PORTLAND GENERAL ELECTRIC CO /OR/ - Quarter Report: 2008 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

Number of shares of common stock outstanding as of October 24, 2008 is 62,557,928 shares.

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PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

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PART I – FINANCIAL INFORMATION

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power and fuel marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. The Company served approximately 814,000 retail customers as of September 30, 2008.

As of September 30, 2008, PGE had 2,726 employees, with 884 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (the Union). Such agreements cover 851 and 33 employees for the five-year periods ending February 28, 2009 and August 1, 2011, respectively. The Company is currently in negotiations with the Union to develop a new agreement to replace the agreement that expires February 28, 2009.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein for the three and nine month periods ended September 30, 2008 and 2007 is unaudited. Such information, however, reflects all adjustments, consisting of normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated results of operations and condensed consolidated cash flows of the Company for these interim periods. 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 may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2007 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2007, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 27, 2008, and should be read in conjunction with such consolidated financial statements.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

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Reclassifications

Certain reclassifications have been made to the 2007 financial information to conform to the 2008 presentation. These reclassifications include (1) the presentation of income tax expense as one caption in the condensed consolidated statements of income for the three and nine month periods ended September 30, 2007, which was previously reported as a separate line within operating expenses and other income (deductions), and (2) the inclusion of long-term debt of $1,313 million in total liabilities in the condensed consolidated balance sheet as of December 31, 2007, which was previously reported in total capitalization. For the three months ended September 30, 2007, income tax expense of $10 million and $2 million was previously reported in operating expenses and other income (deductions), respectively. For the nine months ended September 30, 2007, income tax expense of $59 million and $3 million was previously reported in operating expenses and other income (deductions), respectively.

Recent Accounting Pronouncements

Adopted Accounting Pronouncements

On January 1, 2008, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. In February 2008, Financial Accounting Standards Board (FASB) Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2) was issued. FSP 157-2 delays the adoption of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, or January 1, 2009 for PGE. SFAS 157 does not modify any currently existing accounting pronouncements. PGE applies fair value measurements to certain assets and liabilities, including assets and liabilities from price risk management activities. The adoption of SFAS 157 did not have a material impact on the Company’s consolidated financial position or consolidated results of operations. PGE is in the process of determining whether the adoption of FSP 157-2 will have a material impact on its financial statements. For additional information, see Note 3.

On September 30, 2008, PGE adopted FASB Staff Position No. SFAS 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active (FSP 157-3), which clarifies the application of SFAS 157 in an inactive market and provides an illustrative example to demonstrate how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP 157-3 was issued on October 10, 2008 and is effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of FSP 157-3 had no impact on the Company’s financial statements.

On January 1, 2008, PGE adopted SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS 159), which allows eligible financial assets and liabilities to be measured at fair value that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in earnings at each reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the Company elects for similar types of assets and liabilities. The Company elected not to measure eligible financial assets and liabilities at fair value that were not otherwise measured at fair value. The adoption of SFAS 159 had no impact on PGE’s financial statements.

On January 1, 2008, PGE adopted FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (FSP FIN 39-1), which permits reporting entities to offset the receivable or payable recognized for

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derivative instruments that have been offset under a master netting arrangement. FSP FIN 39-1 requires financial statement disclosure of a reporting entity’s accounting policy (to offset or not to offset), as well as amounts recognized for the right to reclaim cash collateral, or the obligation to return cash collateral, that have been offset against net derivative positions. PGE elects to continue to not offset its exposures under master netting arrangements in accordance with FSP FIN 39-1, and therefore elects not to offset any fair value amounts recognized for the right to claim cash collateral or the obligation to return cash collateral against its derivative positions. The adoption of FSP FIN 39-1 had no impact on PGE’s financial statements.

On January 1, 2008, PGE adopted Emerging Issues Task Force (EITF) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11), which was ratified by the EITF on June 27, 2007. EITF 06-11 clarifies how an entity should recognize the income tax benefit received on dividends that are (1) paid to employees holding equity-classified nonvested shares and (2) charged to retained earnings under SFAS 123R, Share-Based Payment. EITF 06-11 is applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years. The adoption of EITF 06-11 had no impact on PGE’s financial statements.

