Back to GetFilings.com

The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim periods presented. Such statements, which are unaudited, are presented in accordance with the SEC's interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs are subject to year-end adjustment. It is management's opinion that, when the interim statements are read in conjunction with the 2003 Annual Re port on Form 10-K and the other reports filed with the SEC since its 2003 Form 10-K was filed, the disclosures are adequate to make the information presented not misleading.

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

PGE 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 (TOLI) and, beginning in 2003, marketable securities, are intended to be the primary source for financing these plans.

PGE further 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 are made to a voluntary employees' beneficiary association (VEBA) to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers.

The measurement date for these plans is December 31. PGE has not made contributions to the plans during 2004.

The following table indicates components of net periodic benefit cost for the first quarter of 2004 and 2003 (in millions):

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

For retail (non-trading) activities, changes in fair value of derivative instruments prior to settlement are recorded on a net basis in Purchased Power and Fuel expense. As these derivative instruments are settled, physical electricity activities are recorded on a gross basis, with sales recorded in Operating Revenues and purchases, natural gas swaps and futures recorded in Purchased Power and Fuel expense. In accordance with Emerging Issues Task Force Issue No. 03-11 (EITF 03-11), Reporting Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, on October 1, 2003, PGE began recording, on a prospective basis, the non-physical settlements (i.e. book outs) of non-trading electricity derivative activities on a net basis in Purchased Power and Fuel expense. Prior period amounts for non-physical settlements that were recorded on a gross basis in both Operating Revenue s and Purchased Power and Fuel expense have not been reclassified.

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

For energy trading activities, PGE reports all unrealized and realized gains and losses on a net basis, in accordance with EITF 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, with such activities recorded as a component of Operating Revenues.

As PGE's primary business is to serve its retail customers, it uses derivative instruments, including electricity forward and option, and natural gas forward, swap, option and futures contracts to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers. Most of the Company's non-trading wholesale sales have been to utilities and power marketers and have been predominantly short-term. PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such participation includes power purchases and sales resulting from daily economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions ar e also referred to as "book outs". Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations are physically settled.

SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. Rates approved by the OPUC are based on a valuation of all the Company's energy resources, including derivative instruments existing on October 30, 2003 that will settle during the 12-month period from January 1, 2004 to December 31, 2004. Such valuation was based on forward price curves in effect on November 11, 2003 for electricity and natural gas. The timing difference between the recognition of gains and losses on certain derivative instruments and their realization and subsequent collection in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. As these contracts are settled, the regulatory asset or regulatory liability is reversed. However, as there is currently no power cost adjustment mechanism i n effect for 2004, unrealized gains and losses on new 2004 derivatives not included in rates, and changes in fair value of derivatives used to set rates, are not deferred as regulatory assets or regulatory liabilities.

In the first three months of 2004, PGE recorded $8 million in net unrealized gains in earnings in its retail portfolio; this was partially offset by recording a $6 million SFAS No. 71 regulatory liability. In the first three months of 2003, PGE recorded $22 million in net unrealized gains in earnings in its retail portfolio; this was partially offset by recording an $11 million SFAS No. 71 regulatory liability.

Derivative activities recorded in OCI for the first quarter of 2004 from cash flow hedges consist of $9 million of unrealized gains from new contracts and changes in fair value, partially offset by $3 million in net gains reclassified in earnings for contracts that settled during the period. A $1 million SFAS No. 71 regulatory liability was recorded in the first quarter of 2004.

Derivative activities recorded in OCI for the first quarter of 2003 from cash flow hedges consist of $5 million of net unrealized gains in new contracts and changes in fair value, $3 million in net gains reclassified to earnings for contracts that settled during the period, and $6 million in net gains for the discontinuance of cash flow hedges due to the probability that the original forecasted transactions will not occur.

Hedge ineffectiveness from cash flow hedges was not material in the first quarters of 2004 and 2003. As of March 31, 2004, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 21 months. The Company estimates that the $11 million of net unrealized gains at March 31, 2004 will be reclassified into earnings within the next twelve months.

PGE utilizes electricity forward, swap, and option contracts, natural gas forward, swap, option, and futures contracts, and crude oil futures contracts to participate in electricity, natural gas, and crude oil markets. Such activities are not reflected in PGE's retail prices. As indicated above, all unrealized and realized gains and losses associated with "energy trading activities" are reported on a net basis for all periods presented.

The following tables indicate unrealized and realized gains and losses on electricity and fuel trading activities and transaction volumes for electricity trading contracts that settled in the three-month periods ended March 31, 2004 and 2003:

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

Numerous challenges, appeals and requested reviews were subsequently filed in the Marion County, 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 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 Enron/PGC merger. The settlement also allows PGE recovery of approximately $47 million in income tax benefits related to the Trojan investmen t which had been flowed through to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five-year period, beginning in October 2000. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. Collection of decommissioning costs of Trojan is unaffected by the settlement agreements or the OPUC orders.

The URP filed a complaint challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, after a full contested case hearing, the OPUC issued an order (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, from 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.

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.

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

Union Grievances - 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 these grievances.

Other Legal Matters - PGE is party to various other claims, legal actions, and complaints arising in the ordinary course of business. Management cannot predict the ultimate outcome of these matters; however, it believes these matters will not have a material adverse impact on its financial statements.

