and 4, in which PGE has a 20% ownership interest, have been in violation of the clean air permit issued under the CAA. The permit required Colstrip Units 3 and 4 to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if and when EPA promulgated certain requirements for nitrogen oxide emissions. The EPA is asserting that regulations it promulgated in 1980 triggered the requirement. The EPA does not expressly seek penalties nor indicate what, if any, additional control technology requirements that it may require to be considered. PPL Montana, which has reported that it believes that the ACO is unfounded, is discussing the matter with the EPA.

In addition to the ACO, the EPA has issued an information request with respect to the Colstrip units. The EPA is investigating whether older coal-fired plants have been modified over the years in a manner that would subject them to more stringent requirements under the CAA. PPL Montana is in the process of responding to the information request.

A local Native American tribe has asserted that sulfur dioxide emissions from Colstrip Units 3 and 4 are affecting local tribal areas more than previously estimated. PPL Montana is working with the Montana Department of Environmental Quality to provide additional information to address this issue.

PPL Montana and EPA are discussing possible emission control and monitoring requirements involving all Colstrip units to address the issues discussed above.

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

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

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' bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);
• events related to Enron's Chapter 11 Plan;
• events related to Enron's distribution of PGE common stock to the Debtor's creditors who hold allowed claims;
• effects of electric industry restructuring in Oregon and in the United States, including retail and wholesale competition;
• governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;
• changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;
• wholesale energy prices (including the effect of FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;
• the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;
• operational factors affecting PGE's power generation facilities;
• changes in, and compliance with, environmental and endangered species laws and policies;
• financial or regulatory accounting principles or policies imposed by governing bodies;
• residential, commercial, and industrial growth and demographic patterns in PGE's service territory;
• the loss of any significant customer, or changes in the business of a major customer, that may result in changes in demand for PGE services;
• the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;
• capital market conditions, including interest rate fluctuations and capital availability;
• changes in PGE's credit ratings, which could have an impact on the availability and cost of capital;
• legal and regulatory proceedings and issues;
• employee workforce factors, including strikes, work stoppages, and the loss of key executives; and,
• general political, economic, and financial market conditions.

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

PGE is exposed to various forms of market risk (including changes in commodity prices, foreign currency exchange rates, and interest rates), as well as to credit risk. These changes may affect the Company's future financial results, as discussed below.

PGE's primary business is to provide electricity to its retail customers. The Company uses both long- and short-term purchased power contracts to supplement its thermal and hydroelectric generation to respond to fluctuations in the demand for electricity and variability in generating plant operations. In meeting these needs, PGE is exposed to market risk arising from the need to purchase power and to purchase fuel for its natural gas and coal fired generating units. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options, and futures contracts to mitigate risk that arises from market fluctuations of commodity prices.

Gains and losses from non-trading instruments that reduce commodity price risks are recognized when settled in Purchased Power and Fuel expense, or in wholesale revenue. 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. 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 of money, and volatility factors underlying the commitments.

PGE actively manages its risk to ensure compliance with its risk management policies. The Company monitors open commodity positions in its energy portfolios using a value at risk methodology, which measures the potential 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 2005 were zero and in the first quarter of 2004 were $0.1 million, $0.2 million, and zero, respectively. In ear ly 2005, PGE discontinued its trading activities; existing trading transactions will continue to settle through December 31, 2005. The average, high, and low value at risk on the non-trading portfolio in the first quarter of 2005 were $3.8 million, $5.0 million, and $3.0 million, respectively, and in 2004 were $1.7 million, $2.3 million, and $1.2 million, respectively.

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

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, 2005, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 12 months. 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, 2005, the Company is typically exposed to risk resulting from changes in interest rates on variable rate short-term borrowings. The Company has also had exposure to interest rate changes on variable rate commercial paper. Although PGE currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

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

Credit risk with respect to trade accounts receivable from retail electricity sales is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, significantly reduces credit risk. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for credit risk. At March 31, 2005, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following tables present PGE's credit exposure for commodity non-trading and trading activities and their subsequent maturity as of March 31, 2005. The tables reflect credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

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

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

PGE has a Risk Management Committee (RMC) which is responsible for the development and oversight of the corporate policies, guidelines, and procedures for management of commodity position and price risk, foreign currency risk, and credit risk related to the Company's energy portfolio management activities. The RMC, which provides quarterly reports to the Audit Committee of PGE's Board of Directors, consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The RMC approves 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 3, Price Risk Management, in the Notes to Financial Statements.

1. Disclosure Controls and Procedures. Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company's disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, the information relating to the Company (including its consolidated subsidiaries) required to be disclosed by the Company in the reports that it files or submits under the Exchange Act and are effective in ensuring that infor mation required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
2. Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

For further information regarding the following proceedings, see PGE's 2004 Annual Report on Form 10-K and other reports filed with the SEC since its 2004 Form 10-K was filed.

On March 29, 2005, PGE filed a second Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions. The parties will file briefs on both Petitions over the next few months. Oral argument before the Oregon Supreme Court is expected in the fall of 2005.

On March 24, 2005, PGE filed a motion to abate or in the alternative dismiss.

On March 10, 2005, a notice of appeal was filed in the Ninth Circuit Court of Appeals.

On March 10, 2005, a notice of appeal was filed in the Ninth Circuit Court of Appeals.

On May 3, 2005, the Compensation Committee of PGE's Board of Directors approved an increase in base compensation for the executive officers of PGE. The new annual base compensation, effective May 16, 2005, for the Named Executive Officers, as listed in Item 11. Executive Compensation, in PGE's 2004 Annual Report on Form 10-K, are presented below:

On May 3, 2005, the Compensation Committee of PGE's Board of Directors approved a one-time, discretionary cash bonus of $16,525 for Stephen M. Quennoz, Vice President, Nuclear & Power Supply/Generation, in recognition of the leadership that Mr. Quennoz provided in PGE's successful decommissioning of the Trojan Nuclear Plant, including the pending receipt of NRC approval of the termination of the plant's Facility Operating License.

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)