New Accounting Pronouncements

SFAS 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51 (SFAS 160), was issued in December 2007 and amends Accounting Research Bulletin No. 51, Consolidated Financial Statements. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also (1) changes the way the consolidated income statement is presented, by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, (2) establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation, and (3) changes the way the consolidated income statement is presented. SFAS 160 shall be applied prospectively, with the exception of the presentation and disclosure requirements, and is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. Any noncontrolling interests resulting from the consolidation of a less than wholly-owned subsidiary beginning January 1, 2009 will be accounted for in accordance with SFAS 160. PGE estimates that the adoption of SFAS 160 will not have a material impact on its financial statements.

In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for annual and interim periods beginning after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will have no impact on PGE’s financial statements.

In June 2008, FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), was issued and addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in SFAS 128, Earnings per Share. FSP EITF 03-6-1 is

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effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period earnings per share data presented shall be adjusted retrospectively to conform to the provisions of this FASB Staff Position. Early application is not permitted. The adoption of FSP EITF 03-6-1 will not have a material impact on PGE’s financial statements.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts and Notes Receivable, Net

Accounts and notes receivable is net of an allowance for uncollectible accounts of $4 million and $5 million as of September 30, 2008 and December 31, 2007, respectively.

The following is the activity in the allowance for uncollectible accounts (in millions):

Inventories

Inventories consist of fuel and materials and supplies, all of which are considered finished goods, for use in operations or for the maintenance of the Company’s generating plants and transmission and distribution facilities.

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $107 million and $96 million as of September 30, 2008 and December 31, 2007, respectively. Amortization expense related to intangible assets was $4 million for the three month periods ended September 30, 2008 and 2007, and $11 million for the nine month periods ended September 30, 2008 and 2007.

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Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):

Credit Facility and Debt

Credit Facility

PGE has a $400 million unsecured revolving credit facility (Credit Facility) with a group of eight banks. The Credit Facility is available to the Company for borrowings for general corporate purposes and the issuance of standby letters of credit, as well as for supporting the Company’s commercial paper program, under which it may issue commercial paper for terms of up to 270 days. The commercial paper program requires the Company to maintain unused revolving credit capacity at least equal to the amount of commercial paper issued. The Credit Facility allows PGE to borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the Credit Facility. The Credit Facility provides that all outstanding loans mature on the termination date of the Credit Facility, provided that annually such date may be extended for an additional year for those lenders who agree to an extension. On June 13, 2008, PGE received approval from seven of the eight banks in the Credit Facility to extend the termination date for an additional year. As a result, a total of $390 million was extended for an additional year to July 2013. The remaining $10 million continues to have a termination date of July 2012.

On September 15, 2008, Lehman Brothers Holdings, Inc., the parent company of Lehman Brothers Bank, FSB (Lehman), filed for protection under Chapter 11 of the U.S. Bankruptcy Code. At that time, Lehman represented $55 million, or approximately 14%, of the Credit Facility. In October 2008, $25 million of

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Lehman’s $55 million share of the Credit Facility was reassigned to Sumitomo Mitsui Banking Corporation (Sumitomo). The Company is in discussions with another financial institution for reassignment of the remaining $30 million of Lehman’s share.

In October 2008, Wells Fargo & Company (Wells Fargo) announced the proposed acquisition of Wachovia Corporation (Wachovia). Wells Fargo and Wachovia each participate in the Credit Facility, with Wells Fargo representing $55 million, or 14%, and Wachovia representing $70 million, or 18%, of the Credit Facility. It is not expected that the proposed merger of Wells Fargo and Wachovia will have an impact on the Company’s ability to access funds available to it under the Credit Facility. The proposed merger is expected to close during the fourth quarter of 2008.

The Credit Facility requires annual fees based on PGE’s unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the Credit Facility agreement, to 65% of total capitalization. As of September 30, 2008, PGE was in compliance with this covenant.

As of September 30, 2008, PGE had $27 million of commercial paper outstanding and borrowings of $11 million under the Credit Facility, the total of which is classified as Short-term borrowings on the condensed consolidated balance sheet. The Company also had issued $37 million in letters of credit, with $270 million of remaining borrowing capacity available. As of October 24, 2008, PGE had $179 million borrowing capacity under its Credit Facility.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), PGE is authorized to issue short-term debt, including commercial paper, in an amount not to exceed $550 million outstanding at any one time, over the two-year period February 7, 2008 through February 6, 2010.

Long-term Debt

During 2008, PGE repurchased and retired $50 million of its 5.279% series First Mortgage Bonds due April 1, 2013 and issued $50 million of 4.45% series First Mortgage Bonds due April 1, 2013. Additionally, the Company repurchased $5.8 million of its Port of Morrow variable rate pollution control revenue bonds due December 1, 2031.

The current interest rate and interest period expire May 1, 2009 on $142 million of Pollution Control Revenue Bonds (Bonds), consisting of $23 million issued through the Port of Morrow, Oregon, and $119 million issued through the City of Forsyth, Montana. PGE is required under the terms of these Bonds to redeem the entire principal amount of the Bonds at a redemption price equal to 100% of the principal amount plus accrued interest on May 1, 2009. PGE has the option to have the Bonds remarketed beginning May 1, 2009 and can choose a new interest rate period that would be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of the remarketing. The Bonds are currently secured by a pledge of PGE First Mortgage Bonds. The Bonds could be remarketed as unsecured obligations of PGE or may be backed by PGE First Mortgage Bonds depending on market conditions. The Bonds are classified under the Current portion of long-term debt in the condensed consolidated balance sheet as of September 30, 2008.

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Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost for the three months ended September 30 (in millions):

The following table provides the components of net periodic benefit cost (income) for the nine months ended September 30 (in millions):

Management periodically reviews the reasonableness of the assumptions underlying the annual actuarial estimates.

NOTE 3: FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Company adopted SFAS 157, which requires, among other things, enhanced disclosures about assets and liabilities carried at fair value on a recurring basis. Pursuant to FSP 157-2, PGE will adopt SFAS 157 with respect to its nonfinancial assets and liabilities, which include asset retirement obligations, on January 1, 2009.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. However, as permitted under SFAS 157, PGE utilizes a mid-market pricing convention, the mid-point price between bid and ask prices, as a practical expedient for valuing the majority of its financial instruments.

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As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2-Pricing inputs are other than quoted market prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter (OTC) forwards and swaps.

Level 3-Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The Company’s financial assets and liabilities whose fair values were accounted for on a recurring basis are as follows by level within the fair value hierarchy (in millions):

* Activities are subject to regulation and, accordingly, gains and losses are deferred pursuant to SFAS 71 and included in regulatory assets or regulatory liabilities as appropriate.

Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and consist of fixed

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income securities. Changes in the fair value of decommissioning trust assets are deferred to the balance sheet pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation. Non-qualified benefit plan trust reflects the assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and consist primarily of marketable securities. While fluctuations in the fair value of the non-qualified benefit plan assets are recorded in current earnings, a portion of the change in assets value representing the cash surrender value is excluded from the table above as it is not subject to SFAS 157. Assets and liabilities from price risk management activities represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas.

As a result of continued turbulence in capital markets into October 2008, the fair values of financial assets classified as Level 1 have sustained additional decreases in fair value. From September 30, 2008 through October 24, 2008, the fair value of assets held by the Non-qualified benefit plan trust have decreased approximately $7 million.

Changes in the fair value of assets and liabilities from price risk management activities classified as Level 3 in the fair value hierarchy were as follows (in millions):

Net realized and unrealized losses included in Purchased power and fuel in the condensed consolidated statements of income, which includes $236 million and $60 million in net unrealized losses for the three and nine month periods ended September 30, 2008, respectively, have been fully offset by the effects of regulatory accounting pursuant to SFAS 71.

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NOTE 4: EARNINGS PER SHARE

Components of basic and diluted earnings per share were as follows:

Unvested performance stock units and related dividend equivalent rights are not included in the computation of dilutive securities because vesting of these instruments is dependent upon the attainment of specific goals during three-year performance periods.

Basic and diluted earnings per share amounts are calculated based on actual amounts. Accordingly, basic and diluted earnings per share amounts as presented in the table above and on the condensed consolidated statements of income may not necessarily recalculate based on the rounded amounts presented for both net income and weighted-average shares outstanding.

NOTE 5: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such activities include power and natural gas purchases and sales resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. PGE utilizes derivative instruments, which may include forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas, in its retail electric utility activities to manage its exposure to commodity price risk and to minimize net power costs. Under SFAS 133, derivative instruments are recorded at estimated fair value on the balance sheet as an asset or liability unless they qualify for the normal purchase, normal sale exception, with changes in estimated fair value recognized currently in earnings, unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows gains and losses on a derivative instrument to be recorded in comprehensive income until they can offset the related results on the hedged item in net income. The derivative instruments entered into to manage the Company’s future retail resource requirements are subject to regulation; accordingly, the unrealized gains and losses are deferred pursuant to SFAS 71 in both net income and comprehensive income.

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PGE has affirmed its ongoing policy election pursuant to FASB Interpretation No. (FIN) 39, Offsetting of Amounts Related to Certain Contracts, not to net on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists, as allowed under FIN 39.

Most of PGE’s wholesale sales have been to utilities and power marketers and have been predominantly short-term. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions are referred to as “book outs.” Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations and physically delivered is recorded in Wholesale sales and Purchased power and fuel expense.

Changes in the fair value of retail derivative instruments prior to settlement that do not qualify for either the normal purchases and normal sales exception or for hedge accounting are recorded on a net basis in Purchased power and fuel expense. For derivative instruments that are physically settled, sales are recorded in Revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel expense. PGE records the non-physical settlement of electricity derivative activities on a net basis in Purchased power and fuel expense, in accordance with EITF 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, as none of PGE’s derivative activities are executed for trading purposes.

Net unrealized gains (losses) from derivative activities recorded in net income, fully offset by the recognition of SFAS 71 regulatory assets or liabilities, were as follows (in millions):

In 2007, PGE elected to discontinue hedge accounting for the Company’s remaining outstanding derivatives designated as cash flow hedges, in accordance with SFAS 133, which did not have a material impact on the Company’s consolidated financial position or consolidated results of operations. Net unrealized gains of $2 million, substantially all of which the Company estimates will be reclassified into earnings within the next twelve months, are fully offset by SFAS 71 regulatory accounting, with the balance to settle over the next 36 months. These net unrealized gains, fully offset by SFAS 71 regulatory accounting, are included in Accumulated other comprehensive loss in the condensed consolidated balance sheet as of September 30, 2008.

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The following table reflects derivative activities from cash flow hedges recorded in comprehensive income, before taxes (in millions):

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NOTE 6: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):

NOTE 7: CONTINGENCIES

Legal Matters

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant as part of the Company’s least cost planning process. 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 Public Utility Commission of Oregon (OPUC). 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.

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Court Proceedings on OPUC Authority to Grant Recovery of Return on Trojan Investment. Numerous challenges, appeals and reviews were subsequently filed in the Marion County Circuit Court (Circuit Court), the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The primary plaintiffs in the litigation were the Citizens’ Utility Board (CUB) and the Utility Reform Project (URP). The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC’s authorization of PGE’s recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case was remanded to the OPUC (1998 Remand).

Settlement of Court Proceedings on OPUC Authority. In 2000, while the petitions for review of the 1998 Oregon Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE’s recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of the 1997 merger of the Company’s parent corporation at the time (Portland General Corporation) with Enron Corp. The settlement also allowed PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had flowed through to customers in prior years; such amount was recovered from PGE customers by the end of 2006. 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 prices charged to customers, either through a return of or a return on that investment. Authorized collection of Trojan decommissioning costs is unaffected by the settlement agreements or the OPUC orders.

Challenge to Settlement of Court Proceeding. URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC’s September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of URP’s challenges, and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 Order to the Circuit Court. On November 7, 2003, the Circuit Court issued an opinion remanding the case to the OPUC for action to reduce prices or order refunds (2003 Remand). The opinion did not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC appealed the 2003 Remand to the Oregon Court of Appeals. On October 10, 2007, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration because the 2002 Order was based, in part, on an incorrect understanding of Section 757.225 of the Oregon Revised Statutes. The Oregon Court of Appeals also vacated the 2003 Remand finding error in the Circuit Court’s specific instructions to the OPUC to revise the rate structure.

Remand of 2002 Order. As a result of the Oregon Court of Appeals remand of the 2002 Order, the OPUC considered the following issues:

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On September 30, 2008, the OPUC issued an order that requires PGE to refund $33.1 million to certain customers. The refund relates to the unamortized Trojan balance on September 30, 2000, as discussed below.

In the order, the OPUC also made the following findings:

The OPUC examined the rates in effect for the period April 1, 1995 through September 30, 2000 and determined what rates during this period would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. The OPUC removed the previously allowed return on the Company’s Trojan investment during the period, reduced the recovery period from 17 to 10 years, and revised certain other assumptions, all of which reduced the recoverable balance as of September 30, 2000 from $180.5 million to $165.1 million. The OPUC ruled that the difference of $15.4 million, plus interest at 9.6% from September 30, 2000, should be refunded to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The $15.4 million amount, plus accrued interest, results in a total refund of $33.1 million as of September 30, 2008. The order also provides that the total refund amount will accrue interest at 9.6% from October 1, 2008 until all refunds are issued to customers. The Company expects the refunds to customers to occur by mid-2009.

