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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 PGE's opinion that, when the interim statements are read in conjunction with the 2001 Annual Report on Form 10-K and the other reports filed with the Securities and Exchange Commission since its 2001 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 engages in non-trading and trading activities by utilizing derivative financial instruments in its electric utility business. Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), which the Company adopted on January 1, 2001, derivative instruments are recorded on the Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings (in Purchased power and fuel), unless specific hedge accounting criteria are met. As contracts settle, sales are recorded in Operating revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel on the Statement of Income. Upon adoption of SFAS No. 133, PGE recorded after-tax gains of $11 million and $35 million in earnings and Other Comprehensive Income (OCI), respectively, from the cumulative effect of a change in accounting principle.

Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. As discussed below, the effects of changes in the fair value of derivative instruments entered into to hedge the company's future retail resource requirements are subject to regulation and are deferred pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

As PGE's primary business is to serve its retail customers, it enters into derivative instruments, including electricity forward and option, and natural gas forward and swap contracts to manage its exposure to commodity price risk and endeavor to minimize net power costs for customers. Effective October 1, 2001, PGE's base rates changed as a result of an OPUC general rate order. The new rates reflect an update of PGE's net variable power costs to include electricity and natural gas contracts that will settle over the 15-month period ended December 31, 2002. In addition, the OPUC approved a 15-month power cost adjustment mechanism, effective October 1, 2001, to mitigate the Company's exposure to risk from power and natural gas price volatility. Such mechanism provides an incentive for the Company to continue to actively manage resources it has procured to serve its retail load and reduce retail power costs over the 15-month period October 1, 2001 to December 31, 2002. The mechanism provides that PGE recover from or refund to customers a portion of the difference in changes in power costs and energy revenues from baseline amounts as a result of continuing management of its resources and changes in the forecasted load. At the end of 2002, any balance for collection or refund will be subject to OPUC approval. Each year thereafter, PGE will provide updates of its net variable power costs to the OPUC for inclusion in base rates for the following year.

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. OPUC-approved rates are based on the value of all the Company's resources, including derivative instruments that will settle during the 15-month period from October 1, 2001 to December 31, 2002. The timing difference between the recognition of gains and losses on 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 a result, in the third quarter of 2001 PGE began recording a regulatory asset or regulatory liability pursuant to SFAS No. 71 to offset the effects of unrealized gains and losses from changes in fair values of these contracts recorded prior to settlement. As contracts are settled, the regulatory asset or regulatory lia bility is reversed. PGE recorded in the first half of 2002 and 2001, net unrealized gains of $1 million and $6 million, respectively in earnings on natural gas swaps in its retail portfolio, including net gains of $5 million and $7 million in the second quarter of 2002 and 2001. The 2002 gains were fully offset by the recording of a SFAS No. 71 regulatory liability.

Derivative activities in OCI for the three- and six-month periods ended June 30, 2002 from cash flow hedges consist of $6 million net unrealized losses and $3 million net unrealized gains, respectively, that were fully offset by the recording of a SFAS No. 71 regulatory liability. For the comparative three- and six-month periods ended June 30, 2001, $75 million and $67 million net unrealized losses, respectively, in new contracts and changes in fair values were recognized in OCI; in addition, $4 million and $17 million net gains, respectively, were reclassified to earnings from OCI for contracts that settled during the 2001 periods. No amounts were reclassified into earnings as a result of hedge ineffectiveness in the first half of 2002 or 2001. Cash flow hedges of zero and $7 million losses were discontinued and reversed to Purchased power and fuel during the first half of 2002 and 2001, respectively, due to the probability that the original forecasted transactions will not occur. As of J une 30, 2002, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 21 months. The Company estimates that of the $1 million of net unrealized gains at June 30, 2002, a $1 million loss will be reclassified into earnings within the next twelve months, with a $2 million gain to be reclassified over the remaining other nine months.

New Accounting Guidance - On December 19, 2001, the FASB approved the interpretations issued by the Derivatives Implementation Group (DIG) that are outlined in SFAS No. 133 Implementation Issues No. 15, Scope Exceptions: Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, and No. C16, Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract. Under Issue No. C15, the FASB included "clearly and closely related" pricing requirements for contracts to qualify for the normal purchases and normal sales exception. Issue No. C16 disallows normal purchases and normal sales treatment for commodity contracts (except as provided in Issue No. C15 with respect to certain power purchase or sales agreements) that contain volumetric variability or optionality. Such interpretations and guidance became effective April 1, 2002. PGE determined that there was no material impact of implementing this guidance on its financial statements.

PGE trading activities utilize electricity forward and option contracts and natural gas forward, swap and futures contracts to take advantage of price movements in electricity and natural gas. Such activities are not subject to regulation. In the first half of 2002, PGE recorded in earnings $2 million in unrealized losses that were offset by $2 million in realized gains from trading activities. In the first half of 2001, PGE recorded in earnings an $11 million loss from trading activities, comprised of $27 million in unrealized gains and $38 million in realized losses. In the second quarter of 2002, PGE recorded in earnings $1 million in realized gains from trading activities, with unrealized gains and losses netting to zero. In the second quarter of 2001, PGE recorded in earnings an $11 million loss from trading activities, comprised of $14 million in unrealized gains and $25 million in realized losses.

Emerging Issues Task Force Issue - The Emerging Issues Task Force (EITF) of the FASB recently reached a consensus in Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, regarding financial statement presentation of revenues and expenses associated with "energy trading contracts". The EITF requires that, effective for the third quarter of 2002, such revenues and expenses be reported on a net basis for all periods presented. PGE has historically presented such activities on a gross basis as contracts are settled, with sales recorded in Operating revenues and power purchases recorded in Purchased power and fuel expense.

PGE continues to evaluate the financial statement reclassification required by EITF Issue No. 02-3. PGE believes that implementation of the consensus in EITF Issue No. 02-3 will likely have a material impact on total revenues and expenses, but will have no impact on its financial condition or results of operations.

On May 17, 2002, Enron and NW Natural entered into a Termination Agreement in which they agreed to terminate the Stock Purchase Agreement to sell PGE to NW Natural. The Termination Agreement was subject to, and effective upon, approval of the Bankruptcy Court and the consent of the lenders from whom Enron has obtained debtor-in-possession financing, both of which have been obtained. The Termination Agreement also provides for mutual releases from any legal action associated with the Stock Purchase Agreement.

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

Numerous challenges, appeals and requested reviews have been filed in Marion County, Oregon Circuit Court, Oregon Court of Appeals and with 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 are the Citizens' Utility Board (CUB) and the Utility Reform Project (URP). Rulings issued to date by the Circuit Court and the Court of Appeals have been inconsistent on the issue. The Court of Appeals issued the latest ruling in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upheld the OPUC's authorization of PGE's recovery of the Trojan investment. 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 investmen t issue. The Supreme Court has indicated it will conduct a review.

In 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of its investment in the Trojan plant. Under the agreements, CUB agreed to withdraw from the litigation and support the settlement as the means to resolve the Trojan litigation. The settlement, which was approved by the OPUC, 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 about $80 million of the remaining obligation under terms of the Enron/PGC merger. The settlement also allows PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had been flowed through to customers in prior years; such amount is being recovered from PGE customers, with no return on the unamortized balance, over an approximate five year period. 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. The URP challenged the settlement agreements and the OPUC order. Collection of decommissioning costs at Trojan is unaffected by the settlement agreements or the OPUC order.

PGE had requested the Oregon Supreme Court to hold in abeyance its review of the Court of Appeals decision pending resolution of URP's complaint with the OPUC challenging PGE's application for approval of the accounting and ratemaking elements of the settlement agreements approved by the Commission on September 29, 2000. On March 25, 2002, the OPUC issued an order denying all of URP's challenges, and approving PGE's application of the accounting and ratemaking elements of the settlement. On July 1, 2002, PGE filed with the Oregon Supreme Court a Notice of Mootness and Motion to Dismiss and Vacate the Case.

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

Union Grievances - Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enron, n ot PGE. The IBEW filed an answer and counterclaim that the issue is arbitrable, and PGE filed a reply which denied the counterclaim and raised four affirmative defenses. It is not likely that a hearing on these motions and counterclaim will take place before the fall of 2002. No reserves have been established by PGE for any amounts related to this issue.

Other Legal Matters - PGE is party to various other claims, legal actions and complaints arising in the ordinary course of business. These claims are not material.

Environmental Matter - A 1997 investigation of a 5.5 mile segment of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Based upon analytical results of the investigation, the EPA included the Portland Harbor on the federal National Priority list pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act ("Superfund") in 2000.

In 1999, the DEQ asked that PGE perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000 the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement. Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.

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

In February 2002, PGE submitted a report to the DEQ summarizing its pre-remedial investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette River because no likely sources of hazardous substance releases were identified. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign such order. Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE.

Although management does not believe it has any responsibility for contamination of the Portland Harbor, it cannot predict the ultimate outcome of this matter or estimate any possible loss.

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

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

Enron suspended its monthly payments to PGE in September 2001, pursuant to its Stock Purchase Agreement with NW Natural, under which NW Natural was to have assumed Enron's merger payment obligation upon its purchase of PGE. The Stock Purchase Agreement was terminated on May 17, 2002. At June 30, 2002, Enron owed PGE approximately $77 million, including accrued interest. The realization of the Merger Receivable from Enron is uncertain at this time due to Enron's bankruptcy. Based on this uncertainty, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001. For further information, see Note 8, Enron Bankruptcy.

Income Taxes Receivable - As a member of Enron's consolidated income tax return, PGE made income tax payments to Enron for PGE's income tax liabilities. The $4 million balance at June 30, 2002 represents a receivable from Enron for refunds of prior income taxes paid by PGE.

Intercompany Receivables and Payable - As part of its ongoing operations, PGE bills affiliates for various services provided. These include services provided by PGE employees along with other corporate governance services and are billed at the higher of cost or market. Also, PGE is billed for services received at the lower of cost or market, primarily for employee benefit plans and corporate overhead costs. All affiliated interest transactions with PGE are subject to approval of the OPUC and are described below.

Enron - PGE receives management services from Enron and provides incidental services to Enron. In the first six months of 2002, Enron billed PGE approximately $5 million for retirement savings plan matching and medical and dental benefits and an additional $6 million for corporate overhead costs. For the same period in 2001, Enron billed PGE $14 million for allocated overhead and other direct costs, comprised of $4 million for retirement savings plan matching, $3 million for medical and dental benefits, and $7 million for corporate overhead costs.

Intercompany payables to Enron were paid by PGE until Enron filed for bankruptcy in early December 2001. PGE has since stopped making payments to Enron, except those for employee benefit plans, pending the ultimate disposition of payables to and receivables from Enron resulting from Enron's bankruptcy proceedings. The $11 million payable to Enron at June 30, 2002 consisted primarily of corporate overhead costs.

In 2001, PGE received $3 million from Enron for expenses related to the proposed merger with Sierra Pacific Resources.

Other Enron Subsidiaries - In 2001, PGE provided services and sublease of office space to other Enron subsidiaries, including Enron Broadband Services, Inc. and Enron North America Corp. (ENA). PGE purchased and sold electricity and transmission services to Enron Power Marketing, Inc. (EPMI), a subsidiary of ENA. Under these transactions with EPMI, the purchases and sales of energy were primarily for like quantities and hours. PGE purchased power at prices no higher than the Dow Jones Mid-Columbia Index and charged at prices at or higher than the Dow Jones Mid-Columbia Index. In 2002, PGE is no longer purchasing and selling electricity with EPMI; however, PGE continues to provide transmission services. As of February 2002, PGE is no longer subleasing office space to ENA due to the sale of ENA's trading operations. For the first six months of 2002, PGE billed EPMI $1 million for transmission services, which have been paid by EPMI. At June 30, 2002, PGE is owed $1 million by EPMI for power and transmission services provided in 2001.

Portland General Holdings and Subsidiaries - Portland General Holdings (PGH) is a wholly owned subsidiary of Enron. Prior to Enron's bankruptcy, Enron had provided a portion of the funding for operations of PGH and its subsidiaries. With Enron's bankruptcy, any future funding from Enron will be subject to approval by Enron, and must be in compliance with the Order of the Bankruptcy Court Authorizing Continued Use Of Existing Bank Accounts, Cash Management System, Checks and Business Forms dated December 3, 2001, as amended on February 25, 2002 (the "Cash Order"). PGH and its subsidiaries are not part of Enron's bankruptcy proceedings. At June 30, 2002, PGE has an outstanding receivable balance from PGH and its subsidiaries of $35 million, comprised of $30 million related to non-regulated asset sales, $4 million related to PGH employee benefit plans, and $1 million for employee services and other corporate governance services. In June 2002, Enron loaned PGH $475 thousand to fu nd current operating activities, in compliance with the Cash Order.

In 1999, PGE transferred $21 million of corporate owned life insurance policies to PGH, creating a receivable balance due PGE. PGH transferred these policies to a trust for non-qualified benefit plan obligations, leaving a receivable balance due PGE. Later in 1999, PGH recorded a capital transaction with its wholly owned subsidiary PGH II, Inc. (PGH2), transferring the $21 million PGE intercompany payable to PGH2. PGH retained the trust owned life insurance policies in this transaction. The transfer to PGH2 was the result of negotiations between Enron and Sierra Pacific Resources related to the proposed sale of PGE and PGH2 to Sierra (the sale of which was later terminated). In the proposed sale of PGE and PGH2 to NW Natural, the PGE intercompany payable was also to have been assumed by NW Natural. In June 2002, due to the termination of the sale agreement with NW Natural, the PGE intercompany payable was transferred back to PGH. Due to the effects of both the termination of the sale agree ment with NW Natural and the complexities of the Enron bankruptcy on the length of time to collect this receivable balance from PGH, PGE's board of directors on July 25, 2002 approved the transfer of the intercompany receivable at PGE to Enron in the form of a non-cash dividend. As of June 30, 2002, the balance due PGE from PGH was $27 million, including accrued interest.

PGH2 is the parent company of various subsidiaries that receive services from PGE. These include Portland General Distribution Company and Portland General Broadband Wireless (telecommunications companies), Microclimates, Inc. (a project management company), and Portland Energy Solutions (PES), which provides cooling services to buildings in downtown Portland, Oregon. For the first six months of 2002, PGE billed PGH and its subsidiaries $1 million for various employee services and corporate governance services. At June 30, 2002, PGE has a $3 million receivable balance from Portland General Distribution Company related to assets sold for a capital project and for employee services provided by PGE.

PGE has entered into a one-year revolving credit agreement to loan PES $2 million. The agreement, approved by the OPUC, expires on April 1, 2003. Under the agreement, PGE will advance funds to PES to complete a district cooling system project, with advances to accrue interest at 16% per annum. The OPUC order further provides that interest paid by PES to PGE in excess of PGE's authorized cost of capital (9.083%) be deferred for refund to customers. PGE also has a security interest in certain contracts and equipment related to the project. As of June 30, 2002, no funds have been advanced by PGE under the agreement.

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

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

Interest Income and Expense - Interest is accrued on the Enron Merger Receivable balance at PGE's current authorized cost of capital (9.083%) and is being fully reserved, as discussed above. Receivable balances from PGH and its subsidiaries accrue interest at 9.5%. Prior to 2001, interest was accrued at 9.5% on other outstanding receivable and payable balances with Enron and its other subsidiaries. Beginning in 2001, interest was no longer accrued on those other outstanding balances with Enron due to the proposed merger with Sierra Pacific Resources. Although the proposed merger was terminated in April 2001, interest accrual has not resumed.

Management Assessment - Due to Enron's bankruptcy, management cannot predict the ultimate outcome of the above matters and the realization of its receivables. In particular, the collectibility of the $77 million Enron Merger Receivable would be uncertain under Enron's bankruptcy proceedings. As a result, the Company has established a reserve for the entire amount of this receivable, of which $74 million was recorded in December 2001. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve was established in December 2001 for the entire $5 million remaining balance of such receivables.

As of August 1, 2002, PGE has accounts receivable totaling approximately $74 million that may be affected by the financial condition of two California utilities. Remaining payments totaling approximately $11 million (including imputed interest at 6.79%) are owed by Southern California Edison Company (SCE) under terms of a 1996 agreement providing for the termination of a Power Sales Agreement between the two companies. SCE has made its scheduled monthly payments under the termination agreement, with the final payment due in December 2002. In addition, a balance of approximately $63 million is currently owed the Company by 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 SCE and Pacific Gas & Electric Company (PG&E).

On March 9, 2001, the PX filed for bankruptcy, and on April 6, 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, PG&E retains control of its assets and is authorized to operate its business as a debtor in possession while subject to the jurisdiction of the Bankruptcy Court.

PGE is pursuing collection of all past due amounts. Management continues to assess PGE's exposure relative to its California receivables and has established a credit reserve for amounts due under its wholesale electricity contracts.

The Company has retained legal counsel on the bankruptcy matters and has numerous options, including legal, regulatory, and other means to pursue collection of amounts ultimately not received. Due to uncertainties surrounding both the bankruptcy filings and regulatory reviews of sales made during this time period, management cannot predict the ultimate realization of these receivables.

Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations for future reporting periods.

In a June 19, 2001 FERC order adopting a price mitigation program for 11 states within the WSCC area, the issue of refunds for spot market sales made between October 2, 2000 through June 20, 2001 was referred to a settlement judge.

On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds related to non federally-mandated transactions in the spot markets operated by the ISO and the PX. In addition, an evidentiary hearing proceeding was ordered to develop a factual record to provide the basis for the refund calculation. The Company's potential refund obligation, using the FERC methodology, is currently estimated to be in the range of $20 million to $30 million, with final determination to be made after FERC review of calculations filed by the ISO. Hearings were held in March 2002, with additional hearings scheduled for August 2002. PGE will have the opportunity to challenge the FERC's determination of the amount of any proposed refunds.

In the July 25, 2001 order, the FERC 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. Upon completion of hearings, the appointed Administrative Law Judge issued a recommended order that the claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action.

Several of the complainants in this case have filed motions to reopen the hearing. Those motions are also awaiting Commission action.

Any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism. This could potentially mitigate the financial effect of any refunds made or received by the Company. In addition, PGE believes that any refunds related to California sales that may be required by the FERC can be offset by accounts receivable related to sales in California (as discussed in Note 6, Receivables - California Wholesale Market).

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

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 filing.

On May 3, 2002, Enron presented to its creditors committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of PGE in the new company would be subject to potential sale to a different buyer under a Section 363 auction process, which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the creditors committee and is one of many options Enron may pursue. There can be no assurance as to whether PGE would ultimately be included in a new company or separately sold to a bidder in a Section 363 auction. Until this process results in a filing with the Bankruptcy Court, management will not know the role of PGE in the proposed structure and cannot assess the impact on PGE's business and operations.

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

Management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day-to-day operations. Regulatory and contractual protections restrict Enron access to PGE assets. Under Oregon law and specific conditions imposed on Enron and PGE by the OPUC in connection with Enron's acquisition of PGE in the merger of Enron and Portland General Corporation in 1997 (the merger conditions), Enron's access to PGE cash or assets (through dividends or otherwise) is limited. Under the merger conditions, PGE cannot make any distribution to Enron that would cause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approva l. The merger conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings. PGE maintains its own cash management system and finances itself separately from Enron, on both a short-term and long-term basis.

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

1. Amounts Due from Enron and Enron-Supported Affiliates - As described in Note 5, Related Party Transactions, PGE is owed approximately $77 million from Enron relating to the Merger Receivable (including interest accrued to June 30, 2002). Because of uncertainties associated with Enron's bankruptcy, PGE has established a reserve for the full amount of this receivable, of which $74 million was recorded in December 2001. In addition, due to uncertainties associated with other receivable balances from Enron and its subsidiary companies which are part of the bankruptcy proceedings, a credit reserve was established in December 2001 for the entire $5 million remaining balance of such receivables.

2. For years 1996-1999, Enron and its subsidiaries generated substantial net operating losses (NOLs). For 2000, Enron and its subsidiaries paid an alternative minimum tax. Enron and its subsidiaries anticipate that the 2001 consolidated tax return will show a substantial loss, which would be carried back to tax year 2000, and is anticipated to result in a tax refund for taxes paid in 2000. The carryback of the 2001 loss to 2000 is expected to provide Enron and its subsidiaries substantial NOLs for any additional income tax liabilities that may result from the ongoing IRS audit for the periods in which PGE was a member of Enron's consolidated federal income tax returns. The last day that the IRS can file a proof of claim for prepetition taxes in the bankruptcy case is March 31, 2003. It is anticipated that the IRS will file a proof of claim through 2001 prior to that date. If there were additional tax liabilities claimed by the IRS, these would be satisfied by funds in the bankruptcy estat e ahead of unsecured Enron creditors.

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

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

PGE entered into a new $72 million 364-day revolving credit facility with a group of commercial banks, replacing a $200 million credit facility that expired on June 12, 2002. Under the new credit facility, PGE has the option to issue letters of credit, in addition to borrowings, totaling up to the $72 million. This new facility, along with an existing $150 million revolving credit facility (which expires in June 2003), provides total available liquidity to PGE of $222 million. Both facilities are secured by First Mortgage Bonds issued by the Company.

SFAS No. 143, Accounting for Asset Retirement Obligations, requires the recognition, as an Asset Retirement Obligation (ARO), of a liability for dismantlement and restoration costs associated with the retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition, the probability weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized amount of the related long-lived assets. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the income statement. PGE is required to comply with SFAS No. 143 beginning January 1, 2003 and is currently evaluating the impact of SFAS No. 143 to its tangible long-lived assets, substantially all of which are included in rate-regulated operations.

SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, requires the recognition of a liability for costs related to exit or disposal activities when the costs are incurred. Previous accounting guidance required the liability to be recorded at the date of commitment to an exit or disposal plan. PGE is required to comply with SFAS No. 146 beginning January 1, 2003. PGE does not expect the adoption of SFAS No. 146 to have an effect on its financial statements.

The following review of PGE's results of operations should be read in conjunction with the consolidated financial statements. 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 2002.

PGE's net income in the second quarter of 2002 was $16 million, compared to $29 million in the second quarter of 2001. The $13 million decrease was due primarily to reduced margins on energy sales. A slowed economy and conservation efforts combined to reduce retail energy sales from last year's second quarter. Lower wholesale prices further reduced operating margins as excess power purchased under forward contracts at higher prevailing market prices was sold in the wholesale market.

Total operating revenues decreased $278 million (33%) compared to the second quarter of 2001 due to significantly lower prices for energy sold in the wholesale market. Wholesale revenues decreased $371 million (from $587 million to $216 million), as prices dropped 86% from last year's second quarter due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale sales volume increased 158% as PGE sold on the wholesale market excess power purchased; last year, such purchases were used to replace lower hydro generation to meet second quarter retail load requirements. Retail revenues increased $102 million primarily due to a general rate increase that became effective October 1, 2001; energy sales decreased 4% as a slowing economy and conservation more than offset an approximate 10,000 (1.4%) increase in total customers from the end of last year's second quarter. O ther operating revenues decreased $8 million primarily due to lower prices for sales of natural gas in excess of generating plant requirements.

Purchased power and fuel costs decreased $253 million primarily due to significantly lower energy prices. Lower regional power and natural gas prices resulted in a 70% drop in the average cost of firm power purchases from last year's second quarter. Combined with lower prices for spot market purchases and a 60% decrease in thermal generation, PGE's average variable power cost was 36% of last year's second quarter (for further information, see "Power

Supply" in the Financial and Operating Outlook section). Partially offsetting the effect of the average cost decrease was a 59% increase in total system load resulting from higher wholesale energy sales.

PGE energy generation decreased 49% from last year's second quarter due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance outages at the Company's coal fired generating plants. Improved hydro conditions resulted in energy production approximately equal to that of 2001's second quarter despite the loss in generation attributable to the January 1, 2002 sale of a portion of the Company's interest in the Pelton Round Butte project. Total Company generation met approximately 31% of PGE's retail load during the second quarter, compared to 59% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the second quarters of 2002 and 2001. Average variable power costs exclude the effect of PGE's power cost mechanisms on purchased power and fuel costs.

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) decreased $8 million (11%). Production expenses decreased by $4 million, due primarily to the termination of fees previously paid to the Confederated Tribes of Warm Springs related to the operation of PGE's Pelton Round Butte hydroelectric project, a 33.33% interest in which was sold to the Tribes in January 2002. In addition, lower maintenance costs were incurred at the Company's thermal generating plants. Corporate overhead expenses, including certain employee benefit costs, decreased $5 million, due partially to the timing of allocated overhead costs from Enron, which in 2001 were not recorded until the second quarter due to the proposed sale of PGE to Sierra Pacific Resources (which sale was later terminated). Increased provision for uncollectible customer accounts partially offset the decrease in corporate overhead costs.

Depreciation and amortization expense decreased $2 million. Increased amortization of regulatory liabilities, related to various refunds to customers, was partially offset by an increase in depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's recent general rate case.

Income taxes decreased $4 million (19%) due to lower taxable income.

Other income decreased $7 million, caused by a $4 million loss in the market value of trust owned life insurance assets, a $2 million reserve for interest accrued on the Merger Receivable from Enron in the second quarter, and a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company. Partially offsetting these items was increased interest on regulatory assets, including the deferred Power Cost Adjustment.

PGE's net income in the first half of 2002 was $52 million, compared to $72 million in the first half of 2001. Last year's first half results include the $11 million cumulative effect of a change in accounting principle resulting from the adoption of SFAS No. 133 on January 1, 2001. The $9 million decrease in net income before the effect of the accounting change was due primarily to reduced margins on energy sales. A slowed economy and conservation efforts combined to reduce retail energy sales from last year's first half. Lower wholesale prices in this year's first half further reduced operating margins as excess power purchased under forward contracts at higher prevailing market prices was sold in the wholesale market.

Total operating revenues decreased $504 million (32%) compared to the first half of 2001 due to significantly lower prices for energy sold in the wholesale market. Wholesale revenues decreased $715 million (from $1,067 million to $352 million), as prices dropped 84% from last year's first half due to market forces within the region, including the effects of improved hydro conditions, lower natural gas prices, conservation, and a reduction in demand due to a slowing economy. Wholesale sales volume approximately doubled as PGE sold on the wholesale market excess power purchased; during the first half of last year, such purchases were used to replace lower hydro generation to meet retail load requirements. Retail revenues increased $231 million primarily due to a general rate increase that became effective October 1, 2001; energy sales decreased 4% as a slowing economy and conservation more than offset an approximate 10,000 (1.4%) increase in total customers from the end of last year's first half. Other operating revenues decreased $19 million due primarily to lower prices for sales of natural gas in excess of generating plant requirements.

Purchased power and fuel costs decreased $498 million due primarily to significantly lower energy prices. Due to both lower regional power and natural gas prices, the average cost of firm power purchases dropped over 62% from last year's first half. Combined with lower prices for spot market purchases and a 48% decrease in thermal generation, PGE's average variable power cost was 56% of last year's first half (for further information, see "Power Supply" in the Financial and Operating Outlook section). Partially offsetting the average cost decrease was a 34% increase in total system load resulting from higher wholesale energy sales. Purchased power and fuel costs in the first half of 2002 includes a credit of approximately $23 million related to the Company's power cost mechanisms, in which a portion of the Power Cost Variance is deferred for future recovery from customers. (See "Power Cost Mechanisms" in the Financial and Operating Outlook section for further information).

PGE energy generation decreased 39% from last year's first half due to both planned maintenance and economic displacement of combustion turbine generation and planned maintenance and forced repair outages at the Company's coal fired generating plants. Improved hydro conditions resulted in energy production approximately equal to that of 2001's first half despite the loss in generation attributable to the January 1, 2002 sale of a portion of the Company's interest in the Pelton Round Butte project. Total Company generation met approximately 37% of PGE's retail load during the first half of 2002, compared to 59% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the first half of 2002 and 2001. Average variable power costs exclude the effect of 2002 credits to purchased power and fuel costs related to PGE's power cost mechanisms, as discussed above.

Operating expenses (excluding purchased power and fuel, depreciation and amortization, and taxes) increased $6 million (5%). Production and distribution expenses were unchanged as higher delivery system costs were offset by lower plant maintenance expenses and the termination of fees to the Confederated Tribes of Warm Springs. (Such fees related to the Pelton Round Butte hydroelectric project, a 33.33% interest in which was sold to the Tribes in January 2002). Expenditures for energy efficiency, including an expanded program encouraging use of compact fluorescent lighting, and increased provisions for uncollectible customer accounts, were partially offset by lower corporate overhead expenses, including certain employee benefit costs.

Depreciation and amortization expense decreased $5 million. Increased amortization of regulatory liabilities, related to various refunds to customers, was partially offset by an increase in depreciation of utility plant, due to both normal property additions and higher depreciation rates established in the Company's recent general rate case.

Taxes other than income taxes increased $2 million primarily due to higher franchise fees resulting from increased retail revenue.

Other income decreased $3 million, caused by a $3 million reserve for interest accrued on the Merger Receivable from Enron in the first half of 2002, a $3 million decrease in the allowance for equity funds used during construction (AFDC), a $2 million provision to reflect a decrease in the estimated net realizable value of a gas turbine currently held for sale by the Company, and the $1 million write-off of certain non-utility investments. These were partially offset by a $2 million increase in the market value of trust owned life insurance assets and a $4 million increase in interest on regulatory assets, including the deferred Power Cost Adjustment.

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.

A significant portion of cash from operations comes from depreciation and amortization of utility plant, charges which are recovered in customer revenues but require no current cash outlay. Changes in accounts receivable and accounts payable can also be significant contributors or users of cash.

Cash provided by operating activities totaled $164 million in the first half of 2002 compared to $110 million used in the same period last year. The increase is due primarily to a $252 million net decrease in cash collateral deposits made with certain wholesale customers, related to the settlement of certain energy contracts, and an increase in payments received from wholesale electricity sales.

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. A $31 million reduction in capital expenditures in the first half of 2002 is primarily attributable to reduced expenditures for transmission substation and distribution line construction activities. In addition, costs in the first half of 2001 include $6 million related to a new 24.5 megawatt combustion turbine unit at the Beaver plant site.

Financing Activities provide supplemental cash for day-to-day operations and capital requirements as needed. PGE currently relies on short-term bank loans and cash from operations to manage its day-to-day financing requirements. During the first half of 2002, the Company reduced its short-term borrowings by $39 million, as it repaid $129 million in outstanding commercial paper and borrowed $90 million under its committed credit lines. In addition, PGE paid $15 million in matured First Mortgage Bonds and $4 million of conservation bonds, retired $2 million of preferred stock, and paid $1 million in preferred stock dividends. No common stock dividends were declared in the first half of 2002; management continues to evaluate future declaration of common stock dividends in light of expected cash requirements and other considerations.

In June 2002, PGE entered into a new $72 million 364-day revolving credit facility with a group of commercial banks. For further information, see Note 9, Credit Facilities and Debt, in the Notes to Financial Statements.

On July 25, 2002, PGE's board of directors approved a non-cash dividend of $27 million to Enron related to the transfer of a receivable balance due from PGH. (For further information, see Note 5, Related Party Transactions, in the Notes to Financial Statements).

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Articles of Incorporation and the Indenture securing its First Mortgage Bonds. As of June 30, 2002, PGE has the capability to issue additional First Mortgage Bonds in amounts sufficient to meet its anticipated capital requirements.

As a result of the May 2002 termination of the stock purchase agreement to sell PGE to NW Natural, credit rating agencies reviewed their ratings of PGE. Moody's Investors Service (Moody's) lowered its ratings and retained the Company "on review for possible downgrade." Fitch Ratings (Fitch) also lowered its ratings and retained the Company on "Rating Watch Negative." Standard & Poor's (S&P) reaffirmed PGE's ratings and maintained its "CreditWatch with Negative Implications" listing.

On August 1, 2002, Fitch further lowered its ratings of PGE to below investment grade and maintained a "Ratings Watch Negative" status on the Company. This action by Fitch reflects its view that the Company has reduced financial flexibility resulting from its status as a subsidiary of an insolvent parent and a difficult capital market environment. Fitch also considered the risk associated with PGE's ongoing exposure to the Enron bankruptcy and the uncertainty regarding ongoing investigations into PGE's energy trading activities in the western U.S. power markets (see "Federal Investigations - Wholesale Power Markets" in the Financial and Operating Outlook section).

PGE's current ratings are as follows:

Due to the latest ratings action by Fitch, PGE could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral, with an exposure estimated at $8 million. Currently, no additional performance collateral has been requested as a result of this ratings action.

PGE's secured and unsecured debt ratings continue to be investment grade from both Moody's and S&P. However, S&P has indicated that its ratings could be lowered if PGE were to remain a wholly owned subsidiary of Enron, reflecting the general vulnerability of a wholly owned subsidiary to its insolvent parent. S&P has indicated that, in the absence of effective structural separation ("ring-fencing") measures, PGE's ratings are likely to be downgraded well into the speculative grade category. PGE continues to actively pursue the satisfaction of S&P's structural separation criteria.

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. Based on PGE's non-trading and trading portfolio, estimates of current energy market prices, and the level of collateral outstanding as of July 22, 2002, the approximate amount of additional collateral that could be requested upon such a downgrade event is $163 million. This amount decreases to approximately $29 million by year-end 2002 as current higher-priced energy contracts continue to settle. In addition to collateral calls, such a credit ratings reduction would likely have an adverse effect on PGE's ability to issue long-term debt. In addition, any such rating reductions would increase interest rates on PGE's two revolving credit facilities, increasing the cost of funding its day-to-day working capital requirements.

The Company's ability to access the commercial paper market has been adversely affected by recent ratings reductions for commercial paper by Moody's and Fitch. PGE has $150 million in long-term debt maturing in December 2002 and $182 million in 2003 ($142 million in May 2003 and $40 million in August 2003). The Company is pursuing options to refinance these maturities, including the issuance of additional First Mortgage Bonds and the use of revolving lines of credit with commercial banks. PGE anticipates meeting these obligations.

Management believes that it has the ability to use its existing lines of credit, along with cash from operations, to provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

On May 17, 2002, Enron and NW Natural entered into a Termination Agreement in which they agreed to terminate the Stock Purchase Agreement to sell PGE to NW Natural. The Termination Agreement was subject to, and effective upon, approval of the Bankruptcy Court and the consent of the lenders from whom Enron has obtained debtor-in-possession financing, both of which have been obtained. The Termination Agreement also provides for mutual releases from any legal action associated with the Stock Purchase Agreement.

In December 2001, Enron and certain of its subsidiaries filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. Neither PGE nor numerous other Enron subsidiaries, including subsidiaries owning gas pipelines and related facilities, are included in the bankruptcy. Numerous shareholder and employee class action lawsuits have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members, and its stock has been suspended from trading on the New York Stock Exchange. In addition, investigations of Enron have been commenced by several Congressional committees and state and federal regulators, including the FERC and the State of Oregon. In March 2002, Enron, substantially all of its subsidiaries and several former officers were suspended by the General Services Administration from contracting with the federal government.

On May 3, 2002, Enron presented to its creditors committee a proposal under which certain of Enron's core energy assets, including PGE, would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. If Enron's proposal were to be adopted, the inclusion of PGE in the new company would be subject to potential sale to a different buyer under a Section 363 auction process, which would be supervised by the Bankruptcy Court. Enron's proposal has not been endorsed or approved by the creditors committee and is one of many options Enron may pursue. There can be no assurance as to whether PGE would ultimately be included in a new company or separately sold to a bidder in a Section 363 auction. Until this process results in a filing with the Bankruptcy Court, management will not know the role of PGE in the proposed structure and cannot assess the impact on PGE's business and operations.

Although PGE is not included in the Enron bankruptcy, it has been affected. The Company has been included in requests for documents related to Congressional and regulatory investigations, with which it is fully cooperating. PGE was also included in Enron subsidiaries suspended from contracting with the federal government. Although no federal, state, or local governmental entity has ceased to transact business with PGE, and the BPA has stated that the suspension does not affect its sales and purchases of electricity with PGE, the Company believes it does not merit suspension and has begun the process to be removed from the suspension. Management believes the suspension will not have a material adverse effect on PGE business and operations.

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

Management cannot predict with certainty what impact Enron's bankruptcy may have on PGE. However, it does believe that the assets and liabilities of PGE will not become part of the Enron estate in bankruptcy. Although Enron owns all of PGE's common stock, PGE as a separate corporation owns or leases the assets used in its business and PGE's management, separate from Enron, is responsible for PGE's day to day operations. 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. 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 Portland General Corporation in 1997 (the merger conditions), Enron's access to PGE cash or utility assets (through dividends or otherwise) is limited. Under the merger conditions, PGE cannot make any distribution to Enron that would c ause PGE's equity capital to fall below 48% of total PGE capitalization (excluding short-term borrowings) without OPUC approval. The merger conditions also include notification requirements regarding dividends and retained earnings transfers to Enron. PGE is required to maintain its own accounting system as well as separate debt and preferred stock ratings.

Neither does management believe that there is any incentive for Enron or its creditors to take PGE into bankruptcy. PGE is a solvent enterprise whose greatest value is as a going concern. PGE believes that in a bankruptcy, Enron would lose most, if not all control over PGE. It would become merely the holder of PGE's common stock, and PGE, as a debtor in possession, would be managed by its management or, as is the case with Enron in its bankruptcy, new management brought in for that purpose. As debtor in possession, PGE would owe fiduciary obligations to its creditors. It would be the creditors of PGE, not Enron or the creditors of Enron, that would form a creditors' committee with oversight over the activities of PGE management. PGE believes that any plan of reorganization would be devised by PGE management and subject to confirmation by the Bankruptcy Court after the vote of PGE's (not Enron's) creditors. No dividends could be paid to Enron, no assets could be sold, and no other transfer of funds could be made except with the approval of the Bankruptcy Court after notice to PGE's creditors. Further, PGE would continue to be required to operate its business according to Oregon law, and the OPUC would not be stayed from enforcing its police and regulatory powers. Since the issue of whether a Bankruptcy Court has the authority to supersede state regulation of a utility has not been resolved, PGE believes that the OPUC would challenge any attempt to sell assets, transfer stock, or otherwise affect the activities of PGE without the approval of the OPUC. Any such challenge would likely result in years of litigation and effectively preclude any transfer of stock, assets, or other funds from PGE to Enron or any other party. As a result, PGE believes that the economic interests of Enron and its creditors are better served by pursuing their present course.

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 JP Morgan Chase Bank. The agreement was amended and restated in July 2002. PGE management has been advised by Enron management and its legal advisors that, under the amended and restated agreement and related security agreement, all of which were approved by the Bankruptcy Court, Enron has pledged its stock in a number of subsidiaries, including PGE, to secure the repayment of any amounts due under the debtor-in-possession financing. The pledge will be automatically released upon a sale of PGE otherwise permitted under the terms of the credit agreement. Enron also granted the lenders a security interest in the proceeds of any sale of PGE. The lenders may not exercise substantially all of their rights to foreclose against the pledged shares of PGE stock or to exercise control over PG E unless and until the lenders have obtained the necessary regulatory approvals for the transfer of PGE stock to the lenders.

Management cannot predict the ultimate outcome of the above matters due to the uncertainties surrounding Enron's bankruptcy. For additional information, see Note 8, Enron Bankruptcy, in the Notes to Financial Statements.

In order to protect both PGE and its customers from price volatility in the wholesale power and natural gas markets, the OPUC has authorized the Company to defer actual net variable power costs which differ from certain baseline amounts approved by the Commission. During the initial power cost mechanism, which covered the period January through September 2001, PGE's net variable power costs, as calculated under terms approved by the OPUC, exceeded the baseline. The Company received Commission approval to recover the approximate $91 million balance (including $7 million of interest), over a period of 3 1/2 years (April 1, 2002 - September 30, 2005). Such recovery is being offset by the refund of approximately $22 million in certain customer credits over the period April 1, 2002 through December 31, 2002, with no net effect on customer rates during this time. Such customer credits consist primarily of a final distribution received in 2000 related to PGE's terminated membership in Nuc lear Electric Insurance Limited (NEIL).

In its August 2001 general rate order, the OPUC approved a Power Cost Adjustment mechanism extending from October 1, 2001 through the end of 2002. Under this mechanism, PGE shares with its retail customers the difference between actual net variable power costs and the amount used to establish base energy rates. In addition, PGE shares with customers the difference between actual energy revenues and a pre-determined base. A portion of the net difference between pre-determined levels and actual net variable power costs and revenues (termed "Power Cost Variance") is subject to recovery (or refund). Any Power Cost Variance exceeding $28 million is shared with PGE customers, with any variance between $28 million and $38 million shared equally. Of the next $62 million (up to $100 million), PGE will collect or refund 85% of the variance, and of the next $100 million (up to $200 million), PGE will collect or refund 90% of the variance. For variances that exceed $200 million, PGE will collect or re fund 95% of the variance.

A Power Cost Adjustment Account is maintained to record both the calculated Power Cost Variance and amounts actually collected from or refunded to customers. Any tariff rate adjustments, calculated on a quarterly basis, are subject to review and approval by the OPUC. In the first nine months of the mechanism, approximately $31 million was deferred for future recovery from retail customers, all of which applied to the first half of 2002. In May 2002, PGE filed with the OPUC proposed tariff schedules that offer two alternatives for collection of the deferred Power Cost Variance. The Commission has postponed a decision on such alternatives pending PGE's filing of its next Power Cost Adjustment forecast, anticipated in August 2002.

PGE has filed a proposed tariff with the OPUC to continue the power cost adjustment mechanism beyond 2002.

On July 1, 2002, PGE filed with the OPUC an updated 2003 power cost forecast that estimates a reduction in power costs utilized in the Company's most recent general rate filing. The updated forecast projects a 7 to13 percent price decrease for the Company's business customers and a one percent decrease for residential customers. Rates for business customers are affected more by wholesale energy market prices, which have decreased significantly in recent months. Benefits to residential customers are expected to be smaller as their rates are affected more by PGE's cost of generation, which has increased due to higher natural gas prices, as well as the cost of electricity from BPA, which is expected to increase prices in October 2002.

PGE anticipates filing additional power cost updates throughout the remainder of 2002 and will submit its final forecast for OPUC approval in mid-November, with new prices to be effective January 1, 2003.

Under OPUC rules implementing Oregon's electric industry restructuring law, electric utilities were required to file a resource plan, including an evaluation of, and recommendations regarding, existing generating resources. Such recommendations were required to facilitate a fully competitive market, provide consumers fair, non-discriminatory access to competitive markets, and retain the benefit of low-cost resources for customers.

Although the OPUC has not adopted final rules governing resource plan updates, PGE filed an Integrated Resource Plan on August 9, 2002, updating its plan filed in late 2000. In its updated plan, PGE has described its strategy to meet the electric energy needs of its customers, with an emphasis on long-term price stability and supply reliability. PGE has requested a prehearing conference with the Commission to schedule a review of the plan.

The Emerging Issues Task Force (EITF) of the FASB recently reached a consensus in Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, regarding financial statement presentation of revenues and expenses associated with "energy trading contracts." The EITF requires that, effective for the third quarter of 2002, such revenues and expenses be reported on a net basis for all periods presented. PGE has historically presented such activities on a gross basis as contracts settled, with sales recorded in Operating revenues and power purchases recorded in Purchased power and fuel expense.

PGE continues to evaluate the financial statement reclassification required by EITF Issue No. 02-3. PGE believes that implementation of the consensus in EITF Issue No. 02-3 will likely have a material impact on total revenues and expenses, but will have no impact on its financial condition or results of operations.

As of August 1, 2002, PGE has accounts receivable totaling approximately $74 million that may be affected by the financial condition of two major California utilities. Significant increases in wholesale power prices in the last half of 2000 and in early 2001 severely affected the financial stability of both companies and resulted in the declaration of bankruptcy by one of the utilities. A credit reserve has been established by PGE for amounts due under wholesale electricity contracts. For further information, see Note 6, Receivables-California Wholesale Market, in the Notes to Financial Statements.

The FERC has issued an order directing certain electricity suppliers, including PGE, to supply information regarding wholesale power sales to California made in 2000 and 2001. Settlement discussions have taken place between the power suppliers, the state of California, and the FERC regarding potential refunds by suppliers. The discussions did not resolve the issues and hearings were held in March 2002, with additional hearings scheduled for August 2002 to determine any potential refunds for sales in the California spot market between October 2, 2000 and June 20, 2001.

FERC hearings have also been held to determine whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest by PGE and other suppliers from December 25, 2000 through June 20, 2001. A FERC Administrative Law Judge issued a recommended order that claims for refunds be dismissed. That recommendation, which would eliminate any potential refunds to be paid or received by PGE as a result of this proceeding, is now before the FERC for action. Several of the complainants in this case have filed motions to reopen the hearing. Those motions are also awaiting FERC action.

Any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California and the Pacific Northwest may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost mechanism. This could potentially mitigate the financial effect of any refunds made or received by the Company. In addition, PGE believes that any refunds related to California sales that may be required by the FERC can be offset by accounts receivable related to sales in California.

See Note 6, Receivables - California Wholesale Market, and Note 7, Refunds on Wholesale Transactions, in the Notes to Financial Statements for further information.

In June 2001, the FERC adopted a price mitigation program for the power system serving 11 Western states, adopting a new benchmark formula that limits prices for electricity sold in the spot markets at all times throughout the region through September 2002. The program applies to power generators, marketers, and investor-owned utilities under FERC jurisdiction, as well as public power providers, municipal utilities, and electric cooperatives that use FERC-regulated transmission lines.

Under the program, a ceiling price is set by FERC for wholesale electricity sold in the spot market coordinated by the California Independent System Operator and in markets in the other Western states. The ceiling price, reflecting specified fuel, operations, and maintenance costs, is based upon the bid submitted by the highest cost gas-fired generating unit whose power is needed when reserves in California fall below 7 percent, triggering a Stage 1 supply emergency. No bid to sell power may exceed the ceiling price as long as the reserve emergency is in place. When reserves again exceed 7 percent, removing the emergency, the ceiling price drops to 85 percent of the highest hourly price in effect during the most recent Stage 1 reserve emergency. Because of increased credit risk, wholesale electricity sales to California are allowed a 10 percent surcharge. The initial ceiling price was set at $91.87/MWh.

PGE and other Northwest utilities expressed concerns regarding potentially adverse consequences of price mitigation measures on Northwest citizens, utilities, power marketers and generators. In response, the FERC in December 2001 temporarily modified the method for calculating the ceiling price for markets in Western states not coordinated by the California Independent System Operator. The changes acknowledged differences between the Northwest and California markets, including those related to hydropower utilization and seasons of peak usage. They include the discontinuation of the above reserve deficiency method to formulate the mitigated price and utilize instead incremental changes in the cost of natural gas to trigger adjustments in the price, initially set at $108/MWh. The changes were in effect until May 1, 2002, at which time the previous methodology and ceiling price again became effective.

In a July 17, 2002 order, the FERC raised the ceiling price on Western wholesale electricity prices from $91.87/MWh to $250/MWh, effective October 1, 2002. The new ceiling price, which applies to all sales of electricity in the Western Systems Coordinating Council, is intended to reflect market conditions and allow prices that properly signal energy supply scarcity and provide greater opportunity for generators to recover their costs. In addition to the new price ceiling, the FERC order established conditions and rules that will guide participation in Western wholesale electricity markets after the current wholesale price mitigation plan expires in September 2002, including automatic price mitigation procedures that will be implemented during periods of tight supplies to help ensure fair prices.

On February 13, 2002, the FERC initiated a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West, or otherwise exercised undue influence over wholesale prices in the West, since January 1, 2000. On March 5, 2002, all sellers with wholesale sales in the U.S. portion of the WSCC were directed to provide certain historical and projected information for all energy transactions in calendar years 2000 and 2001. Although PGE was not specifically named in the FERC directive, the Company bought and sold power in the region during the relevant period and voluntarily submitted requested information.

In early May 2002, the FERC received information contained in memos released by Enron, indicating that Enron, through subsidiary Enron Power Marketing, Inc. (EPMI), may have engaged in several types of trading strategies that raised questions regarding potential manipulation of electricity and natural gas prices in California in 2000-2001. On May 8, 2002, the FERC ordered all sellers of wholesale electricity or ancillary services into the California markets during 2000-2001 to respond to the FERC whether they engaged in any transactions falling within any of the enumerated types of trading strategies, and, if they did, to provide information about the transactions. On May 22, 2002, PGE submitted the results of its investigation, which did not uncover any instances where the Company, itself, engaged in or knowingly aided deceptive or misleading trading strategies. PGE did discover that it was among other intermediaries in a series of trading activities that occurred on 15 days from Apri l through June 2000 where EPMI was found to be at both ends of the transaction chain (revised from 17 days, as initially reported). The trading transactions identified during the 15-day period moved about 2,300 (revised from 2,500, as initially reported) megawatt hours (0.12%) of the total 2 million megawatt hours traded by PGE on those days, and about 0.02% of the total 13 million megawatt hours traded by PGE during the three-month period. The services provided by PGE may have been used by EPMI as a step in one of the enumerated strategies. In addition, it is conceivable that in the normal course of business, PGE could have provided services to third parties that may have resulted in PGE being used, unknowingly, as an intermediary in partial execution of one or more of the enumerated strategies.

On June 4, 2002, the FERC issued an order to PGE and three other companies to show cause why their authority to charge market-based rates should not be revoked. Such order states that the companies' responses to the FERC's May 8, 2002 data request (discussed above) are indicative of a failure to cooperate with its investigation. PGE believes that it has fully

cooperated with the FERC's inquiry. On June 14, 2002, PGE filed a response with the FERC, indicating that a thorough review of Company documents again found no evidence of deception or market manipulation by PGE.

On May 21, 2002, the FERC issued a data request and request for admissions to all sellers of wholesale electricity and/or ancillary services in the U.S. portion of the WSCC during the years 2000-2001. Such request ordered sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. Although PGE was not listed in the data request, PGE conducted an investigation and submitted the results in a response to the FERC on May 31, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request to the extent that such activities artificially inflated trading volumes, revenues or market prices. PGE's response also noted that it had no reason or incentive to artificially inflate trading volumes or revenues, as the primary purpose of its wholesale trading operations is to manage risk and reduce costs for its retail customers by balancing load requirements and maximizing the value of owned generation and purchase contracts to the extent that available supply is excess to the needs of the Company's firm customers.

On May 22, 2002, the FERC issued a data request and request for admissions to all sellers of natural gas in the U.S. portion of the WSCC and in Texas during the years 2000-2001. Such request ordered such sellers to admit or deny engagement in activities referred to as "wash," "round trip," or "sell/buyback" type transactions. PGE conducted an investigation and submitted the results in a response to the FERC on June 5, 2002. Such response denied that PGE engaged in trading activities described in the FERC data request.

On June 17, 2002, the U.S. Commodity Futures Trading Commission (CFTC), which regulates futures contracts traded on U.S. exchanges, subpoenaed documents from PGE regarding the Company's electricity and natural gas trading, including any "wash" trading used to inflate revenue and trading volume. PGE forwarded documents previously prepared for the FERC investigation (described above).

PGE is cooperating and will continue to cooperate to the fullest extent with these investigations.

In late 2001, the State of California and numerous individuals, businesses and California cities, counties and other governmental entities filed class action law suits (Wholesale Electricity Antitrust Cases) against various individuals, utilities, generators, traders and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties) alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and penalties.

In late April 2002, the Duke parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. An open extension of time has been agreed to by the parties until 30 days after a ruling on jurisdiction is made in the original case. At this time, management is unable to make any assessment of or determination with respect to this complaint.

In May 2002, the Attorney General of California filed a complaint alleging failure of PGE to comply with FERC approval requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price;" no specific damage claim is stated. In July 2002, PGE filed a Notice of Removal to federal court and a Motion to Dismiss on preemptive grounds, with a hearing currently scheduled for late August 2002.

Due to the closure of the Trojan nuclear plant in 1993 and issuance of a 1995 OPUC general rate order in connection with the recovery of and a return on the Trojan investment, numerous legal challenges, appeals and regulatory actions have taken place. As a result of a settlement agreement that was implemented in 2000, the recovery of the Trojan plant investment is no longer included in rates charged to customers. The Company continues to collect for costs related to the decommissioning of the plant. (For further information, see Note 4, Legal and Environmental Matters, in the Notes to Financial Statements).

Grievances have been filed by several members of the International Brotherhood of Electrical Workers (IBEW) Local 125, the bargaining unit representing PGE's union workers, with respect to losses in their pension/savings plan attributable to the collapse of the price of Enron's stock. The grievances, which allege that the losses were caused by Enron's manipulation of the stock, seek binding arbitration under Local 125's collective bargaining agreement on behalf of all present and retired bargaining unit members. The grievances do not specify an amount of claim, but rather request that the present and retired members be made whole. PGE has filed a Motion for Declaratory Relief in the Multnomah County Circuit Court for the State of Oregon, seeking a declaratory ruling that the grievances are not subject to arbitration under the collective bargaining agreement, that the grievances are preempted by ERISA, and that the conduct complained of is directed against Enron, not PGE. The IBEW f iled an answer and counterclaim that the issue is arbitrable, and PGE filed a reply which denied the counterclaim and raised four affirmative defenses. It is not likely that a hearing on these motions and counterclaim will take place before the fall of 2002. No reserves have been established by PGE for any amounts related to this issue.

A 1997 investigation of a portion of the Willamette River known as the Portland Harbor, conducted by the EPA, revealed significant contamination of sediments within the harbor. Subsequently, the EPA included 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 regulated hazardous substances had been released from the substation property into the Portland Harbor sediments. While PGE does not believe that it is responsible for any contamination in Portland Harbor, in May 2000 the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement. Pursuant to the Voluntary Agreement, PGE submitted a pre-remedial investigation work plan for DEQ review and approval.

In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. Such 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, PGE submitted a final study plan to the DEQ for approval, with testing initiating in June 2001. PGE has performed initial investigations and remedial activities based upon the approved study plan. Such investigations have shown no significant soil or groundwater contaminations with a pathway to the river sediments from the Harborton site.

In February 2002, PGE submitted a report to the DEQ summarizing its pre-remedial investigations conducted in accordance with the May 2000 Voluntary Agreement. The report indicated that such investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments at or from the Harborton Substation site. Further, the investigations demonstrated that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The report concluded that the Harborton Substation facility was not a source of contamination to the Willamette River because no likely sources of hazardous substance releases were identified. A request has been made to the DEQ for a determination that no further work is required under the Voluntary Agreement.

The EPA is coordinating activities of natural resource agencies and the DEQ and in early 2002 requested and received signed "administrative orders of consent" from several Potentially Responsible Parties, voluntarily committing to further remedial investigations; PGE was not requested to sign such order.

Available information is currently not sufficient to determine either the total cost of investigation and remediation of the Portland Harbor or the potential liability of responsible companies, including PGE. (For further information, see Note 4, Legal and Environmental Matters, in the Notes to Financial Statements).

Weather adjusted retail energy sales decreased by 4.3% for the six months ended June 30, 2002, compared to the same period last year. Manufacturing sector sales declined 10.2%, with all segments of this sector down from last year. Excluding the effects of the Demand Buyback program, in which PGE paid large customers to reduce their load during peak demand periods in 2001, manufacturing sector sales declined about 14%. Commercial and residential energy sales were down 2.2% and 1.8%, respectively. PGE forecasts retail energy sales in 2002 will remain down somewhat from last year, as continued customer growth is offset by both a slow economy and increased conservation efforts.

Power Supply

Hydro conditions in the region have significantly improved from last year, although they 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 96% of normal, compared to 55% of normal last year.

PGE generated 37% of its retail load requirement in the first half of 2002, with hydro generation comprising about 11% of the Company's requirement; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with its base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers. Although surplus generation has diminished in recent years due to economic and population growth in the western United States, recent construction of new generating plants has increased the region's capacity to meet its power needs. In addition, a reduction in demand from a slowing economy and increased conservation efforts, along with increased natural gas supplies and federal price mitigation, have together resulted in significantly lower market prices for both electricity and na tural gas than in the first half of 2001.

See Note 10, New Accounting Standards, in the Notes to Financial Statements for information regarding new SFAS No. 143, Accounting for Asset Retirement Obligations, and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities.

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

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

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

• matters related to Enron and certain of its subsidiaries' filings to initiate bankruptcy proceedings under Chapter 11 of the federal Bankruptcy Code (PGE is not included in the filing);
• events related to Enron's bankruptcy proceedings;
• effects of electric industry restructuring in Oregon and in the United States, including wholesale competition;
• governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;
• changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;
• wholesale energy prices (including the effect of FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;
• the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;
• operational factors affecting PGE's power generation facilities;
• changes in, and compliance with, environmental and endangered species laws and policies;
• 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 may 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 exchange rates and interest rates. These changes may affect the Company's future financial results.

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

Gains and losses from instruments that reduce commodity price risk are recognized when settled in purchased power and fuel expense, or in wholesale revenue. In addition, PGE 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. Unrealized gains and losses on such instruments are recognized within "Purchased power and fuel" expense on PGE's Income Statement. Valuation of these financial instruments reflects management's best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value, and volatility factors underlying the commitments.

The Company actively manages its risk to ensure compliance with its risk management policies. PGE 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 half of 2002 was $0.2 million, $0.4 million, and zero, respectively, and in the first half of 2001 was $1.3 million, $3.6 milli on, and $0.2 million, respectively. The value at risk on the non-trading portfolio is not meaningful since the majority of the portfolio is effectively accounted for on an accrual or settlement basis.

Additionally, the Company has a power cost mechanism in place that allows PGE to defer, for future ratemaking treatment, actual net variable power costs that differ from certain baseline amounts approved by the OPUC. (For additional information, see "Power Cost Mechanisms" in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations).

PGE is exposed 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 and determines an appropriate hedging strategy.

At June 30, 2002, a 10% change in the value of the Canadian dollar would result in a change in pre-tax income of approximately $4 million at the time the transactions settle over the next 21 months. However, effects of such value changes would be reflected in the calculation of net variable power costs under PGE's power cost mechanism, which would mitigate their financial effect upon the Company. 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.

PGE is exposed to risk resulting from changes in interest rates on variable rate commercial paper, short-term borrowings, and long-term debt outstanding. Although the Company currently has no financial instruments to mitigate such risk, it will consider such instruments in the future as necessary.

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

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 with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, wholesale marketing, 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, see PGE's report on Form 10-K for the year ended December 31, 2001.

On July 1, 2002, PGE filed with the Oregon Supreme Court a Notice of Mootness and Motion to Dismiss and Vacate the case.

On December 24, 2001, the State of California and numerous individuals, businesses and California cities, counties and other governmental entities filed class action law suits (Wholesale Electricity Antitrust Cases) against various individuals, utilities, generators, traders and other entities, including Duke Energy Trading and Marketing, LLC; Duke Energy Morro Bay, LLC; Duke Energy Moss Landing, LLC; Duke Energy South Bay, LLC and Duke Energy Oakland, LLC (Duke Parties) alleging that activities related to the purchase and sale of electricity in California in 2000 and 2001 violated California antitrust and unfair competition laws. The complaint seeks, among other things, restitution of all funds acquired by means that violate the law and payment of treble damages, interest, and penalties.

On April 23, 2002, the Duke parties filed a cross complaint against PGE and other utilities, generators, traders and other entities not named in the Wholesale Electricity Antitrust Cases, alleging that they participated in the purchase and sale of electricity in California during 2000-2001 and seeking complete indemnification and/or partial equitable indemnity on a comparative fault basis for any liability that the Court may impose on the Duke Parties under the Wholesale Electricity Antitrust Cases. Legal and equitable relief is sought, with no specific monetary amount claimed. An open extension of time has been agreed to by the parties until 30 days after a ruling on jurisdiction is made in the original case.

On May 30, 2002, the Attorney General of California filed a complaint alleging failure of PGE to comply with FERC approval requirements for its market based sales of power in California. The complaint seeks fines and penalties under the California Business and Professions Code for each sale from 1998 through 2001 above a "capped price"; no specific damage claim is stated. On July 10, 2002, PGE filed a Notice of Removal to federal court. On July 17, 2002, PGE filed a Motion to Dismiss on preemptive grounds, with a hearing currently scheduled for late August 2002.

The following have been appointed as Directors of PGE, effective July 2, 2002:

Raymond M. Bowen, Jr. - Has served as Executive Vice President, Chief Financial Officer and Treasurer of Enron since January 2002. Previously, he was Executive Vice President and Treasurer of Enron and, prior to that, was Chief Operating Officer of Enron Industrial Markets. Mr. Bowen joined Enron in 1996 as Vice President of Enron Energy Services and has also served as Vice President of Enron Capital Management, Vice President and Treasurer of Enron Capital & Trade Resources Corp., and Managing Director and Treasurer of Enron North America Corp.

Michael E. France - Has been a Partner with Zolfo Cooper, LLC, crisis management and corporate recovery specialists, since 1982, and is currently participating in corporate restructuring efforts at Enron. He has approximately thirty years of diversified business and professional experience, including approximately fifteen years working with troubled companies, their creditors, investors, and other interested parties. Previously, Mr. France was a financial consulting principal at Touche Ross & Co. (now Deloitte & Touche).

Robert H. Walls, Jr. - Has served as Executive Vice President and General Counsel for Enron since March 2002. Previously, he was Managing Director and Deputy General Counsel of Enron from August 2000 to March 2002 and, prior to that, was Managing Director and General Counsel of Enron International Inc. Mr. Walls joined Enron in 1992 as Vice President and General Counsel of Enron Power Corp. and became Senior Vice President and General Counsel of Enron Development Corp. in 1995.

The above individuals join the following as Directors of PGE:

Peggy Y. Fowler, Chief Executive Officer and President of PGE;

Stanley C. Horton, Chairman and Chief Executive Officer of Enron Global Services; and,

James J. Piro, Executive Vice President Finance, Chief Financial Officer & Treasurer of PGE.

On August 6, 2002, a NRC Notice of Violation was issued to PGE as a result of an investigation conducted during the period from December 2, 1999 to July 3, 2001, relating to the loading of spent nuclear fuel into a multi-assembly sealed basket (MSB) on July 11, 1999. The NRC investigation, in part, was to review the circumstances surrounding the coatings qualification testing conducted by the MSB vendor for PGE. The coating was used to coat the surfaces of the internal carbon steel components of the MSBs to be stored within spent fuel concrete storage casks at the Trojan Nuclear Plant, which was permanently shut down in 1993. The NRC's investigation did not substantiate that employees of PGE were aware that the coatings qualifications testing was inadequate.

As a result of the investigation, the NRC determined that two violations occurred. The first violation involved the submittal of information in support of an application for a dry fuel storage license under 10 CFR Part 72. The NRC determined that the submittal was not complete and accurate in all material respects because the report stated that the quality assurance program for the coating was performed under the control of PGE's vendor. The NRC found that PGE failed to verify that its vendor implemented its quality assurance program in certain respects. The NRC also identified a second violation involving a failure to establish measures to ensure that the coating applied to the surfaces of the internal components of the MSB complied with design basis requirements. This was found to have resulted in the MSB generating volatile organic compounds and flammable gases during loading operations.

The NRC categorized these violations as a Severity Level III problem based on the potential for safety consequences. The NRC categorizes violations as Severity Levels I through IV, with Severity Level I being the most serious. The NRC found that PGE took prompt action to correct and to prevent recurrence of the violations to achieve full compliance with the NRC requirements. PGE's corrective actions included the replacement of the MSB vendor.

Under the NRC's enforcement policy, a base civil penalty of $60 thousand is considered for a Severity Level III problem. However, due to PGE's prompt and comprehensive correction of the violations, and in recognition of the absence of previous escalated enforcement actions within the last two inspections, the NRC did not propose a civil penalty.

1. Exhibits:

(99) Additional Exhibits

b. Reports on Form 8-K

June 12, 2002 - Item 5. Other Events: Financing Activities.

August 1, 2002 - Item 5. Other Event: Credit Ratings.

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 hereunto duly authorized.

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

53

I, Peggy Y. Fowler, Chief Executive Officer and President of Portland General Electric Company (the "Company"), hereby certify, to the best of my knowledge and belief, that the accompanying report on Form 10-Q for the quarterly period ended June 30, 2002, and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.

I further certify, to the best of my knowledge and belief, that the information contained in such report on Form 10-Q for the quarterly period ended June 30, 2002, fairly presents, in all material aspects, the financial condition and results of operations of the Company.

I, James J. Piro, Chief Financial Officer of Portland General Electric Company (the "Company"), hereby certify, to the best of my knowledge and belief, that the accompanying report on Form 10-Q for the quarterly period ended June 30, 2002, and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.

I further certify, to the best of my knowledge and belief, that the information contained in such report on Form 10-Q for the quarterly period ended June 30, 2002, fairly presents, in all material aspects, the financial condition and results of operations of the Company.