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. 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):

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

Enron suspended its monthly payments to PGE in September 2001, pursuant to its Stock Purchase Agreement with NW Natural, under which NW Natural was to have assumed Enron's merger payment obligation upon its purchase of PGE. The Stock Purchase Agreement was terminated in May 2002. PGE accrued interest on the Merger Receivable and recorded an offsetting reserve from the December 2001 Enron bankruptcy filing until December 2003. Both the interest and the related reserve accrued in Enron's post-petition bankruptcy period were reversed in December 2003 to reflect PGE's proofs of claim filing. At March 31, 2004, Enron owed PGE approximately $73 million, including interest accrued prior to Enron's bankruptcy filing. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE established a reserve for the full amount of this receivable in December 2001. On October 15, 2002, PGE submitted proofs of claim to the Bankruptcy C ourt for amounts owed PGE by Enron and other bankrupt Enron subsidiaries, including approximately $73 million (including accrued interest) for the Merger Receivable balance as of December 2, 2001, the date of Enron's bankruptcy filing. For further information, see Note 7, Enron Bankruptcy.

Income Taxes 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 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 $36 million income taxes payable to Enron at March 31, 2004 represents a net current income taxes payable of $29 million related to income taxes owed for the first quarter 2004 and $7 million for income taxes owed up to May 7, 2001 (pre-petition liability included as an offset in PGE's proofs of claim filing). During the first quarter 2004, PGE paid $29 million to Enron for income taxes payable for the period from December 24, 2002 to December 31, 2003, primarily for the third and fourth quarters of 2003. Income tax payments were withheld until PGE's December 24, 2002 reconsolidation with Enron was agreed to by the IRS. Agreement was received from the IRS on February 2, 2004. For further information, see Note 7, Enron Bankruptcy.

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

Enron - Beginning in 2004, Enron no longer bills PGE for corporate overhead costs. In the first quarter 2004, Enron passed through to PGE approximately $5 million for medical/dental benefits and retirement savings plan matching and $1 million for insurance coverage. For the same period in 2003, Enron passed through to PGE approximately $5 million for medical/dental benefits and retirement savings plan matching and insurance coverage and billed $3 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001, except for payments for employee benefit plans. In reaching an agreement with Enron regarding the allocation of corporate overheads in the post-bankruptcy period, PGE resumed payments for corporate overhead costs from March 2003 through December 2003. During the first three months of 2004, PGE paid $6 million to Enron, consisting of $5 million for employee benefits and $1 million for insurance premiums. At March 31, 2004, PGE had a $6 million payable to Enron, consisting of $4 million for corporate overheads and restricted stock costs and $2 million for employee benefit costs. Included in the $6 million liability is $4 million related to the pre-petition period, which is included as an offset in PGE's proofs of claim.

At March 31, 2004, Enron owed PGE $1 million related to employee benefits (pre-petition), which has been fully reserved and is included in PGE's proofs of claim filing.

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

At December 31, 2003, PGE was owed a net $2 million by EPMI for power sales and transmission services, which remained outstanding at March 31, 2004. EPMI is part of Enron's bankruptcy proceedings. Due to uncertainties associated with the realization of this receivable from EPMI, a $2 million reserve has been established. PGE included amounts owed by EPMI for power sales and transmission services in the proofs of claim filed with the Bankruptcy Court.

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

Portland General Holdings, Inc. - in Bankruptcy - On June 27, 2003, 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, 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. 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. PGE will continue to assess the collectibility of this receivable.

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

As of March 31, 2004, PGE had outstanding accounts and notes receivable from PGH II and its subsidiaries of $3 million, comprised of $2 million for employee and other corporate governance services ($1 million each owed PGE by PGDC and PES) and a $1 million secured loan to PES.

In April 2004, PES sold substantially all of its assets to an unrelated third party. The proceeds from the sale were used to repay all amounts PES owed to PGE, including trade payables and amounts due under the loan.

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

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

Interest Income and Expense - Interest on the Enron Merger Receivable balance and the related reserve accrued in Enron's post-petition bankruptcy period were reversed in December 2003, as previously discussed. Accounts receivable balances from PGH II and its subsidiaries accrue interest at 9.5%. Receivable balances from PGH also accrued interest at 9.5% until PGH filed bankruptcy and the interest accrual was discontinued. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its other subsidiaries. Beginning in 2001, interest was no longer accrued on those other outstanding balances with Enron due to the proposed merger with Sierra Pacific Resources. Although the proposed merger was terminated in April 2001, interest accrual has not resumed.

As of March 31, 2004, PGE has net accounts receivable balances totaling approximately $60 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 is pursuing collection of all past due amounts through the PX and PG&E bankruptcy proceedings and has filed a proof of claim in each of the proceedings. 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.

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

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

Also in August 2002, the FERC Staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in 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. Although no final dollar amounts were included in the certification, the recommended methodology indicated a potential refund by PGE of $20 million to $30 million.

On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge, issued in December 2002, but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimated that the modified methodology could increase the amount of the potential refunds by approximately $20 million, with the Company's potential liability estimated at between $20 million and $50 million.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the pricing methodology. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. 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.

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.

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

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

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

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

Although Enron is continuing the sale process for PGE, under the Chapter 11 Plan, if PGE is not sold, the shares of PGE's common stock will be distributed over time to the Debtors' creditors. It is anticipated that once a sufficient amount of the common stock is distributed to creditors, the shares would be publicly traded. The Chapter 11 Plan is subject to creditor approval and confirmation by the Bankruptcy Court. A confirmation hearing on the Chapter 11 Plan is currently scheduled to take place in June 2004.

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

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

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

On November 18, 2003, Enron and Oregon Electric Utility Company, LLC (Oregon Electric), a newly-formed Oregon limited liability company financially backed by investment funds managed by Texas Pacific Group, entered into a definitive agreement under which Enron will sell all of the issued and outstanding common stock of PGE to Oregon Electric. The transaction is valued at approximately $2.35 billion, including the assumption of debt. The final amount of consideration will be determined on the basis of PGE's financial performance between January 1, 2003 and closing. The transaction, previously approved by the Enron Board of Directors and supported by the Official Unsecured Creditors' Committee, was approved by the Bankruptcy Court on February 5, 2004. The transaction also requires approval of the OPUC, the SEC, the FERC, and certain other regulatory agencies. On March 8, 2004, application for approval of the acquisition of PGE by Oregon Electric was filed with the OPUC, and on April 6, 2 004, application for approval was filed with the FERC. Filings will be made with the other agencies over the ensuing weeks. A decision is expected by year-end 2004.

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

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

FASB Interpretation No. 46 (FIN 46) Revised December 2003, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, was issued on December 24, 2003. FIN 46 provides guidance on the identification and consolidation of entities (termed "variable interest entities") for which control is achieved by means other than through voting rights. The application of FIN 46 is required in financial statements of entities that have interests in structures commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application of FIN 46 for all other types of variable interest entities is required in financial statements for periods ending after March 15, 2004. The application of FIN 46 did not have a material impact on the Company's financial statements.

On January 12, 2004, the Financial Accounting Standards Board released FASB Staff Position No. FAS 106-1 (FSP 106-1), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefit plans. Uncertainties exist regarding the effects of the Medicare Act on PGE's accumulated postretirement benefit obligation and net postretirement benefit costs and the accounting for those effects, if any. Under FSP 106-1, plan sponsors are allowed to elect a one-time deferral of the accounting for the Medicare Act until the FASB issues specific authoritative accounting guidance regarding the federal subsidy. Amounts and disclosures related to PGE's accumulated postr etirement benefit obligation and net postretirement benefit costs in the financial statements and accompanying notes do not reflect the effects of the Medicare Act on the plan.

Operations - PGE continues to serve its customers effectively and operate well. Earnings in the first quarter of 2004, compared to the prior year, were more typical of the Company's historical levels. It is expected that the effects of a suppressed economy and recent years' financial reserves related to Enron's bankruptcy and the 2000-2001 West Coast energy crisis will have less impact on PGE's future earnings. PGE continues to maintain investment-grade ratings on its secured debt, has adequate liquidity, and stable operating cash flow.

Despite the positive effect of significantly colder-than-normal January weather on residential and commercial energy sales, retail loads continue to run below projections. The combined effect of a decrease in industrial load, a continued slow economy, and warmer-than-normal weather in February and March contributed to loads that fell below both current year projections and last year's first quarter. On a weather-adjusted basis, however, retail energy sales have grown marginally from the first quarter of last year.

January 2004's snow and ice storm demonstrated the skills of PGE employees and the value of the Company's ongoing investment in its transmission, distribution, and customer service systems. PGE's continuing commitment to invest in system improvement and preventive maintenance, as well as outage preparation efforts and other specific actions taken over the last several years, significantly reduced the impact of the storm. Despite its severity (one of Oregon's worst storms in the last 100 years), outages affected less than 8% of PGE's customers. Insurance recovery will help mitigate the storm's financial impact on the Company.

In early April 2004, PGE's bargaining unit employees (Local Union No. 125 of the International Brotherhood of Electrical Workers) voted to ratify a new five-year contract with the Company. Both sides worked very hard to reach a fair settlement that recognizes the critical work performed to deliver safe, reliable power to customers. The new agreement, which provides for wage increases as well as improved retirement and health benefits, provides predictability and stability for both union employees and the Company.

PGE continues to oppose recent efforts by public power proponents to acquire Company service territory. The Company is pleased with the continued support of its communities, as demonstrated by the rejection of two PUD initiatives (in Multnomah and Yamhill Counties) in the last six months, and is aggressively preparing for a third ballot measure, in Clackamas County, in May 2004.

Economy - Oregon's economy has shown recent signs of improvement, which are expected to continue along with the national economy. In this year's first quarter, the state posted modest payroll gains amid a continued high jobless rate. As Oregon slowly recovers from the recession, the seasonally-adjusted unemployment rate has fallen from a high of 8.5% in June 2003 to 7.1% in February 2004. The Company continues to experience customer growth, adding approximately 3,500 retail customers in the first quarter of this year. PGE remains committed to promoting economic growth, working with regional and state economic development agencies to help promote future business development. To enhance these efforts, the Company is working with a local economic development group, which recently received a federal grant to complete a comprehensive economic development strategy for the Portland metropolitan area.

Power Supply - Despite heavy snowfall in early January, regional hydro conditions have deteriorated significantly from earlier forecasts due to reduced precipitation and generally dry conditions from February through April. Regional conditions are expected to remain significantly below normal for 2004, with both the Clackamas and Deschutes river systems, where PGE's hydro generation facilities are located, also projected at below normal levels. To the extent that hydro conditions utilized in power cost projections for setting customer rates are not realized, increased power costs could result, as increased output from PGE's thermal generating plants, as well as higher purchased power costs, are necessary to meet its load requirements.

PGE's thermal generating plants continue to operate well and the Company's hydro plants continue to serve as a reliable low-cost resource, providing economical power for customers. During the first quarter of 2004, PGE effectively utilized its generating assets and position in the wholesale marketplace to meet load requirements and offset the adverse financial effects of poor regional hydro conditions.

The "Resource Valuation Mechanism" (RVM) process, by which retail rates are adjusted annually with changes in projected power costs, has enabled the Company to more timely adjust customer rates to reflect the variable cost of power. The RVM utilizes a combination of market prices and the value of the Company's resources to establish power costs and set rates for energy services. The RVM rate process is finalized by mid-November with new rates to become effective January 1 of the following year. PGE's preliminary 2005 RVM filing, submitted to the OPUC in April 2004, indicates a moderate retail rate increase beginning in 2005. The Company currently has a hydro cost deferral application for the current year pending with the OPUC and will continue to work with the Commission to develop a longer term mechanism that allows rate adjustments reflecting changes in power costs caused by variations in hydro conditions.

The Company is awaiting OPUC response to its final Action Plan, filed in March 2004 in conjunction with the Integrated Resource Plan process. The plan proposes specific resource actions, including construction of a natural gas-fired plant at the Port Westward site in Columbia County, Oregon and increased use of renewable energy resources, to meet the future electricity needs of customers. The OPUC Staff has issued a report recommending that the Commission adopt a proposed order to acknowledge the plan, with the current schedule providing for Commission action on Staff's recommendation by the end of May 2004. PGE will work further with the Commission in decisions regarding cost-based rate recovery of such additional resources.

Proposed Sale of PGE - The proposed sale of PGE by Enron to Oregon Electric Utility Company, LLC (Oregon Electric) has begun moving through the regulatory hearing and approval process. The OPUC is conducting public meetings to provide information and gain public input on the proposed purchase and has adopted a schedule for the formal process that Commission staff and parties will follow. This schedule provides for information sharing and for the exchange of proposals to ensure that the proposed transaction provides net benefits to retail customers. Although Oregon Electric initiated and will lead the required legal and regulatory approvals, PGE believes the proposed transaction represents the best possible outcome for the Company and will be working to support its full regulatory approval. A decision is currently expected by the end of this year.

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 2004.

PGE's net income in the first quarter of 2004 was $32 million, compared to $21 million in the first quarter of 2003. The increase was due primarily to a higher margin on total retail and wholesale energy sales. Results for the first quarter of 2003 include an after tax provision of approximately $7 million related to amounts due PGE for certain prior year wholesale electricity sales made in California and a $2 million gain from a cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations.

The following table summarizes Operating Revenues and Energy Sales for the first quarter of 2004 and 2003:

Retail revenues increased slightly from the first quarter of last year, as an approximate 0.4% rate increase, reflecting an increase in projected 2004 variable power costs, was partially offset by a decrease in energy sales. (See "Retail Rate Changes" in the Financial and Operating Outlook section for further information). Retail energy sales decreased about 2.5% from last year's first quarter due to a 27% decline in industrial energy sales, most of which was attributable to a single large customer that began generating its own power requirements in the second quarter of 2003. Residential and commercial energy sales increased 7% and 2%, respectively. An approximate 12,600 increase in customers served since the end of last year's first quarter, combined with significantly colder January weather, partially offset the decrease in industrial energy sales.

Lower wholesale energy sales and revenues resulted from a reduction in energy marketing activity from last year's first quarter, the result of both a continued decline in market liquidity and in the number of wholesale energy market participants. Average wholesale power prices increased 2%, primarily due to higher natural gas prices. Wholesale revenues and energy sales for the first quarter of 2004 reflect reductions of $59 million and 1,406 thousand MWhs related to the adoption of EITF 03-11 in the fourth quarter of 2003. Beginning October 1, 2003, revenues and expenses related to non-trading energy activities that are not physically settled, formerly included on a "gross" basis within both Operating Revenues and Purchased Power and Fuel expense, are recorded on a "net" basis in Purchased Power and Fuel expense. This change results in a decrease in reported non-trading wholesale energy sales and purchases and related amounts in comparative financial statements. Although determination of t he effect of the change on prior year reported revenues and expenses is not practicable, the change has no impact on reported net income.

The decrease in Other Operating Revenues from last year's first quarter was caused primarily by reduced gains on the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense decreased $106 million (37%). The decrease was due to a reduction in both the volume and average price of energy purchased in the wholesale market, related to a reduction in market activity, as discussed above. Purchased Power and Fuel expense for the first quarter of 2004 reflects a reduction of $59 million related to the adoption of EITF 03-11 (described above). Decreases in the average price of both firm and spot market purchases, as well as PGE thermal generation, resulted in a 21% reduction in the Company's average variable power cost from that of the first quarter of 2003. Included in first quarter 2003 expense was an $11.5 million provision for uncollectible accounts receivable for wholesale electricity sales in the California market. (For further information, see "Receivables and Refunds on Wholesale Market Transactions" in the Financial and Operating Outlook section). Company generation increased 5% from that of last year's first quarter, with an 1 1% increase in coal-fired generation partially offset by a decrease in hydro production, due to lower stream flows. Total generation met approximately 48% of PGE's retail load during the first quarter of 2004, compared to 44% 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 2004 and 2003.

(*includes wheeling costs)

Production, distribution, administrative and other expenses were unchanged from the first quarter of 2003. Increased service restoration costs related to a five-day snow and ice storm in January 2004 were offset by the estimated insurance recovery of storm costs and by reduced corporate overhead charges from Enron.

Depreciation and Amortization expense increased $4 million (7%) due primarily to a $3 million increase in amortization of regulatory assets (including costs related to implementation of Oregon's electricity restructuring law), the effects of which are fully offset within Operating Revenues. In addition, there was a $1 million increase in depreciation of utility plant.

Income taxes increased $11 million primarily due to higher taxable income.

Other Income decreased $1 million. A $4 million reduction in interest on regulatory assets was partially offset by a $3 million increase in income from non-qualified benefit plan trust assets.

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 weather conditions, as temperatures outside the normal range can affect electricity usage and resultant operating cash flow, as well as the need for short-term borrowings to meet current cash requirements.

Cash provided by operating activities totaled $99 million in this year's first quarter compared to $81 million in the same period last year. The increase is due primarily to a decrease in payments made for power purchases and to cash collateral deposits received from certain wholesale customers. These increases were partially offset by a reduction in amounts received from wholesale energy sales.

Cash from operations and remaining proceeds from long-term debt issued in 2003 were invested primarily in government money market funds at March 31, 2004. 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 maturing within one year, as approved by PGE's board of directors.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. A $2 million increase in capital expenditures in the first quarter of 2004 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. The $5 million increase in "Other - net" is related primarily to cash benefits received under agreements with BPA that provide both power and cash benefits for PGE's residential and small farm customers.

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 facility, and long-term financing activities to support such requirements. `

During the first quarter of 2004, PGE repaid $2 million of conservation bonds and also paid $0.5 million of preferred stock dividends. In accordance with requirements of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which became effective July 1, 2003, preferred stock dividends are now classified as interest expense on the income statement. No cash dividends on common stock were declared or paid in the first quarter of 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 securing the bonds. As of March 31, 2004, 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's has a $150 million 364-day revolving credit facility with a group of commercial banks. Under the facility, PGE has the option to issue up to $100 million in letters of credit, which accommodates the Company's collateral requirements related to its wholesale trading activities and other operating needs. At March 31, 2004, the Company had utilized approximately $3 million in letters of credit, all of which were related to wholesale trading activities. PGE's current credit facility contains a material adverse change clause and financial covenants that limit consolidated indebtedness, as defined in the facility, to 60% of total capitalization; it also requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.75:1. At March 31, 2004, the Company's indebtedness to total capitalization and interest coverage ratios, as calculated under the facility, were 46.2% and 5.23:1, respectively. The facility is secured by First Mortgage Bonds issued by the C ompany and requires annual facility fees of 0.25%. The facility prohibits the payment of any cash dividends or any other distributions by PGE on its common stock. PGE's current revolving credit facility is expected to be replaced on or before its May 27, 2004 expiration date.

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 facility supplements operating cash flow and provides 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 50% to 55%. 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 55.4% and 54.7% at March 31, 2004 and December 31, 2003, 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 $160 million to $190 million annually over the period 2004-2006. Combined with all other sources, total cash provided by operations is estimated to range from $300 million to $360 million annually during the 2004-2006 period.

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

1. System improvements to support both new and existing customers, excluding the proposed construction of Port Westward.

Projected cash flow from operations in excess of cash requirements may be used to fund costs associated with securing new energy resources, including the proposed construction of the Port Westward combustion turbine plant. Construction of the Port Westward plant is contingent upon OPUC review and acknowledgment of PGE's Integrated Resource Plan (for further information, see "Integrated Resource Plan" in the Financial and Operating Outlook section). Under the Company's proposal, it is anticipated that the Port Westward plant would be operational in late 2006 and cost approximately $210 million to $260 million, excluding Allowance for Funds Used During Construction, ($80 million to $100 million in 2004, $110 million to $130 million in 2005, and $20 million to $30 million in 2006). To the extent necessary, long-term debt may be considered to fund any potential shortfall. Additional liquidity is available under the Company's revolving credit facility, which is expected to be replaced on or before its May 27, 2004 expiration date. PGE anticipates long-term financing activity of $75 million to $100 million in both 2004 and 2005.

PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's Investors Service (Moody's) and Standard and Poor's (S&P). Fitch Ratings (Fitch) rates PGE's secured debt at investment grade and unsecured debt at below investment grade.

PGE 's current credit ratings are as follows:

In March 2004, S&P placed PGE's credit ratings on CreditWatch with negative implications following Oregon Electric's filing with the OPUC to purchase PGE from Enron. S&P's Outlook change is based on their view of the consolidated leverage from the proposed acquisition of PGE by Oregon Electric. Should Moody's and S&P reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On March 31, 2004, PGE had posted, in the form of letters of credit, approximately $3 million of collateral. 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, 2004, the approximate amount of additional collateral that could be requested upon such a downgrade event is $35 million and decreases to approximately $25 million by year-en d 2004. In addition to collateral calls, such 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 facility, increasing the cost of funding the Company's day-to-day working capital requirements. As discussed in "Cash Requirements" above, management believes that the Company's existing line 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 its insolvent parent company, PGE, in September 2002, 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 bankruptcy on PGE, management is unable to predict what actions, if any, will be taken by the rating agencies in the future. However, PGE management believes there are sufficient structural and regulatory mechanisms to protect the Company's assets from Enron and its creditors and there are no economic incentives for Enron to cause PGE to file for bankruptcy protection. PGE, as a separate corporation, owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. PGE maintains its own cash management system and finances itself separately from Enron, on both a short- and long-term basis. Neither PGE nor Enron have guaranteed the obligations of the other and there are no loans between them. Under Oregon law and specific conditions imposed on Enron and PGE by t he OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997, Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. PGE is a solvent enterprise whose greatest value is as a going concern. In a bankruptcy, Enron would lose most, if not all, control over PGE. It would merely continue to be the holder of PGE's common stock, and PGE, as a Debtor in Possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. Any plan of reorganization would be devised by PGE management and approved by PGE's creditors, not Enron or its creditors. No dividends could be paid to Enron, no assets could be sold, and no other transfer of funds could be made except with the approval of the PGE creditors and the Bankruptcy Court. PGE believes that the OPUC would challenge any attempt in the bankruptcy proceedings to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party without OPUC approval.

Weather adjusted retail energy sales increased approximately 1% for the three months ended March 31, 2004, compared to the same period last year. An approximate 5% increase in weather adjusted residential and commercial energy sales was largely offset by a 14% decrease in industrial energy sales. The decrease in industrial sales is largely attributable to two large customers, one of which elected to obtain its electricity requirements through co-generation. These two customers represented 3.9% of weather adjusted retail energy sales in the first quarter of 2003. The increase in residential and commercial energy sales was largely attributable to a 1.6% increase in customers served. PGE forecasts retail energy sales growth of approximately 1% in 2004.

Power Supply

Hydro conditions in the region have worsened in the first quarter of 2004 and remain below normal levels. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, currently project the January-to-July runoff at 76% of normal, down from 87% of normal projected earlier in 2004. Actual January-to-July runoff in 2003 was 83% of normal. Hydro conditions in both the Clackamas and Deschutes river systems, where PGE's facilities are located, are currently projected at 87% of normal for 2004.

PGE generated 48% of its retail load requirement in the first quarter of 2004, with 11% of such requirement met 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.

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

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 endeavor 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 Other Comprehensive Income 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.

PGE employees represented by Local Union No. 125 of the International Brotherhood of Electrical Workers (IBEW) have voted in favor of a new five-year agreement, which is effective for the period March 1, 2004 through February 28, 2009. The agreement provides for wage increases in each of the five years as well as improved retirement and retiree health benefits for the duration of the agreement.

Commencing in December 2001, 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.

Proponents of the formation of Peoples' Utility Districts (PUDs) to acquire PGE's service territory obtained sufficient certified signatures on initiative petitions to place measures on election ballots in Multnomah, Yamhill, and Clackamas Counties. Formation initiatives in Multnomah and Yamhill Counties were rejected by voters in November 2003 and March 2004. In Clackamas County (which has approximately 158,000 PGE customers), the vote on formation of a PUD has been set for the May 18, 2004 ballot.

In addition, sufficient signatures have been certified to place a PUD measure on a future election ballot to form a PUD in eight Portland voting precincts within Multnomah County in which a majority voted for a Multnomah County PUD in November 2003, and sufficient signatures have been certified to place a PUD measure on a future election ballot in Washington County. No election dates have yet been finalized for these initiatives.

In order to protect both PGE and its customers from price volatility in the wholesale power and natural gas markets, the OPUC authorized the Company 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 initial 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, 2004, the remaining balance to be collected was approximately $40 million.

In its August 2001 general rate order, the OPUC approved a power cost adjustment mechanism for the period October 2001 through December 2002. Under this mechanism, PGE deferred approximately $41 million in power costs, representing the difference between actual net variable power costs and the amount used to establish base energy rates, as well as the difference between actual energy revenues and a pre-determined base. The deferred amount is being collected over a two-year period (January 2003 - December 2004), with recovery from large industrial customers completed during 2003. As a result of a stipulation reached with the OPUC staff and an intervenor related to a prudence review, the deferred amount was reduced by $1 million in the first quarter of 2004 and reflected in earnings for the quarter. At March 31, 2004, the remaining balance to be collected was approximately $6 million.

PGE did not have a power cost adjustment mechanism in place for 2003 and has none in place for 2004.

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

PGE's first annual revision of its power supply costs under the RVM process forecast a reduction in the cost of power from that included in the Company's 2001 general rate case. Accordingly, the OPUC authorized an approximate 7% average reduction in the Company's retail prices, effective January 1, 2003. Price decreases ranged from 2% for residential customers to between 9% and 17% for commercial and industrial customers. Rates for business customers were affected more by wholesale energy market prices, which decreased in the 2003 forecast. The smaller decrease in residential rates reflected both PGE's cost of generation as well as the higher cost of electricity from BPA, which increased its rates in October 2002. These price decreases reduced PGE's 2003 revenues by approximately $90 million.

In August 2003, PGE, OPUC staff, and intervenors entered into a stipulation, approved by the Commission, related to the Company's forecast of 2004 net variable power costs. Forecast adjustments were made to the price of certain wholesale power purchase contracts, reflecting recent electricity forward prices and certain other modifications and adjustments to estimated variable power and fuel costs. The 2004 RVM was finalized in November 2003, with new rates effective January 1, 2004. The average price for all customers increased by approximately 0.4%. Price adjustments ranged from a 2.3% decrease for industrial customers to increases of 2.8% and 1.9% for small commercial and residential customers, respectively. Price adjustments varied between customer classes primarily due to different collection periods for PGE's 2001-2002 power cost adjustment mechanism (see "Power Cost Adjustment Mechanisms" in this section for further information). Based upon projected energy sales, it is estimated that the price adjustments will increase PGE's 2004 revenues by approximately $4 million.

The stipulation also provides that PGE withdraw a proposed power cost adjustment mechanism for 2004 and participate in a process to address the need for, and structure of, a cost recovery mechanism for variances in power costs from forecasted levels. PGE continues to work with customer groups and the OPUC staff on the development of a multi-year power cost adjustment mechanism, with particular focus on power cost variations caused by changes in hydro conditions.

On April 1, 2004, PGE submitted an RVM filing with the OPUC containing an estimate of 2005 power costs based upon preliminary information that will be updated later in 2004. Power costs in 2005 are estimated at $492 million, or $42 million higher than the 2004 forecast. The projected power cost increase is based upon an estimated $31 million increase caused by higher loads for customers receiving power under PGE "cost of service" tariffs, an estimated $10 million increase resulting from higher wholesale power and gas prices, an estimated $8 million increase in BPA subscription power costs, and an estimated $7 million increase resulting from lower hydroelectric power availability during 2005. Such increases are partially offset by $14 million in power cost reductions related to a projected increase in the availability and output of PGE's Boardman coal-fired plant, along with reduced coal transportation costs.

The filing forecasts an average retail price increase of 1.7 percent. Preliminary estimates indicate 2.1 percent and 2.0 percent increases in residential and large nonresidential rates, respectively. Small nonresidential rates would decrease by 0.6 percent. Final adjustments will be determined in November 2004.

In anticipation of the effects of adverse hydro conditions, PGE began in early 2003 to acquire replacement power resources for the expected shortfall in hydro-based power, incurring substantially higher variable power costs than those included in the Company's electric rates.

In February 2003, PGE filed an Application for Deferral of Hydro Replacement Power Costs with the OPUC, in which the Company requested authorization to defer for later ratemaking treatment increases in power costs incurred from the application date through December 31, 2003. The Company's application requested authorization for the deferral of 95% of the difference between actual net variable power costs and those allowed in current rates. As proposed, the deferral would be adjusted for the impact that changes in load would otherwise have on net variable power costs. Under the Company's proposed methodology, approximately $25 million in power costs would have been deferred for future ratemaking treatment in 2003. In March 2004, the OPUC denied PGE's application for the deferral of hydro replacement power costs incurred in 2003.

On December 31, 2003, PGE filed an Application for Deferral of 2004 Hydro Related Costs with the OPUC covering the year 2004. The application, similar to the February 2003 filing, requests the deferral of excess power costs resulting from hydro conditions that vary from those assumed in the 2004 RVM process. PGE continues to work with customer groups and the OPUC staff to develop a multi-year power cost adjustment mechanism that focuses on power cost variations caused by changes in hydro conditions.

PGE filed an Integrated Resource Plan (IRP) with the OPUC in 2002, with a supplement filed in February 2003. The IRP describes the Company's strategy to meet the electric energy needs of its customers, with an emphasis on cost, long-term price stability, and supply reliability. It details resource actions over the next two to three years that provide for reduced reliance on short-term wholesale power contracts and increased emphasis on longer-term supplies. The IRP also addresses future investment in additional generating resources (including upgrades to existing resources), an increase in renewable resources, longer-term power purchases, the use of seasonal exchanges to meet peaking requirements, demand-side management, and capacity tolling contracts.

In June 2003, following approval by the OPUC, PGE issued a request for proposals (RFP) to prospective suppliers (including power generators, wholesalers, and developers) to acquire resources to meet the electricity needs of its customers. In January 2004, PGE filed a Proposed Action Plan with the Commission on how to best meet its customers' future power supply requirements, beginning as early as 2006. On March 26, 2004, PGE filed its Final Action Plan to update and refine its recommendations. These recommendations include the acquisition of approximately 790 average MW in short-term, mid-term, and long-term resources, consisting of six components: 1) construction of a natural gas-fired power plant at PGE's Port Westward site in Columbia County, Oregon, producing 350 average MW, beginning in late 2006; 2) acquisition of 65 average MW (195 MW capacity) of wind generation from RFP proposals; 3) acquisition of 135 average MW in fixed price power purchase agreements with durations of 5 to 10 y ears from RFP proposals; 4) acquisition of 55 average MW in energy efficiency savings by the Energy Trust of Oregon; 5) upgrades and contract extensions to existing plants of 60 average MW; and, 6) short-term market acquisitions of 125 average MW. In addition to the increased capacity, the recommendations include approximately 955 MW of additional capacity from the extension of a current contract with the Confederated Tribes to 2012, new dispatchable standby generation, duct firing from the proposed Port Westward plant, and peak tolling agreements.

On April 23, 2004, the OPUC Staff issued a report recommending that the Commission adopt a proposed order to acknowledge PGE's Final Action Plan. The current schedule provides for Commission action on Staff's recommendation by the end of May 2004.

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, approved by the OPUC in September 2000, which 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 ratemaking elements of the 2000 settlement. URP appealed the 2002 order to the Marion County Circuit Court and on November 7, 2003, the Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appealed to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment.

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.

Management cannot predict the ultimate outcome of these 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.

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. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement. 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 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.

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.

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 Environmental Protection Agency (EPA) pursuant to the Clean Air Act (Act). 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 Act. 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 oxides. 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 regional office that regulates plants in Montana has issued an information request with respect to the Colstrip plants. The regional office 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 Act. 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 3 & 4 units 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. The Company is unable to predict the cost, if any, to it related to these matters.

On January 12, 2004, the Financial Accounting Standards Board released FASB Staff Position No. FAS 106-1 (FSP 106-1), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefit plans. Uncertainties exist regarding the effects of the Medicare Act on PGE's accumulated postretirement benefit obligation and net postretirement benefit costs and the accounting for those effects, if any. Under FSP 106-1, plan sponsors are allowed to elect a one-time deferral of the accounting for the Medicare Act until the FASB issues specific authoritative accounting guidance regarding the federal subsidy. Amounts and disclosures related to PGE's accumulat ed postretirement benefit obligation and net postretirement benefit costs in the financial statements and accompanying notes do not reflect the effects of the Medicare Act on the plan.

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

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

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

• matters related to Enron and certain of its subsidiaries' filings to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);
• events related to Enron's bankruptcy proceedings;
• events related to Enron's proposed sale of PGE to Oregon Electric;
• 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, which include changes in commodity prices, foreign currency exchange rates, interest rates, and 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. Under EITF 02-3, gains and losses on such instruments are recognized on a net basis within Operating Revenues on PGE's income statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value 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 2004 were $0.1 million, $0.2 million, and zero, respectively, and in the first quarter of 2003 were $0.1 million, $0 .2 million, and $0.1 million, respectively. The average, high, and low value at risk on the non-trading portfolio in the first quarter of 2004 were $1.7 million, $2.3 million, and $1.2 million, respectively, and in the first quarter of 2003 were $2.3 million, $2.6 million, and $2.0 million, respectively. In 2004 and 2003, PGE did not reduce its non-trading value at risk by the amount of potential deferrals.

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

At March 31, 2004, 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, 2004, 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 and setting limits and monitoring exposures, 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, 2004, 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, 2004. The tables reflect credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. The netting of counterparty balances is reflected only to the extent PGE has the contractual right of offset.

Investment grade includes counterparties with a minimum senior unsecured debt credit rating of Baa3 assigned by Moody's Investor Service (Moody's) and BBB- assigned by Standard & Poor's Rating Group (S&P). Non-investment grade includes counterparties with credit ratings that are below investment grade. The credit exposure includes activity for electricity and natural gas forward, swap and option contracts. Credit collateral posted 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, which is responsible for the oversight of commodity position and price risk, foreign currency risk and credit risk related to wholesale energy marketing activities. PGE's Risk Management Committee consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The Risk Management Committee approves trading and credit policies and procedures, establishes limits subject to Enron approval, and monitors compliance and risk exposure on a regular basis through reports and meetings.

For further information on price risk management activities, see Note 3, Price Risk Management, in the Notes to Consolidated 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.
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 report on Form 10-K for the year ended December 31, 2003.

On April 28, 2004, plaintiffs filed a Motion for Partial Summary Judgment.

The following individual was appointed as a Director of PGE, effective April 1, 2004:

Raymond S. Troubh - Mr. Troubh has been a financial consultant for more than five years. Mr. Troubh has been a director of Enron Corp.^(*) since November 27, 2001 and Chairman of the Board of Enron since November 14, 2002. He is also a director of Diamond Offshore Drilling, Inc., General American Investors Company, Gentiva Health Services, Inc., Petrie Stores Liquidating Trust (Trustee), Triarc Companies, Inc. and WHX Corporation.

1. Exhibits

(3) Articles of Incorporation and Bylaws

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

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

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

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

3.5 * Amended and Restated Bylaws of Portland General Electric Company as amended on February 1, 2004.

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

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

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

31.1 Certification of Chief Executive Officer of Portland General Electric Company pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 (filed herewith).

31.2 Certification of Chief Financial Officer of Portland General Electric Company pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934 (filed herewith).

(32) Section 1350 Certifications

Certifications of Chief Executive Officer and Chief Financial Officer of Portland General Electric Company Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

* Incorporated by reference as indicated.

 

2. Reports on Form 8-K

January 9, 2004 - Item 4. Changes in Registrant's Certifying Accountant (Form 8-K/A).

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)