As a result of this order, PGE recorded, as a regulatory liability, the total refund due to customers of $33.1 million, which reduced 2008 revenues. The URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals. PGE is continuing to review and evaluate the order along with the subsequent appeals. The full text of OPUC Order No. 08-487 is available on its Internet website at www.puc.state.or.us.

Class Actions. In a separate legal proceeding, two class action suits were filed in Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million plus interest for the Current Class and $70 million plus interest for the Former Class, as a result of the inclusion of a return on investment of Trojan in the prices PGE charges its customers. On December 14, 2004, the judge granted the Class Action Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial judge to dismiss the complaints or to show cause why they should not be dismissed, and seeking to overturn the Class Certification. On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions for Alternative Writ of Mandamus, abating the class action proceedings until the OPUC responds to the 2003 Remand (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1995 through October 2000. The Oregon Supreme Court further stated that if the OPUC determines that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part, but if the OPUC determines that it cannot provide a remedy, and that decision becomes final, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings.

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On October 5, 2006, the Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions, but inviting motions to lift the abatement after one year. On October 17, 2007, the plaintiffs filed a motion to lift the abatement. A hearing on this motion was held on April 10, 2008. At the hearing, the Circuit Court declined to lift the abatement. The Circuit Court has encouraged the parties to attempt to agree on steps that might be taken in preparation for a trial in the event the Circuit Court lifts the abatement following the OPUC order issued on September 30, 2008. On June 3, 2008, the Circuit Court scheduled a status conference for October 15, 2008 and set a tentative trial date for April 2009. At the October 15, 2008 status conference, the Circuit Court set a schedule for the filing of briefs on the plaintiffs’ motion to lift the abatement. The schedule calls for the completion of briefing by November 25, 2008 and oral argument on January 12, 2009.

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

Regulatory Matters

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal from the Rosebud Mine in Montana under a Coal Supply Agreement and a Transportation Agreement with owners of Colstrip Units 3 and 4 coal plant (Colstrip), in which PGE has a 20% ownership interest. In 2002 and 2003, WECO received two orders from the Office of Minerals Revenue Management of the U.S. Department of the Interior (USDI) which asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip during the period October 1991 through December 2001. In late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additional royalties for the period January 2002 through December 2004. WECO has appealed the 2002 and 2003 orders and filed a Complaint for Declaratory and Injunctive Relief with the U.S. District Court for the District of Columbia challenging the decision of the Interior Board of Land Appeals to deny the appeal. In May 2005, WECO received a “Preliminary Assessment Notice” from the Montana Department of Revenue (MDOR), asserting claims similar to those of the USDI.

In October 2008, PGE and the other owners of Colstrip agreed with WECO to pay a portion of the taxes and royalties that WECO is required to pay to the MDOR and the USDI for both past and future periods. On October 23, 2008, WECO entered into an agreement with MDOR that settles all claims for years prior to 2008 and establishes a method for calculating taxes and royalties for subsequent periods. Management believes that PGE’s share of WECO’s obligation to pay royalties, taxes and interest to the USDI and MDOR for periods through September 30, 2008 would range from $2 million to $3 million. As of September 30, 2008, PGE has accrued $2.2 million related to this matter. The October 2008 agreements have not changed the Company’s assessment of its exposure for past periods.

PGE estimates that the Company’s share of royalties, taxes and interest for future periods will be approximately $0.2 million per year. The Company anticipates that amounts relating to future periods would be recovered through the ratemaking process. The Company will evaluate the likelihood of recovery through the ratemaking process of amounts relating to past periods. However, there can be no assurance that recovery of any amounts relating to past periods, if pursued, would be granted.

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Refunds on Wholesale Market Transactions

Pacific Northwest Refund Proceeding. On July 25, 2001, 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 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and declined to rule on the merits of the FERC’s ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, (California Refund case) et seq., approved by the FERC on May 17, 2007, resolves all claims as between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001, but does not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The Lockyer Case. In a separate but potentially related action, in 2002, the California Attorney General filed a complaint (the Lockyer case) with the FERC against various sellers in the wholesale power market, alleging that the FERC’s authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. Upon appeal of the FERC’s refusal to order refunds pursuant to the complaint, the Ninth Circuit remanded the case for further proceedings at the FERC to determine whether refunds should be ordered due to failure of parties to file correct and timely quarterly reports. PGE settled the Lockyer case with the California Attorney General and other California parties as part of its previously reported comprehensive settlement of the California Refund and related cases, which settlement became effective on May 17, 2007.

On December 10, 2007, the California Attorney General and others filed with the FERC a motion to suspend any Lockyer remand proceedings until the court issues mandates in the California Refund case and Pacific Northwest Refund proceeding on the basis that all three cases include similar parties and similar issues. They indicated their intent to file a motion to consolidate all three cases upon remand of the two that remain pending rehearing before the Ninth Circuit.

On March 21, 2008, the FERC issued an order on remand (Remand Order) that denied the California parties’ motion to suspend the Lockyer remand proceedings and set the case for further proceedings. On

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April 15, 2008, pursuant to a request for clarification filed by parties, including PGE, who had previously settled the Lockyer case with the California Attorney General and other California parties, the FERC issued an order that dismissed PGE from the Lockyer remand proceeding, which relates solely to California markets.

On October 6, 2008, the FERC denied a request for rehearing of the Remand Order, insofar as certain California Parties had requested that the remand proceedings be expanded to include issues beyond those raised by the inaccurate or untimely filing of quarterly transaction reports. On October 14, 2008, the California Attorney General and other California parties appealed the Remand Order and the order on rehearing to the Ninth Circuit Court of Appeals. PGE’s dismissal from the remand proceedings was not appealed and has become final.

Although PGE is no longer a party to the Lockyer remand proceedings, future consolidation of the Lockyer case with the Pacific Northwest Refund proceeding, on remand, could increase the Company’s potential liability in the Pacific Northwest proceeding by extending the period for which other parties are requesting refunds back to May 1, 2000, or earlier.

Management cannot predict the outcome of the Pacific Northwest Refund proceeding or Lockyer remand, if it is ever consolidated with the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in the Pacific Northwest, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and Ken Lewis (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of Oregon Senate Bill 408 (SB 408), PGE’s rates were not just and reasonable and were in violation of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes. PGE contended that no adjustment for taxes may be made prior to the January 1, 2006 effective date of the automatic adjustment clause included in SB 408.

On August 14, 2007, the OPUC issued an order granting the Application for Deferred Accounting for the period from October 5, 2005 through December 31, 2005 (Deferral Period). The OPUC’s order also dismissed the Complaint, without prejudice, on grounds that it was superfluous to the Complainants’ request for deferred accounting. The order required that PGE calculate the amounts applicable to the Deferral Period, along with calculations of PGE’s earnings and the effect of the deferral on the Company’s return on equity. The order also provided that the OPUC would review PGE’s earnings at the time it considers amortization of the deferral. PGE understands that the OPUC will consider the potential impact of the deferral on PGE’s earnings over a relevant 12-month period, which will include the Deferral Period.

On December 1, 2007, PGE filed its report as required by the OPUC. In the report, PGE determined that (i) the amount of any deferral would be between zero and $26.6 million; (ii) a relevant 12-month period would be the 12-month period ended September 30, 2006; and (iii) PGE’s earnings over such period would preclude any refund. The OPUC has indicated that it will determine whether any necessary rate adjustment should be made to amortize the deferral granted in its August 14, 2007 order.

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On October 15, 2007, PGE filed a petition for judicial review with the Oregon Court of Appeals, seeking review of the OPUC’s August 14, 2007 order. The Court of Appeals has granted PGE’s request to stay the proceedings pending an OPUC order in the matter.

Management cannot predict the ultimate outcome of this matter. However, based on the information currently known to management, it believes this matter will not have a material adverse effect on PGE’s financial condition, results of operations or cash flows.

FERC Investigation

In May 2008, PGE received a notice of a preliminary non-public investigation from the FERC Division of Investigations concerning PGE’s compliance with its Open Access Transmission Tariff. The investigation involves certain issues identified during an audit by FERC staff.

Management cannot predict the final outcome of the investigation or what actions, if any, the FERC will take or require the Company to take. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

Environmental Matters

Portland Harbor

Since 1973, PGE has operated the Harborton Substation on land owned by the Company located near the Willamette River. A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a 5.5 mile segment of the river, known as the Portland Harbor Superfund Site, revealed significant contamination of sediments within the harbor. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act.

The Portland Harbor Superfund Site is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several Potentially Responsible Parties (PRPs), not including PGE. In the AOC, the EPA determined the site for purposes of the RI/FS to be a segment of the river approximately 10 miles in length.

On January 22, 2008, PGE received a Section 104(e) Information Request from the EPA requiring the Company to provide information concerning its properties in or near the Portland Harbor Superfund Site being examined in the RI/FS, as well as several miles beyond that segment. PGE’s response is now due by the end of January 2009.

The boundaries of the site for remediation purposes will be determined at the conclusion of the RI/FS in a Record of Decision, in which the EPA documents its findings and selects a preferred cleanup alternative.

Sufficient information is currently not available to determine the total cost of any required investigation or remediation of the Portland Harbor or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

PGE has filed an application with the OPUC requesting deferred accounting, for later ratemaking treatment, of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Portland Harbor site. However, there can be no assurance that any recovery of these costs will be granted.

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Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company’s power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. On September 29, 2003, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for RI/FS from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter started a period for the PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance an RI/FS of the Harbor Oil site. On May 31, 2007, an Administrative Order on Compliance was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The EPA has approved an RI/FS work plan. On-site sampling was completed during the second quarter of 2008.

Sufficient information is currently not available to determine the total cost of investigation and remediation of the Harbor Oil site or the liability of the PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

PGE has filed an application with the OPUC requesting deferred accounting, for later ratemaking treatment, of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Harbor Oil site. However, there can be no assurance that any recovery of these costs will be granted.

Other Matters

PGE is subject to other regulatory and legal proceedings that arise from time to time in the ordinary course of its business, which may result in adverse judgments against the Company. Although management currently believes that resolving such matters will not have a material adverse effect on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties and management’s view of these matters may change in the future.

NOTE 8: GUARANTEES

PGE enters into financial and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise in connection with the transactions contemplated by these agreements. Generally, these indemnification provisions do not set a maximum obligation amount and therefore, the aggregate maximum amount of PGE’s obligations under these agreements cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities. Based on PGE’s historical experience and the evaluation of the specific indemnities, management believes the likelihood that PGE would be required to perform, or otherwise incur any significant losses, is remote.

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Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements relate to expectations, beliefs, plans, objectives for future operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions are intended to identify such 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 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 any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

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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.

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Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, its Annual Report on Form 10-K for the year ended December 31, 2007, and other periodic and current reports filed with the SEC.

Current Market Conditions - Turbulent capital market conditions during the third and early fourth quarter of 2008 have adversely affected both access to capital and the cost of capital in global markets. PGE is assessing the impact of these market conditions on its operations, which include, but are not limited to, the following:

For additional information with respect to these and other matters, see “Liquidity and Capital Resources” in this Item and Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Customers - During the nine months ended September 30, 2008, PGE served an average of 811,000 retail customers compared to 799,000 during the comparable period of 2007, an increase of 1.5%. This customer growth, along with generally cooler weather in 2008, resulted in a 3% increase in retail energy deliveries relative to 2007. On a weather adjusted basis, retail energy deliveries increased 1.5% from the comparable period of 2007.

A slow-down in the state’s economy, including a sustained decline in the housing market, continued through the third quarter of 2008. Oregon’s unemployment rate rose from 5.2% for 2007 to 5.8% through

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September 2008, compared to the national jobless rate of 5.4%. Despite the slow-down, Oregon had a 0.3% payroll growth compared to a national growth of 0.1% during the nine months ended September 30, 2008. PGE projects an approximate 1.5% increase in weather adjusted energy deliveries for 2008, with higher use by industrial customers projected during the last quarter of the year. PGE currently projects an approximate 1.9% increase in weather adjusted energy deliveries for 2009.

Regulatory review of the Company’s general rate case and proposed tariffs, filed with the OPUC in late February 2008, is continuing under procedural schedules that currently provide for new rates to become effective on January 1, 2009. PGE’s initial filing proposed an 8.9% average price increase related to higher purchased power and fuel costs, increased investment in utility plant, and higher operating expenses. Due to projections of increased costs of purchased power and fuel for the Company’s thermal generating plants subsequent to the initial filing, PGE has filed power cost updates reflecting additional projected power costs. PGE, OPUC staff, and interveners have reached stipulations on several items, including the method of determining estimated power costs and the cost of capital. The cost of capital stipulation provides for a debt-to-equity capital structure of 50/50 and a return on equity of 10.1%. The stipulated items and the power cost updates filed to date would result in a proposed average price increase of approximately 10%, consisting of increased revenue requirements of approximately $104 million for NVPC and $57 million for other costs. Certain customer credits, including those related to 2007 results of the Company’s Power Cost Adjustment Mechanism (PCAM), are expected to reduce the average price increase to approximately 8.4% effective January 1, 2009. The proposed increases remain subject to change until a final decision is made by the OPUC, which is expected in late December. Estimated 2009 NVPC will be updated in November 2008 according to a procedural schedule established by the OPUC. Additional information regarding PGE’s general rate case filing, including copies of direct testimony and exhibits, is available on the Company’s Internet website at www.portlandgeneral.com. Information may also be obtained on the OPUC Internet website at www.puc.state.or.us.

Installation of a limited number of new smart meters has begun as part of the smart meter project’s acceptance testing phase, with the remaining meters to be installed by the end of 2010 for residential and commercial customers. PGE expects the project to provide improved services as well as operational efficiencies and cost savings. A new tariff, effective from June 1, 2008 through December 31, 2010, provides for recovery of costs related to this project, including the net book value of existing meters, during this period.

Power Supply - PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. The Company’s generating plants provided approximately 60% of its retail load requirement during the nine months ended September 30, 2008, compared to 52% in the comparable period of 2007, primarily due to the addition of Port Westward and Biglow Canyon Phase I to the Company’s generation portfolio in June and December 2007, respectively. Current forecasts indicate near normal regional hydro conditions for 2008.

On August 15, 2008, PGE set a new all-time net system load “summer peak” (3,743 MW), driven by unusually warm weather and increased air conditioning demand, surpassing the previous record (3,706 MW) set on June 24, 2006. The Company’s all-time high net system load peak (4,073 MW) occurred in December 1998.

In March 2008, PGE executed agreements to purchase 141 wind turbines for Phases II and III of Biglow Canyon, and in July 2008, the Company entered into contracts for the related construction contracts. Construction of Phase II has begun, with completion expected by the end of 2009. Phase III is expected to be completed by the end of 2010. Total cost of the two phases is expected to be $730 million to $770 million, including allowance for funds used during construction (AFDC). The two phases will have a combined installed capacity of approximately 324 MW, further increasing the diversity of the Company’s generating resource portfolio while minimizing related environmental impacts. For further information regarding estimated future capital expenditures, see “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

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In April 2008, PGE issued a request for proposals for 218 MWa of renewable energy resources and identified an initial short list of bidders in September 2008. Such resources, which are in addition to Biglow Canyon, are required to become available between 2009 and 2014. The Company expects to identify a final short list by the end of the year and then begin negotiations.

As requested by the OPUC, PGE is currently preparing additional long-term analysis to address resource decisions beyond 2012, which the Company plans to include in a revised Integrated Resource Plan (IRP) to be filed by October 2009. PGE expects the updated and revised IRP to further define the Company’s future energy and capacity needs.

In an effort to secure additional renewable energy resources, the Company invested in its first photovoltaic solar power project during the third quarter of 2008 through a limited liability company. The project is located on property owned by the Oregon Department of Transportation, with a total cost estimated at approximately $1.3 million and an installed capacity of approximately 104 kW. On October 2, 2008, the Company invested in, through another limited liability company, an additional photovoltaic solar power project located on the rooftops of three distribution warehouses. The total cost of this facility is estimated at approximately $7.4 million, with an installed capacity of approximately 1,095 kW. Both of these projects are expected to be placed in service by December 31, 2008. Although PGE’s initial interest in each of these limited liability companies is less than 5%, PGE is the managing member and will operate both facilities pursuant to an operating agreement with the investor member. PGE expects to consolidate both entities pursuant to FASB Interpretation No. 46R, Consolidation of Variable Interest Entities.

Legal, Regulatory and Environmental Matters - On September 30, 2008, the OPUC issued an order in the matter of recovery of PGE’s investment in Trojan. The order requires PGE to refund $33.1 million to customers who received service during the period October 1, 2000 through September 30, 2001. For further information, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

In November 2007, PGE proposed to the Oregon Department of Environmental Quality (DEQ) controls that would address emissions from the Boardman coal plant. In August 2008, the DEQ issued a preliminary proposal that would require the installation of even more stringent emission controls, under a phased-in approach. For further discussion of this matter, see Air Quality Standards, in “Capital Requirements” under “Liquidity and Capital Resources” in this Item 2.

PGE is a party to other proceedings whose ultimate outcome could have a material impact on the results of operations and cash flows in future reporting periods. These include matters related to:

For further information regarding the above and other matters, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

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Recent and pending rate actions include, but are not limited to, the following: