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The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim periods presented. Such statements, which are unaudited, are presented in accordance with the SEC's interim reporting requirements, which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods 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.

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 tables indicate components of net periodic benefit cost for the periods indicated (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 Re venues 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 half of 2004, PGE recorded $20 million in net unrealized gains in earnings in its retail portfolio, including $12 million in net unrealized gains in the second quarter. The net unrealized gain in the first half of 2004 was largely offset by recording a $19 million SFAS No. 71 regulatory liability, calculated on the basis indicated above. In the first half of 2003, PGE recorded $23 million in net unrealized gains in earnings in its retail portfolio, including $1 million in net unrealized gains in the second quarter. The net unrealized gain in the first half of 2003 was partially offset by recording a $15 million SFAS No. 71 regulatory liability.

Derivative activities recorded in OCI for the three- and six-month periods ended June 30, 2004 from cash flow hedges consist of unrealized gains of $10 million and $19 million, respectively, from new contracts and changes in fair value, partially offset by $3 million and $6 million, respectively, in net gains reclassified in earnings for contracts that settled during the three- and six-month periods. A $7 million SFAS No. 71 regulatory liability was recorded in the first half of 2004.

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

Hedge ineffectiveness from cash flow hedges was not material in the first half of 2004 and 2003. As of June 30, 2004, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 30 months. The Company estimates that of the $17 million of net unrealized gains at June 30, 2004, $15 million 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- and six-month periods ended June 30, 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, and return on, its investment in the Trojan plant. URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of PGC's 1997 merger with Enron. The settlement also allows PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had been flowed through to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five-year period, beginning in October 2000. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. Authorized collection of decommissioning costs of Trojan is unaffected by the settlement agreements or the OPUC orders.

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

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2001 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, but who are no longer customers (Former Class). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of Plaintiff's claims. A hearing on the motion is set for October 2004 and a hearing on class certification has been set for November 2004.

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. DEQ submitted the final investigative report to EPA and in a May 18, 2004 letter EPA stated "Based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river." Management believes that the Company's contribution to 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 - In 1997, Enron acquired PGE through a merger between Enron and PGC. Under terms of the 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 June 30, 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 Co urt 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 and its subsidiaries ceased to be a member of Enron's consolidated tax group on May 7, 2001. On December 24, 2002, PGE and its subsidiaries again became a member of Enron's consolidated tax group. The $23 million income taxes payable to Enron at June 30, 2004 represents a net current income taxes payable of $16 million for the second quarter of 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 half of 2004, PGE paid $58 million to Enron for income taxes payable, of which $29 million was for the period from December 24, 2002 to December 31, 2003, primarily for the third and fourth quarters of 2003. Income tax payments for those periods were withheld until PGE's December 24, 2002 reconsolidation with Enron was agreed to by the IRS on February 2, 2004. The remaining $29 million tax payment to Enron was for the first quarter of 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 six months of 2004, Enron passed through to PGE approximately $11 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 $10 million for medical/dental benefits and retirement savings plan matching and insurance coverage and billed $7 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 six months of 2004, PGE paid $12 million to Enron, consisting of $11 million for employee benefits and $1 million for insurance premiums. At June 30, 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 June 30, 2004, Enron owed PGE $1 million related to taxes on 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 June 30, 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 June 30, 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. In June 2004, PGE reduced the reserve by $1 million based on management's current assessment. PGE will continue to assess th e 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 June 30, 2004, PGE had outstanding accounts receivable from PGDC of $1 million for employee and other corporate governance services. PGDC is in the process of selling substantially all of its assets to an unrelated third party. Based on management's assessment of the realizability of the receivable from PGDC, a reserve of about $1 million was established in June 2004. PGE will continue to assess the collectibility of this receivable.

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.

Other Subsidiaries - 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 on pre-bankruptcy receivables was discontinued. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its other subsidiaries.

As of June 30, 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 filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

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

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) 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. The Chapter 11 Plan was confirmed by the Bankruptcy Court on July 15, 2004.

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.

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 pled ged 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. In July 2004, Enron filed a motion with the Bankruptcy Court to replace the letters of credit outstanding under the debtor in possession financing with letters of credit issued by Wachovia Bank National Association. If approved by the Bankruptcy Court and the SEC, the replacement letters of credit would be secured by cash collateral and would not involve a pledge of other assets.

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. Applications for approval of the acquisition of PGE by Oregon Electric have been filed with the OPUC (on March 8, 2004), the FERC (on April 6, 2004), the Nuclear Regulatory Commission (on June 14, 2004), and the SEC (on July 29, 2004). On July 30, 2004, a petition was filed with Oregon's Energy Facility Siting Council for a declaratory ruling that the proposed acquisition is not a transfer of ownership that would require a transfer of certain generating plant site certificates held by PGE.

As part of the OPUC process to consider the proposed sale, testimony, settlement conferences, and hearings have been scheduled. Final oral arguments have been scheduled for December, with a decision 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 either the sale to Oregon Electric is approved, the Chapter 11 Plan becomes effective and PGE's common stock is distributed to the Debtors' creditors, 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.

On January 12, 2004, the Financial Accounting Standards Board (FASB) 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 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.

On May 19, 2004, the FASB issued Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which is effective for the first interim period beginning after June 15, 2004 and will supersede FSP 106-1. FSP 106-2 provides authoritative guidance on the accounting for the federal subsidy and specifies the disclosure requirements for employers who have adopted FSP 106-2. PGE is currently evaluating the impact of the application of FSP 106-2 but does not expect its adoption to have a material effect on the financial statements of the Company.

On May 24, 2004, PGE completed two new revolving credit facilities with a group of commercial banks totaling $150 million, consisting of a $50 million 364-day facility and a $100 million three-year facility. These facilities, both of which are unsecured, replaced an expired $150 million 364-day secured revolving credit facility. Both new facilities contain material adverse effect clauses and financial covenants that limit consolidated indebtedness, as defined in the facilities, to 60% of total capitalization. In addition, the new three-year facility requires that PGE maintain an interest coverage ratio, as defined in the facility, of not less than 3.00:1. The new 364-day facility contains a "term out" option that would allow the Company to extend the final maturity of amounts outstanding at the date the facility expires for up to one additional year. Under the new three-year credit facility, PGE has the option to use up to $100 million in letters of credit. The new agr eements provide for borrowings at a variable interest rate and require annual facility fees based on the Company's unsecured credit rating. In addition, the agreements provide for termination of the banks' obligation, and the full repayment of any outstanding balances, in the event of the sale of the Company's common stock to Oregon Electric or other changes in control (as defined in the agreements). The new facilities allow PGE to pay cash dividends on common stock, subject to certain restrictions.

The remaining $5 million of 8 1/4% Junior Subordinated Deferrable Interest Debentures, Series A, due December 31, 2035, were redeemed on June 30, 2004. Pursuant to this redemption, PGE filed on June 30, 2004 to terminate registration of these securities under the Securities Exchange Act of 1934. The Company has de-listed from the New York Stock Exchange and is no longer listed on any stock exchange.

Operations - During the first half of 2004, PGE continued to serve its customers effectively and operate well, with earnings more typical of the Company's historical levels than in the first half of 2003. Although PGE's financial performance continues to be challenged by poor hydro conditions, 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 a reduced impact on the Company's future earnings. PGE continues to maintain investment-grade ratings on its secured debt, has adequate liquidity, and stable operating cash flow.

Retail loads in 2004 continue to run somewhat below both current year projections and last year's first half due to warmer-than-normal weather. The loss of two large industrial customers since the first half of 2003 also contributed to the decrease in retail load. On a weather-adjusted basis, however, retail energy sales approximated that of last year's first half.

Restoration and cleanup efforts required by January's snow and ice storm have been largely completed, with insurance recovery substantially offsetting related costs. PGE's response to such service outages continues to have a positive effect on customer satisfaction. A new five-year agreement with the Company's bargaining unit employees provides improved wages, retirement, and health benefits, as well as stability for both union employees and the Company. Recent changes to PGE's management structure reflect recognition of the critical importance of customer service and satisfaction to the future growth and success of the Company.

PGE continues to oppose recent efforts by public power proponents to acquire Company service territory and is pleased with the continued support of its communities demonstrated by the rejection of PUD initiatives in Multnomah, Yamhill, and Clackamas Counties in the last nine months.

Economy - Oregon's economy continues to show signs of steady improvement. Modest payroll gains earlier this year have accelerated, with over 21,000 seasonally-adjusted non-farm jobs (including 1,600 in manufacturing) added in this year's second quarter. Nearly 40,000 jobs have been added by the state's employers since June of last year, notably in the high tech and manufacturing sectors, resulting in a 2.5% increase in non-farm payroll. The seasonally-adjusted unemployment rate has fallen from a high of 8.7% in July 2003 to 6.9% in June 2004 as the state continues its recovery from the recession. PGE continues to experience customer growth, adding about 10,000 retail customers in the first half of this year, and is working proactively to promote economic growth and business development in the region.

Power Supply - Despite heavy snowfall early in the year, regional hydro conditions have deteriorated significantly from initial forecasts due to reduced precipitation and generally dry conditions since February. 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 hydro plants continue to serve as a reliable low-cost resource, providing economical power for customers. Recently completed efficiency upgrades to the Boardman coal plant, accomplished during an extended maintenance outage, are expected to increase PGE's share of the plant's generation by 21 MW with no additional fuel requirements. In conjunction with a 50-year relicensing application for the Pelton Round Butte hydro project, a settlement agreement, which includes provisions for fish passage over the project's dams, was completed and signed by all participants in July and submitted to the FERC for approval. During the first half of 2004, PGE effectively utilized its generating assets and position in the wholesale marketplace to meet load requirements and partially offset the adverse financial effects of poor regional hydro conditions.

In April 2004, PGE submitted a preliminary "Resource Valuation Mechanism" (RVM) filing to the OPUC, containing an estimate of 2005 power costs. Under the RVM process, retail rates are adjusted annually with changes in projected power costs. The Company continues to update its forecast of 2005 power costs, which will be finalized by mid-November. The preliminary filing and subsequent updates indicate a moderate retail rate increase beginning January 1 of next year.

PGE has withdrawn its hydro cost deferral applications covering the current year that were filed with the OPUC in December 2003 and May 2004. A procedural schedule has been adopted for further consideration by the Commission of a proposed Hydro Generation Adjustment mechanism and tariff which would allow rate adjustments reflecting changes in power costs caused by variations in hydro conditions. Any deferral of costs, for future recovery or refund, would begin only upon approval of the proposed tariff. A decision is expected in early 2005.

In July 2004, the OPUC acknowledged PGE's Integrated Resource Final Action Plan. The plan contains 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. In late May, PGE entered into a ten-year power purchase agreement for 85 average MW, beginning in late 2006, and has also entered into two five-year agreements, for 14 average MW and 25 average MW, beginning in early 2005 and late 2006, respectively. These agreements, the first results from last year's request for proposals issued as part of the Integrated Resource Plan, provide competitive and reliable sources of supply for PGE customers.

Proposed Sale of PGE - The proposed sale of PGE by Enron to Oregon Electric continues to move through the regulatory hearing and approval process. Oregon Electric is leading the required legal and regulatory process and continues to provide information and testimony. The OPUC is conducting its formal process, following a schedule that includes public information and input meetings and also provides for the exchange of proposals to ensure that the proposed transaction provides net benefits to retail customers. PGE management believes the proposed transaction represents the best possible outcome for the Company and is 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 second quarter of 2004 was $22 million, compared to $13 million in the second quarter of 2003. The increase was due primarily to improved margins on energy sales resulting from economic decisions related to the utilization of the Company's thermal generating assets and activities in the wholesale marketplace. In addition, last year's second quarter reflects a disallowance by the OPUC of certain power purchase contracts in rates charged to customers. These factors more than offset the impact from a reduction in retail energy sales during the quarter.

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

Retail revenues decreased by approximately 2% from the second quarter of last year due primarily to lower energy sales. Retail energy sales decreased about 6.6% due largely to a 25% decline in industrial sales, most of which was attributable to two large customers, one of which began generating its own power requirements in May of 2003, with the other now served by an ESS. The decrease in revenue from these two customers approximated $9 million, including about $4 million attributable to the customer now served by an ESS. Total residential and commercial energy sales were unchanged from last year's second quarter, as decreased residential sales, attributable primarily to warmer weather in April and May, were offset by an increase in commercial sales. An approximate 10,800 increase in average customers served in this year's second quarter, as well as an approximate 0.4% average rate increase for 2004, largely offset the effect of warmer weather. (See "Retail Rate Changes" in the Fina ncial and Operating Outlook section for further information).

Wholesale revenues and energy sales for the second quarter of 2004 reflect reductions of $70 million and 1,806 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 the effect of the change on prior year reported revenues and expenses is not practicable, the change has no impact on reported net income.

The increase in Other Operating Revenues from last year's second quarter was primarily attributable to the sale of transmission capacity in excess of the Company's needs.

Purchased Power and Fuel expense for the second quarter of 2004 reflects a reduction of $70 million related to the adoption of EITF 03-11 (described above). The remaining $32 million decrease from last year's second quarter is attributable to a reduction in power purchased to meet a lower total system load requirement. Partially offsetting the effect of a decrease in system load was an approximate 1% increase in PGE's average variable power cost for the quarter, with a higher average cost of Company generation partially offset by a lower average cost of purchased power. The average price of purchased power decreased approximately 4%, with a 7% decrease in the average price of firm power purchases partially offset by higher spot market prices. Company generation was unchanged from that of last year's second quarter, as a 35% decrease in coal-fired generation (due primarily to the Boardman plant's extended maintenance outage) was largely offset by increases in combustion turbine ge neration and PGE hydro production, which increased approximately 1% from last year's second quarter. Total generation met approximately 32% of PGE's retail load during the second quarter of 2004, compared to 30% last year.

The following table indicates PGE's total system load (including both retail and wholesale but excluding energy trading contracts) for the second quarter of 2004 and 2003.

(*includes wheeling costs)

Production, distribution, administrative and other expenses increased $5 million (8%) from the second quarter of 2003 due primarily to increased costs related to an extended maintenance outage at the Boardman coal plant during this year's second quarter. Increases in both employee benefit expenses (including medical and pension costs) and customer service and support expenses were largely offset by reduced corporate overhead charges from Enron.

Depreciation and Amortization expense increased $4 million (8%), 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 due to normal property additions.

Income taxes increased $5 million primarily due to higher taxable income.

Other Income decreased $3 million, due primarily to reductions in both interest income on regulatory assets and income from non-qualified benefit plan trust assets.

Interest Charges decreased $2 million (10%) due to both a lower level of outstanding long-term debt in this year's second quarter and to the replacement of higher rate debt in the second half of 2003.

PGE's net income in the first half of 2004 was $54 million, compared to $34 million in the first half of 2003. Results for the first half 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 increase in net income in this year's first half was due primarily to improved margins on energy sales resulting from economic decisions related to the utilization of the Company's thermal generating assets and activities in the wholesale marketplace. The increase in margin is also partly attributable to a decrease in provisions for uncollectible accounts receivable for wholesale electricity sales, primarily related to prior year sales in the California market. In addition, last year's first half margin reflects a disallowance by the OPUC of certain power purchase contracts in rates charged customers. These factors more than offset the impact from a reduction in retail energy sales during the first half of this year.

The following table summarizes Operating Revenues and Energy Sales for the six-month periods ending June 30, 2004 and 2003: