PORTLAND GENERAL ELECTRIC CO /OR/ - Annual Report: 2008 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2008

OR

For the Transition period from              to             

Commission File Number 1-5532-99

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)

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, no par value

(Title of class)

New York Stock Exchange

(Name of exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 definition of “large accelerated filer,” “accelerated filer,” and “Smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

As of June 30, 2008, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $1,407,939,478. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 18, 2009, there were 62,575,257 shares of common stock outstanding.

Documents Incorporated by Reference

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PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2008

TABLE OF CONTENTS

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DEFINITIONS

The following abbreviations or acronyms used in the text and Notes to Consolidated Financial Statements are defined below:

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PART I

General

Portland General Electric Company (PGE or the Company) is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. PGE operates as a cost-based, regulated electric utility. PGE’s revenue requirements are determined based upon the forecast cost to serve retail customers, including an opportunity to earn a reasonable rate of return. PGE also participates in the wholesale market by purchasing and selling electricity and natural gas to utilities and energy marketers in order to balance its supply of power to meet the needs of retail customers and manage its net variable power costs (NVPC). 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 was incorporated in 1930 and is publicly-owned, with its common stock listed on the New York Stock Exchange under the ticker symbol “POR.” The Company was a wholly-owned subsidiary of Enron Corp. (Enron) for the period from July 1, 1997 through April 3, 2006.

In 1997, Portland General Corporation, the former parent of PGE, merged with Enron, with Enron continuing in existence as the surviving corporation and PGE operating as a wholly-owned subsidiary of Enron. In December 2001, Enron, along with certain of its subsidiaries (collectively “Debtors”), filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. PGE was not included in the filing. On April 3, 2006, in accordance with Enron’s Chapter 11 plan, PGE’s 42.8 million shares of common stock held by Enron were canceled, PGE issued 62.5 million of new shares of common stock, with 27 million shares issued to the Debtors’ creditors holding allowed claims and 35.5 million shares issued to a Disputed Claims Reserve, and PGE and Enron entered into a separation agreement. PGE ceased to be a subsidiary of Enron. On June 18, 2007, the Disputed Claims Reserve sold substantially all of its remaining holdings of PGE stock in a public offering.

PGE’s state-approved service area allocation of approximately 4,000 square miles is located entirely within Oregon and includes 52 incorporated cities, of which Portland and Salem are the largest. The Company estimates that at the end of 2008 its service area population was 1.6 million, comprising about 43% of the state’s population. The Company added 6,409 retail customers during 2008, and as of December 31, 2008 served 810,197 retail customers.

As of December 31, 2008, PGE had 2,753 employees, with 888 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (Local 125). Such agreements cover 854 and 34 employees for the five-year periods ending February 28, 2009 and August 1, 2011, respectively. PGE is in negotiations with Local 125 for a new agreement to replace the one scheduled to expire February 28, 2009. The existing agreement will remain in effect following the expiration date unless either party gives at least 60 days’ written notice of termination.

Available Information

The Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available and may be accessed free of charge through the Investors section of the Company’s Internet website at www.portlandgeneral.com as soon as

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reasonably practicable after the reports are electronically filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). It is not intended that the Company’s website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K. Information may also be obtained via the SEC Internet website at www.sec.gov.

Regulation and Rates

PGE is subject to federal and state regulation, both of which can have a significant impact on the business and operations of the Company. In addition to those activities and agencies discussed below, the Company is subject to regulation by certain environmental agencies, as described in “Environmental Matters” in this Item 1.

Federal Regulation

PGE is subject to federal regulation by the Federal Energy Regulatory Commission (FERC) and by the Nuclear Regulatory Commission (NRC).

FERC Regulation

The Company is a “licensee” and a “public utility,” as defined in the Federal Power Act, and is subject to regulation by the FERC as to accounting policies and practices, licensing of hydroelectric projects, transmission services, wholesale sales, issuance of short-term debt, and certain other matters. The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation.

Wholesale - PGE has authority under its FERC tariff to charge market-based rates for wholesale energy sales made to other utilities and energy marketers. Under FERC Order 697, Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, re-authorization for continued use of market-based rates requires the filing of updated market studies on a regional schedule. PGE’s current authorization is effective until June 2010, at which time the Company, as part of the western region, will file for re-authorization.

Transmission - Terms and conditions related to the transmission of electric energy are contained in PGE’s Open Access Transmission Tariff (OATT), which is filed with the FERC. In 2007, the FERC issued Order 890, Preventing Undue Discrimination and Preference in Transmission Services, which includes requirements for greater specificity and transparency in the OATT and for enhanced coordination of transmission planning. PGE has submitted filings to incorporate into its OATT the requirements of the order. FERC Order 693, Mandatory Reliability Standards for the Bulk-Power System, issued in 2007, approved mandatory reliability standards developed by the North American Electric Reliability Corporation (NERC). Responsibility for compliance and enforcement of these standards has been given to the Western Electricity Coordinating Council (WECC), a regional electric reliability organization.

Pipeline - The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide FERC authority in matters related to extension, enlargement, safety, and abandonment of jurisdictional pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority due to the Company’s 79% ownership interest in the 17-mile interstate pipeline that provides natural gas to its Port Westward and Beaver plants.

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Hydroelectric Licensing - Under the Federal Power Act, PGE’s hydroelectric generating plants are subject to FERC licensing requirements. Such requirements include an extensive public review process that involves numerous natural resource issues and environmental conditions. PGE holds FERC licenses for the Company’s projects on the Deschutes and Willamette Rivers and is currently in the process of relicensing its four hydroelectric projects on the Clackamas River.

NRC Regulation

The NRC regulates the licensing and decommissioning of nuclear power plants. In 1993, the NRC issued a possession-only license amendment to PGE’s operating license for the Trojan Nuclear Plant (Trojan), and in early 1996 approved the Trojan Decommissioning Plan, which has allowed PGE to proceed in decommissioning the plant. The NRC approved the completed transfer of spent nuclear fuel from the Trojan spent fuel pool to a separately licensed dry cask storage system that will house the nuclear fuel on the plant site until permanent storage is available. PGE completed the radiological decommissioning of the Trojan site in 2004 pursuant to an NRC-approved License Termination Plan, with the plant’s Facility Operating License terminated by the NRC in 2005. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site and the storage installation is fully decommissioned.

State of Oregon Regulation

PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC), which is comprised of three members appointed by Oregon’s governor to serve non-concurrent four-year terms. The OPUC reviews and approves the Company’s retail prices (see “Ratemaking” below) and establishes conditions of utility service. In addition, the OPUC regulates the issuance of stock and long-term debt, prescribes accounting policies and practices, and reviews applications to sell utility assets, engage in transactions with affiliated companies, and acquire substantial influence over a public utility. The OPUC also reviews the Company’s generation and transmission resource acquisition plans, pursuant to an integrated resource planning process.

Oregon’s Energy Facility Siting Council (EFSC) has regulatory and siting responsibility for large electric generating facilities, high voltage transmission lines, gas pipelines, and radioactive waste disposal sites. The EFSC also has responsibility for overseeing the decommissioning of Trojan. Members of the EFSC are appointed by the state’s governor, with staff support provided by the Oregon Department of Energy.

Ratemaking - Under Oregon law, the OPUC is required to ensure that the prices and terms of service are fair, non-discriminatory, and provide regulated companies an opportunity to earn a fair return on their investments. Customer prices are determined through formal rate proceedings that generally include testimony by participating parties, data requests, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, include PGE, OPUC staff, and interveners.

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Other ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific OPUC authorization. Such amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs.

Utility Rate Treatment of Income Taxes - In 2005, Oregon adopted Senate Bill 408 (SB 408). The law attempts to more closely match income tax amounts forecasted to be collected in revenues with the amount of income taxes paid to governmental entities by electric and natural gas investor-owned utilities or their consolidated group. The law requires that utilities file a report with the OPUC each year regarding the amount of taxes paid by the utility (with certain adjustments), as well as the amount of taxes authorized to be collected in rates, as defined by the statute. This report is filed by October 15th of the year following the reporting year. If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to adjust future rates, with a regulatory asset or liability recorded for the total amount (including accrued interest) to be collected from, or refunded to, retail customers. The first adjustment under SB 408 applied to taxes paid to governmental entities and collected from customers on or after January 1, 2006.

Application of the provisions of SB 408 can, in certain situations, result in unusual outcomes, commonly termed the “double whammy” effect. As the provisions of the law apply to PGE, if the Company records higher operating income as compared to its latest general rate case, customers are surcharged for the increase in income taxes, further increasing earnings. Conversely, if the Company records lower operating income as compared to its latest rate case, customers would receive refunds for the decrease in income taxes, further decreasing earnings.

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For further information, see Note 6, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements.

Oregon Renewable Energy Act - Enacted in 2007 by the Oregon legislature, the Oregon Renewable Energy Act (the Act) established a Renewable Energy Standard which requires that utilities meet specified percentages of their Oregon retail load with electricity generated by renewable resources by certain dates. PGE and other large electricity providers are required to serve at least 5% of their retail load within the state from renewable resources from 2011 through 2014, 15% for 2015 through 2019, 20% for 2020 through 2024, and 25% in 2025 and subsequent years. PGE anticipates that it will meet the 2011 requirement of the Act with existing or currently planned renewable resources. Further, the Company expects that, with additional resources included in its current planning process, it will meet the 2015 requirement. It is anticipated that subsequent years’ requirements will be met by the acquisition of additional renewable resources, as determined pursuant to the Company’s integrated resource planning process. For further information, see Power and Fuel Supply in this Item 1.

The Act also provides for the recovery in customer rates of all prudently incurred costs required to comply with the Renewable Energy Standard. The OPUC has approved the establishment of a renewable adjustment clause mechanism (RAC), which became effective January 1, 2008. Under the RAC, PGE will submit a filing on April 1 of each year, with rates to become effective January 1 of the following year, to recover the revenue requirement of new renewable resources and associated transmission that are not yet reflected in general rates. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in rates until the next annual RAC filing.

Retail Customer Choice Program - Implemented in 2002 as part of Oregon’s electricity restructuring law, the retail “customer choice” program allows the Company’s commercial and industrial customers direct access to other suppliers of electricity (Electricity Service Suppliers, or ESSs). While “direct access” customers purchase their electricity from other suppliers, PGE continues to deliver the energy to these customers. The program provides for “transition adjustments” for customers that choose to purchase energy at market prices from investor-owned utilities or from ESSs. Such adjustments reflect the above-market or below-market cost of energy resources owned or purchased by the utility and are designed to ensure that such costs or benefits do not unfairly shift to the utility’s remaining energy customers. The retail customer choice program has no material effect on the financial condition or results of operation of the Company. During 2008, ESSs supplied customers with a total average load of approximately 269 MWa, representing 20% of PGE’s non-residential load and 12% of the Company’s total retail load for the year. In early 2009, the three ESSs registered to transact business with PGE supplied a total of 28 customers, representing 214 accounts, with a total average load of approximately 222 MWa, representing 16% of the Company’s non-residential load and 10% of total retail load.

Cost-of-service and market price options are also available to PGE’s commercial and industrial customers. The Company offers an option by which certain large non-residential customers may, for a minimum three- or five-year term, elect to be removed from cost-of-service pricing, with energy supplied by an ESS or at a daily market rate by PGE. A total of 32 commercial and industrial customers, less than 1% of those eligible, were receiving service from PGE under market-based pricing options at the end of 2008.

Residential and small commercial customers can purchase electricity from PGE from a portfolio of rate options that include a basic cost-of-service rate, a time-of-use rate, and renewable resource rates. As of December 31, 2008, approximately 71,000 customers were enrolled in renewable energy options, with 2,100 enrolled in time-of-use options.

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Energy Efficiency Funding - Oregon’s electricity restructuring law also provides for a “public purpose charge” to fund cost-effective energy efficiency measures, new renewable energy resources, and weatherization measures for low-income housing. This charge, equal to 3% of retail revenues, is collected from customers and remitted to the Energy Trust of Oregon (ETO) and other agencies for administration of these programs. In 2008, approximately $47 million in such charges were billed to customers.

PGE also remits to the ETO amounts collected under a new Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. The tariff, which became effective on June 1, 2008, includes an approximate 1% average price increase and is expected to provide about $14 million annually for measures that enable customers to reduce their energy use.

Regulatory Accounting

PGE is subject to the provisions of Statement of Financial Accounting Standards No. (SFAS) 71, Accounting for the Effect of Certain Types of Regulation, and currently applies its provisions to reflect the effects of rate regulation in its financial statements. The Company periodically assesses the applicability of the statement to its business, considering both the current and anticipated future rate environment and related accounting guidance. For further information, see “Regulatory Assets and Liabilities” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements.

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Customers and Revenues

PGE conducts retail electric operations exclusively in Oregon within a state-approved service area. Competitors within the Company’s service territory include the local natural gas company, which competes in the residential and commercial space heating, water heating, and appliance markets, and fuel oil suppliers, which compete primarily for residential space heating customers. In addition, commercial and industrial customers may choose to purchase their energy requirements from ESSs, in accordance with Oregon’s electricity restructuring law.

The following table summarizes PGE’s revenues for the years indicated, with certain averages for retail customers (excluding direct access customers) (dollars in millions, except as indicated):

For further information, see “Results of Operation” in Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

Retail

Residential customers comprised 88% of the Company’s total customers as of December 31, 2008 and 2007, with the remainder consisting of commercial and industrial customers. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating season, and the condition of the economy. Generally, a 1% increase in Oregon’s unemployment rate results in an approximate 0.7% decrease in demand from the Company’s residential customers.

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Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest customers constitute 6% of total retail revenues, they represent nine different commercial and industrial groups, including high technology, paper manufacturing, metal fabrication, health services, and governmental agencies. No single customer represents more than 5% of PGE’s total retail load or 2% of total retail revenues. While demand by the Company’s commercial and industrial customers is generally not affected by weather, these classes can be affected by employment. Generally, a 1% decrease in Oregon’s employment rate results in an approximate 0.4% decrease in demand from the Company’s commercial and industrial customers.

PGE’s direct access customers consist of commercial and industrial customers who purchase their electricity from an ESS, with PGE delivering the electricity. The revenue earned in connection with the transmission and delivery of this electricity is included in Other retail revenue, net of transition adjustments. PGE served an average of 417 direct access customer accounts in 2008, 322 in 2007, and 239 in 2006.

Residential Exchange Program (REP) - In May 2007, the Bonneville Power Administration (BPA), which provides federal hydropower benefits under the REP, suspended payments under the program to investor-owned utilities, which meant that monthly payments in a total expected annual amount of $76.5 million to PGE were suspended. Because PGE passes REP payments along to its residential and small farm customers in the form of monthly billing credits, the suspension had no net income impact to the Company, but resulted in an approximate 14% average price increase to those customers.

In April 2008, the BPA partially restored benefits on a temporary basis. As a result, prices for residential and small farm customers were reduced by an average of 6.3%. The BPA provided $43 million in interim benefits to the Company, the majority of which was credited to customers by the end of 2008.

In September 2008, the BPA and PGE, as ordered by the OPUC, entered into an agreement, terminating on September 30, 2011, that will provide monthly payments totaling approximately $40 million over the 12-month period ending September 30, 2009. Such benefits will be credited to eligible customers. Remaining benefits under the agreement will be based upon certain power exchange rates and other amounts to be determined in BPA proceedings.

PGE will continue to pursue ongoing benefits for its customers. Various parties have challenged the agreements under which the BPA will provide the future benefits to the customers of investor-owned utilities, including PGE, and others who purchase electricity directly from the BPA.

Wholesale

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. The Company’s wholesale market participation includes purchases and sales of power resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers, and purchases and sales of natural gas. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, water conditions, and seasonal demand.

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The majority of PGE’s wholesale sales are to utilities and power marketers and are predominantly short-term. The Company may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power, with only the net amount of those purchases or sales required to meet retail and wholesale obligations physically settled.

Other

Other includes sales of natural gas or oil in excess of generating plant requirements and revenues from transmission services, pole contact rentals, and certain other electric services to customers.

Seasonality

Demand for electricity by residential customers is affected by weather. Retail customer demand is typically highest in the winter across PGE’s service territory when heating and lighting are heavily used. Customer demand also peaks in the summer months primarily due to the use of air conditioning. Within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns for residential customers.

Heating degree-days is an indication of the likelihood that customers will use heating and cooling degree-days is an indication of the likelihood that customers will use air conditioning. Heating and cooling degree-days data is used to measure the effect of weather on the demand for electricity. A degree-day is measured by the difference between a base temperature of 65 degrees Fahrenheit and the average temperature for a given day. The following table indicates the heating and cooling degree-days for 2008, 2007 and 2006, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

PGE’s all-time high net system load peak was 4,073 MW and occurred in December 1998. The Company’s all-time “summer peak” was 3,743 MW, which was driven by unusually warm weather and increased air conditioning demand, and occurred in August 2008. For 2008, PGE’s peak load was 4,031 MW, which occurred in December. PGE’s average load was 2,623 MW for the winter and 2,324 MW for the summer in 2008, compared to 2,638 MW for winter and 2,271 MW for summer in 2007.

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Power and Fuel Supply

Power Supply

PGE relies primarily upon its generating resources, as well as long- and short-term power purchase contracts, to meet its customers’ energy requirements. The Company also continues to emphasize the expansion of renewable energy resources, as well as energy efficiency measures, to meet such needs and enhance customers’ ability to manage their energy use more efficiently. The following table summarizes PGE’s average resource capability (in MW) for the last three years:

That portion of PGE’s energy requirements generated by its plants will vary from year to year and is determined by various factors, including planned and forced outages, availability and price of coal and natural gas, precipitation and snow-pack levels, and the market price of electricity. For information regarding actual generating output and purchases for the period 2006-2008, see the Results of Operation section of Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

Generation

PGE’s current generating portfolio consists of thermal, hydro, and wind resources. For a complete listing of these facilities, see Item 2. - “Properties.”

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Dispatchable Standby Generation (DSG) - PGE has a DSG program under which the Company can start, operate, and monitor customer-owned standby generators when needed to meet peak demand. The program helps provide operating reserves for the Company’s generating resources and, when operating, can supply most or all of DSG customer loads. As of December 31, 2008, there were 23 projects that together provide approximately 48 MW of diesel-fired capacity at peak times.

Purchased Power

PGE supplements its own generation with long- and short-term wholesale contracts as needed to meet its retail load requirement and provide the most economic mix on a variable cost basis. Such contracts have terms ranging from one to 30 years and expire at varying dates through 2035. The following briefly describes the Company’s major power purchase contracts:

Capacity/exchange - These contracts provide PGE with firm capacity to help meet the Company’s peak loads. The contracts range from 30 MW to 300 MW and expire at various dates from 2009 through 2016. They include seasonal exchange contracts with other western utilities that help meet both winter- and summer-peaking requirements.

Mid-Columbia hydro - PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of four hydroelectric projects on the mid-Columbia River. The projects currently provide a total of 545 MW of firm capacity. Under terms of its contract with one of the districts, the Company’s share of the combined output of two of the projects is expected to decline from the current 233 MW to an estimated 158 MW in 2010 as the energy requirements of the district increase.

Confederated Tribes - PGE has a two-thirds ownership interest in the 450 MW Pelton/Round Butte hydroelectric project on the Deschutes River in central Oregon, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. PGE has a long-term agreement that requires the Company to purchase, at market prices, the Tribes’ interest in the output of the project during the term of the license.

Wind - The Company has two long-term contracts, which extend to 2028 and 2035, that provide for the purchase of renewable wind-generated electricity.

Other - These consist of long-term contracts to purchase power from various counterparties, including other Pacific Northwest utilities, over terms extending up to 2018.

Short-term contracts - These contracts are for delivery periods of one month up to one year in length. They are entered into with various counterparties to provide additional firm energy to help meet the Company’s load requirement.

For further information regarding PGE’s power purchase contracts, see Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements.

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Solar - As part of its efforts to secure additional renewable energy resources, PGE has invested in two photovoltaic solar power projects through separate limited liability companies. The first project, with an installed capacity of approximately 104 kW, is located on property owned by the Oregon Department of Transportation. The second project, with a total installed capacity of approximately 1,095 kW, is located on the rooftops of three distribution warehouses in Portland. The projects were placed in service in December 2008 and January 2009. PGE serves as managing member for the limited liability companies, in which it has an initial interest of less than 1%, and operates both facilities under an agreement with the investor member.

Fuel Supply

PGE contracts for natural gas and coal supplies required to fuel the Company’s thermal generating plants, with certain plants also able to operate on fuel oil if needed. In addition, the Company uses forward, swap, option, and futures contracts to manage its exposure to volatility in natural gas prices.

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Reliability

PGE’s base of thermal, hydroelectric, and wind generating resources, along with wholesale power market products, currently provides the Company with the flexibility to respond to seasonal fluctuations in the demand for electricity from its retail and wholesale customers. PGE anticipates that generating capacity within the WECC, as well as an active wholesale market, will continue to provide sufficient supply to supplement the Company’s generation and long-term power contracts. To meet anticipated future energy requirements and help assure continued system reliability, PGE utilizes an integrated resource planning process for acquisition of new supply. The process incorporates input from several sources and includes long-term projections of resource adequacy prepared by both PGE and the WECC.

Integrated Resource Plan

PGE’s Integrated Resource Plan (IRP), required by the OPUC, describes the Company’s energy supply strategy. The primary goal of the IRP is to identify an acquisition plan for generation, transmission, demand-side and energy efficiency resources that, along with the Company’s existing portfolio, provide the best combination of expected cost and associated risks and uncertainties for PGE and its customers.

PGE filed an IRP with the OPUC in June 2007 covering the years 2008 through 2015. It proposed additional energy efficiency programs as well as renewable and demand-side resources. It also proposed power purchase agreements of varying terms and the acquisition of additional peaking capacity.

The OPUC did not officially acknowledge the Company’s IRP, but found key elements of the plan to be reasonable and directed PGE to proceed with a Request for Proposal (RFP) for up to 218 MWa of new renewable resources. PGE issued the RFP in 2008 and developed a final short list of proposals in November, with negotiations expected to be completed in 2009. PGE began construction of Phases II and III of Biglow Canyon and proceeded with its proposed expansion of energy efficiency programs. Also during 2008, PGE began evaluating proposals received in response to an RFP issued for 50 MW of demand response measures, with agreements expected to be completed in 2009.

As requested by the OPUC, PGE has begun preparation of a new IRP that addresses resource requirements through 2020. PGE expects to file the updated IRP by late 2009.

Transmission and Distribution

PGE operates one balancing authority area in its service territory. A balancing authority area is an electric system bounded by interchange metering. PGE is responsible for continuously balancing electric supply to its customers with PGE’s generated power and the power the Company purchases and sells with other entities so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PGE also schedules deliveries of energy over its transmission system in accordance with FERC requirements.

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Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. During the year ended December 31, 2008, PGE delivered approximately 21.4 million MWh to retail and wholesale customers in its balancing authority area through approximately 1,100 miles of transmission lines.

PGE’s transmission system is part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of 11 western states, two Canadian provinces and parts of Mexico, and it is subject to the reliability rules of the WECC and the NERC. PGE’s transmission system, together with contractual rights on other transmission systems, enables the Company to integrate and access generation resources to meet its customers’ load requirements. PGE’s generation is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of the Company’s transmission and distribution systems are located:

PGE’s wholesale transmission services are regulated by the FERC pursuant to the Company’s OATT, which is filed with the FERC and provides for market-based rates. In accordance with its OATT, PGE offers several transmission services to wholesale customers:

These services are offered on a non-discriminatory basis, with all potential customers provided an equal opportunity to access PGE’s transmission system. PGE’s transmission business is managed and operated independently from the power marketing business in accordance with the FERC’s Standards of Conduct.

PGE is currently considering several generation interconnection projects (collectively referred to as the “Southern Crossing Project”) under the Company’s OATT. The Southern Crossing Project is being designed to integrate several of PGE’s generation resources to include Boardman and Coyote Springs and other proposed wind and thermal generation projects. The addition of these generation resources necessitates the development of a significant, new, high-voltage transmission system across the Oregon Cascades to PGE’s service territory. The Company is working closely with other utilities and the WECC to coordinate the Southern Crossing Project.

For additional information, see the Transmission and Distribution section of Item 2. - “Properties.”

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Environmental Matters

PGE operates in a state that is recognized for its environmental leadership and awareness. Accordingly, the Company’s policy of environmental stewardship seeks to minimize risk and waste in its operations and promote the efficient use of energy.

PGE’s operations are subject to a wide range of environmental protection laws, including those related to air and water quality, noise, waste disposal, endangered species, and climate change. The U.S. Environmental Protection Agency (EPA) and certain state agencies, including the Oregon Environmental Quality Commission (OEQC), the Oregon Department of Environmental Quality (DEQ), the Oregon Department of Energy, and the EFSC, have direct jurisdiction over environmental matters that include the siting and operation of generation and transmission facilities and the accumulation, cleanup, and disposal of toxic and hazardous substances. In addition, the Company’s hydroelectric facilities are regulated and licensed by the FERC and are, in some cases, located on property under the jurisdiction of the U.S. Forest Service, which has authority over environmental protection in those cases.

Clean Air Standards

Clean Air Act - PGE’s operations, principally its thermal generation plants, are subject to the federal Clean Air Act (CAA). Primary pollutants addressed by the CAA that affect PGE are sulfur dioxide (SO₂), nitrogen oxides, carbon monoxide, and particulate matter. State governments also monitor and administer certain portions of the CAA and must set standards that are at least equal to federal standards. Oregon’s air quality standards currently equal or exceed federal standards.

PGE manages its air emissions by the use of low sulfur fuel, emission controls, emission monitoring, and combustion controls. The SO₂ emissions allowances awarded under the CAA, along with expected future annual allowances, are anticipated to be sufficient to permit the Company to operate its thermal generation plants at forecasted capacity for at least the next several years within the limitations of current SO₂ emission requirements.

Clean Air Mercury Rule - The federal government adopted the Clean Air Mercury Rule in 2005 to regulate mercury air emissions from coal-fired generating plants. That rule was vacated by an appellate court decision in 2008; however, the states in which PGE facilities are located have adopted the following regulations concerning mercury emissions that could have an impact on the Company’s Boardman and Colstrip plants:

Regional Haze - In accordance with federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ conducted an assessment of emission sources that has

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indicated that the Boardman generating plant may cause or contribute to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination.

In December 2008, the DEQ issued a proposed plan that would require the installation of controls at Boardman in three phases. PGE estimates that the DEQ plan would cost between $575 million and $636 million (100% of total costs, excluding AFDC, in nominal dollars). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change.

The comment and public input period for the DEQ proposed plan has closed. PGE commented with an alternative BART/Reasonable Progress proposal that would allow for decision points along the DEQ timeline to provide flexibility to make the most responsible decision on future controls at those points. The OEQC is expected to adopt a rule in April 2009 now that the public process has been completed. The rule will be submitted to the EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The Company expects the EPA to issue a decision on the SIP in early 2010.

Climate Change

Greenhouse gas emissions and their potential impacts on climate change have recently received increased public attention, with several legislative efforts initiated to establish mandatory control of greenhouse gas emissions. PGE is participating as a stakeholder in the Western Climate Initiative, a regional accord with a stated goal of reducing greenhouse gas emissions to 15% below 2005 levels by the year 2020. The DEQ, also a participant in the regional accord, has issued a notice of advanced rulemaking that would require reporting of greenhouse gas emissions for stationary sources. Any future laws that impose mandatory reductions in greenhouse gas emissions could have a material impact on PGE, as the Company relies on fossil fuels as a resource for power generation. PGE’s Beaver, Coyote Springs, and Port Westward natural gas fired facilities and the Company’s ownership shares of the Boardman and Colstrip coal plants provide nearly 75% of the Company’s net generation capability.

Water Quality and Endangered Species Protection

Populations of many migratory fish species in the Pacific Northwest have declined significantly over the last several decades. Many of these distinct populations have been granted protection under the federal Endangered Species Act (ESA). Long-term recovery plans for these species include major operational changes to the region’s hydroelectric projects. Significant changes thus far include modification in the timing of stored water releases, a spill program to assist juvenile fish at federal dams located in the Columbia River and Snake River basins, and continued investment in fish protection infrastructure (ladders and screens). These changes have resulted in occasional reductions in hydroelectric generation capability and the seasonal shifting of other generation from the fall and winter periods to the spring and summer periods. While PGE does not own facilities on these rivers, the Company does have contracts for power generated at facilities on the mid-Columbia River in central Washington and may be adversely affected by such reductions and seasonal shifting at those facilities. The timing of stored water releases also has an influence on the availability and prices of power in the regional wholesale market in which PGE participates to acquire adequate power to serve its retail customers.

PGE is implementing a series of fish protection measures at its hydro generation facilities on the Clackamas, Deschutes, and Willamette rivers that were prescribed by the U.S. Fish and Wildlife

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Service and the National Marine Fisheries Service under their authority granted in the ESA and are contained in the Company’s FERC operating licenses.

In accordance with a 2002 agreement with state and federal agencies, environmental groups, and others, PGE is proceeding with decommissioning the Company’s 22 MW Bull Run hydroelectric project, which included the Marmot and Little Sandy dams, located in the Sandy River basin. During 2008, the project ceased generation, as planned. Decommissioning and removal of project facilities continues in accordance with a FERC Surrender Order issued in 2004.

Hazardous Waste

PGE has a comprehensive program to comply with requirements of both federal and state regulations related to hazardous waste storage, handling and disposal. The handling and disposal of hazardous waste from PGE facilities is subject to regulation under the federal Resource Conservation and Recovery Act. In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, is regulated by the federal Toxic Substances Control Act.

PGE is also subject to regulation under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA), referred to as Superfund. CERCLA can assert joint and several liability for investigation and remediation costs for designated Superfund sites. PGE is currently listed by the EPA as a Potentially Responsible Party (PRP) at two Superfund sites discussed below.

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (USDOE) is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel for Trojan. Trojan spent nuclear fuel is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel at the plant site until the permanent off-site storage is available. No federal repository is expected to be available until 2020. Shipment of the spent nuclear fuel stored in the ISFSI to the off-site storage is not expected to be completed prior to 2033.

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EPA Actions

Portland Harbor - A 1997 investigation by the EPA of a segment of the Willamette River, known as the Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to CERCLA and listed sixty-nine PRPs, including PGE.

The Portland Harbor is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs, not including PGE. In the AOC, the EPA determined that the RI/FS would focus on a segment of the river approximately 5.7 miles in length.

In January 2008, PGE received a request from the EPA requiring the Company to provide information concerning its properties in or near the area being examined in the RI/FS, as well as several miles beyond that 5.7 mile segment. PGE requested, and the EPA has granted, an extension to August 2009 to respond. The boundaries of the site will be determined at the conclusion of the RI/FS in a Record of Decision, expected in 2010, in which the EPA will document its findings and select a preferred cleanup alternative.

Harbor Oil - In 2005, PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site, located in north Portland. The site includes the location of a company, Harbor Oil, Inc., that PGE utilized to process used oil from power plants and electrical distribution systems until 2003. The Harbor Oil facility continues to be utilized by other entities for the processing of used oil and other lubricants. The EPA has approved an RI/FS work plan for the site and on-site sampling commenced in 2008.

For further information on EPA actions, see “Environmental Matters” in Note 18, Contingencies, in the Notes to Consolidated Financial Statements.

Certain risks and uncertainties that may affect PGE’s business, financial condition, results of operation or cash flows, or that may cause the Company’s actual results to vary from the forward-looking statements contained in this Annual Report on Form 10-K, include those set forth below.

Recovery of PGE’s costs is subject to regulatory review and approval, and the inability to recover costs may adversely affect the Company’s results of operation.

The prices that the OPUC authorizes PGE to charge for its retail services are the major factor in determining the Company’s operating income, financial position, liquidity, and credit ratings. The OPUC has the authority to disallow recovery of any costs that it considers excessive or imprudently incurred. Furthermore, the regulatory process does not provide assurance that PGE will be able to achieve the earnings level authorized. In PGE’s most recent general rate case, the Company’s initial proposal included an overall rate increase of 8.9%, compared to a 7.3% overall increase approved by the OPUC. The Company will seek to manage costs at levels consistent with the reduced rate increase. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the reduced rate increase could adversely affect the Company’s operations or results of operations. For further information, see the Overview section of Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

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Currently, PGE utilizes a PCAM by which the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted and actual NVPC. Use of the approved cost sharing methodology requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, application of the PCAM is expected to only partially mitigate the potentially adverse financial impact of forced generating plant outages, severe weather, reduced hydro availability, and volatile wholesale energy prices.

The current capital and credit market conditions may adversely affect the Company’s access to capital, cost of capital, and ability to execute its business plan as scheduled.

Access to capital markets is important to PGE’s ability to operate. The Company will face significant capital requirements for several large projects in the near term and expects to issue both debt and equity in 2009 in order to fund such projects. In addition, because of contractual commitments and regulatory requirements, the Company has limited ability to delay or terminate these projects, which include Biglow Canyon and the smart meter project. For further information concerning PGE’s capital requirements, see “Capital Requirements” in the Liquidity and Capital Resources section of Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

Recently, the general economic and capital market conditions in the United States and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If these conditions continue or become worse, the Company’s future cost of debt and equity capital and access to capital markets could be adversely affected. In addition, restrictions on PGE’s ability to access capital markets could affect its ability to execute its business plan as scheduled.

The current economic downturn has reduced the demand for electricity and has impaired the financial soundness of customers, which has adversely affected PGE’s results of operation and could continue to do so. The economic downturn could also impair the financial soundness of the Company’s vendors and service providers.

The slowing of the Oregon and national economies has resulted in reduced demand for electricity and could result in a continued reduction in such demand. This reduced demand has decreased the Company’s earnings and cash flow and could continue to do so. In Oregon, the economic slow-down has included a sustained decline in the housing market and rising unemployment. Oregon’s unemployment rate rose from an average of 5.2% for 2007 to an average of 6.3% for 2008, compared to the national average unemployment rate of 5.8%. Oregon’s seasonally-adjusted unemployment rate increased to 9% in December 2008.

In addition, the Company’s uncollectible customer accounts increased in the fourth quarter of 2008. If customers are not successful in generating sufficient revenue or are precluded from securing financing, they may not be able to pay, or may delay payment of, amounts owed to the Company. Any further inability of customers to pay the Company could adversely affect the Company’s earnings and cash flow.

Furthermore, as a result of the current economic downturn affecting the economies of the state of Oregon, the United States and other parts of the world, the Company’s vendors and service providers could experience serious cash flow problems. As a result, PGE’s vendors and service providers may be unable to perform under existing contracts or may significantly increase their prices or reduce their output or performance on future contracts.

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PGE faces regulatory and litigation risk with respect to recovery of the Company’s investment in the closed Trojan Nuclear Plant.

There remains uncertainty regarding the ultimate outcome of legal and regulatory proceedings related to PGE’s recovery of its investment in Trojan, which was closed in 1993. With respect to the OPUC proceedings, the Utility Reform Project (URP) and the class action plaintiffs have separately appealed, to the Oregon Court of Appeals, the September 30, 2008 OPUC order requiring PGE to refund $33.1 million to customers. With respect to the class actions, the Circuit Court has not yet ruled on the plaintiffs’ motion to lift the abatement of the class action proceedings. The outcome of these proceedings could have a material adverse affect on PGE’s results of operation and liquidity. For further information regarding Trojan legal and regulatory proceedings, see “Legal Matters” in Note 18, Contingencies, in the Notes to Consolidated Financial Statements and Item 3. - “Legal Proceedings.”

Adverse market performance could result in further reductions in the fair market value of benefit plan trust assets and increase the Company’s liabilities related to such plans. Such changes could result in a significant increase in funding requirements.

Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under the Company’s pension plan. Sustained adverse market performance, such as the losses in market value that reduced the value of the Company’s pension plan trust assets in 2008, may result in lower rates of return for these assets than projected by the Company and could increase PGE’s funding requirements related to the pension plan. Additionally, changes in interest rates affect the Company’s liabilities under the pension plan. As interest rates decrease, the Company’s liabilities increase, potentially requiring additional funding.

Performance of the capital markets also affects the value of assets that are held in trust to satisfy future obligations under the Company’s non-qualified employee benefit plans, which include deferred compensation plans and a Supplemental Executive Retirement Plan. A reduction in the value of these assets is recorded through current earnings and would adversely affect the funded status of the plans.

If PGE is unable to obtain sufficient financial returns on its benefit plan trust assets, the Company’s operating results and cash flows could be negatively affected. For further information regarding PGE’s contribution obligations under its pension and non-qualified benefit plans, see “Current Market Conditions - Valuation of Investments” in the Overview section of Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, the “Contractual Obligations and Commercial Commitments” table in the Liquidity and Capital Resources section of Item 7, and “Pension and Other Postretirement Plans” in Note 10, Employee Benefits, in the Notes to Consolidated Financial Statements.

Wholesale energy markets are subject to forces that are often not predictable and which can result in price volatility, deterioration of liquidity, and general market disruption, adversely affecting PGE’s costs and ability to manage its energy portfolio and procure required energy supply.

Wholesale electricity prices in the western United States are influenced primarily by factors related to supply and demand. These factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, and changes in technology. Volatility in wholesale energy markets can affect the availability and price of purchased power and demand for energy.

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Changes in the creditworthiness of large wholesale counterparties can also affect PGE’s variable power costs. Further, disruption in wholesale markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, affect wholesale energy prices, and impair PGE’s ability to manage its energy portfolio. Changes in wholesale energy prices can also affect the market value of derivative instruments and cash requirements to purchase electricity. Although the Company’s PCAM can be expected to partially mitigate adverse financial effects related to wholesale market conditions, cost sharing features of the mechanism do not provide for full recovery in customer prices.

Fluctuations in the price of natural gas purchased as fuel for electricity generation can also impact the Company’s liquidity. Recently, as a result of declining wholesale power and natural gas prices, PGE has been required to provide increased margin deposits pursuant to existing purchased power and natural gas agreements. If wholesale power and natural gas prices continue to decline, PGE could be required to continue to provide increased margin deposits, which could adversely affect the Company’s liquidity.

Fluctuations in the price of natural gas purchased as fuel for electricity generation can also impact results of operations. PGE purchases natural gas in the open market or pursuant to short-term or variable-price contracts as part of its normal business operations. If market prices rise, especially during periods when the Company requires greater-than-expected volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated. The Company may not be able to fully recover these increased costs through ratemaking.

Under certain circumstances, one or more of the banks participating in PGE’s credit facilities could decline to fund an advance requested by the Company or could withdraw from participation in the credit facility.

The Company has a $370 million multi-year revolving credit facility, of which $10 million expires in July 2012 and $360 million expires in July 2013, and a $125 million 364-day revolving credit facility, which expires in December 2009. Each facility is with a group of banks. These facilities supplement operating cash flow and provide a primary source of liquidity. The facilities are also used as backup for commercial paper borrowings and are available for general corporate purposes. The Company is required to make certain representations to the banks each time it requests an advance under one of the facilities.

These facilities are commitments on the part of the banks to make loans and, in the case of the multi-year revolving credit facility, to issue letters of credit. However, in the event of the occurrence of certain events that could result in a material adverse change in the business, financial condition or results of operation of PGE, the Company may not be able to make certain representations in which case the banks would not be required to lend. We are also subject to the risk that one or more of the participating banks may default on its obligation to make loans under the credit facilities.

In addition, it is possible that the Company might not be aware of certain developments at the time it makes such a representation in connection with a request for an advance, which could cause the representation to be untrue at the time made and constitute an event of default. Such a circumstance could result in a loss of the banks’ commitments under the facilities and in certain circumstances an acceleration of repayment of any outstanding advance.

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Adverse changes in PGE’s credit ratings could negatively affect its access to the capital markets and its cost of borrowed funds.

Access to capital markets is important to PGE’s ability to operate and to complete its ongoing capital projects, such as Biglow Canyon and the smart meter project. In their normal course of business, credit rating agencies re-examine PGE’s credit ratings on a periodic basis and when certain events occur. A ratings downgrade could increase the interest rates and fees on PGE’s revolving credit facilities, increasing the cost of funding day-to-day working capital requirements, and could also require the Company to pay higher interest rates on future long-term debt. In addition, access to the commercial paper market, a principal source of short-term financing, could be restricted, possibly resulting in higher interest costs. The Company’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). In January 2009, S&P revised its outlook on PGE from ‘stable’ to ‘negative’ and affirmed PGE’s corporate credit rating. The outlook revision reflects the possibility that, in 2009, PGE’s debt balances may increase and credit metrics may weaken to levels that would not be commensurate with S&P’s expectations for the current ‘BBB+’ corporate rating. Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, which could have an adverse effect on the Company’s liquidity.

The effects of weather on electricity usage can adversely affect operating results.

Weather conditions can adversely affect PGE’s revenues and costs and have an impact on the Company’s financial and operating results. Temperatures outside the normal range can affect customer demand for electricity, with warmer-than-normal winters or cooler-than-normal summers reducing energy sales and revenues. Weather conditions are the dominant cause of usage variations from normal seasonal patterns, particularly for residential customers. Severe weather can also disrupt energy delivery and damage the Company’s transmission and distribution system.

Rapid increases in load requirements resulting from unexpected adverse weather changes, particularly if coupled with transmission constraints, could adversely impact PGE’s cost and ability to meet the energy needs of its customers. Conversely, rapid decreases in load requirements could result in the sale of excess energy at depressed market prices.

Weather conditions that reduce stream flows could adversely affect PGE’s hydro production and increase the Company’s generation or power purchase costs required to meet the shortfall.

PGE derives a portion of its power supply from its hydroelectric facilities and from those owned by certain public utility districts in the state of Washington and the city of Portland, with whom the Company has long-term power purchase contracts. Regional rainfall and snow pack levels affect stream flows and the resulting amount of generation available from these facilities. Shortfalls in low-cost hydro production would require increased generation from the Company’s higher cost thermal plants and/or power purchases in the wholesale market, which could have an adverse effect on operating results. As indicated above, application of the Company’s PCAM could help mitigate adverse financial effects of such shortfalls. However, full recovery is not assured and any inability to fully recover such costs in future rates could have a negative impact on the Company’s results of operation.

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Forced outages at PGE’s generating plants can increase the cost of power required to serve customers because the cost of replacement power purchased in the wholesale market generally exceeds the Company’s cost of generation.

Forced outages at the Company’s generating plants could result in replacement power costs greater than those included in customer prices. As indicated above, application of the Company’s PCAM could help mitigate adverse financial impacts of such outages. However, full recovery is not assured and any inability to fully recover such costs in future rates could have a negative impact on the Company’s results of operation.

Measures required to comply with state and federal regulations related to emissions from thermal electric generating plants could result in increased capital expenditures and changes to the Company’s operations that could increase operating costs, reduce generating capacity and adversely affect PGE’s results of operation.

Oregon and federal regulators are currently considering the air emission standards applicable to PGE’s thermal generating plants in Oregon as part of separate regulatory processes related to haze, mercury, and the Company’s air permits. Oregon regulators have adopted measures that will require installation of mercury controls at PGE’s Boardman coal plant. Additional emissions controls could be required at Boardman, although specific measures will depend on the outcome of the regulators’ reviews. For further information, see “Environmental Matters” in Item 1. - “Business.”

Although the full impact of required state and federal remediation measures is not yet determinable, they could have an adverse effect on future operations, operating costs, and generating capacity at both Boardman and Colstrip. The Company would seek to recover through the ratemaking process any costs of additional emission control equipment or emission reduction measures that may be required. However, there can be no assurance that such recovery would be granted.

In addition, PGE could be subject to litigation brought by environmental groups and other private parties alleging violations of state or federal law and seeking the imposition of penalties, damages, injunctive relief, and the closure of plants. For further information, see Sierra Club et al. v. Portland General Electric Company in Item 3. - “Legal Proceedings.”

Failure of PGE’s wholesale suppliers to perform their contractual obligations could adversely affect the Company’s ability to deliver electricity and increase the Company’s costs.

PGE relies on suppliers to deliver natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure of suppliers to comply with existing contracts in a timely manner could disrupt PGE’s ability to deliver electricity and require the Company to incur additional expenses to meet the needs of its customers. In addition, as these contracts expire, PGE could be unable to continue to purchase natural gas, coal or electricity on terms and conditions equivalent to those of existing agreements. Cost and availability of natural gas and coal can also impact the cost and output of the Company’s thermal generating plants.

The construction of new generating facilities, or modifications to existing facilities, is subject to risks that could result in the disallowance of certain costs for recovery in prices, reduced plant efficiency, or higher operating costs.

Long-term increases in both the number of customers and demand for energy will require continued expansion and reinforcement of PGE’s generation, transmission, and distribution systems.

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Construction of new generating facilities, or modifications to existing facilities, could be affected by various factors, including unanticipated delays and cost increases, which could result in the disallowance of certain costs in the rate determination process. In addition, the failure to complete construction projects according to specifications could result in reduced plant efficiency, equipment failure, and plant performance that falls below expected levels, which could increase operating costs.

Capital expenditures and changes in operations required to comply with both existing and new environmental laws related to fish and wildlife could adversely affect PGE’s results of operation.

A portion of PGE’s total energy requirement is comprised of generation from hydroelectric projects on the Columbia, Clackamas, Deschutes, and Willamette rivers. Operation of these projects is subject to extensive regulation related to the protection of fish and wildlife. The listing of various species of salmon, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the amount of hydro generation available to meet the Company’s energy requirements. The Company would likely seek recovery of any such expenditures through the ratemaking process; however, there can be no assurance that such recovery would be granted.

Legislative or regulatory efforts to reduce greenhouse gas emissions, in response to concerns related to climate change, could lead to increased capital and operating costs and have an adverse impact on the Company’s operations or results of operation.

The outcome of legislative or regulatory efforts regarding greenhouse gas emissions, whether at the international, federal, regional, state, or local level, or the timing of any such laws or regulations that could be enacted, could have a material adverse effect on future results of operations and cash flows unless the additional costs incurred to comply with such laws or regulations can be recovered through regulated rates and/or future market prices for electricity. The cost of compliance with such measures could also make some of PGE’s electric generating units uneconomical to operate or maintain. The Company would likely seek to recover through the ratemaking process any costs of additional emission control equipment or emission reduction measures, such as the cost of sequestration or purchasing allowances, or offset the cost of credits that may be required; however, there can be no assurance that such recovery would be granted.

PGE expects that future federal, and possibly state, legislation or regulation may result in the imposition of limitations on the Company’s greenhouse gas emissions from fossil fuel-fired electric generating units. A number of bills have been introduced in the U.S. Congress that would require greenhouse gas emission reductions from fossil fuel-fired electric generation facilities and other sectors of the economy, although no such bill has yet been enacted. Compliance with these greenhouse gas emission reduction requirements could require PGE to make significant expenditures, including with respect to carbon capture and sequestration technology, purchase of emission allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and replacement with lower emitting generation facilities.

The costs of compliance with these expected greenhouse gas requirements are subject to significant uncertainties, including with respect to the timing of the implementation of emission rules, required

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levels of emission reductions, emission allocation requirements, the maturation, regulation and commercialization of carbon capture and sequestration technology, and PGE’s selected compliance alternatives. As a result, PGE cannot estimate the effect of any such legislation on its results of operations, financial condition or cash flows; however, the costs of compliance with such requirements could be material.

PGE is subject to various legal and regulatory proceedings, the outcome of which is uncertain, and resolution unfavorable to PGE could adversely affect the Company’s results of operation, financial condition or cash flows.

From time to time in the normal course of its business, PGE is subject to various regulatory proceedings, lawsuits, claims and other matters, which could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. These actions are subject to many uncertainties and management cannot predict the outcome of individual matters with assurance. The final resolution of some of the matters in which PGE is involved could require the Company to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have an adverse effect on its cash flows and results of operation. Similarly, the terms of resolution could require the Company to change its business practices and procedures, which could also have an adverse effect on its cash flows, financial position or results of operation.

Certain pending legal and regulatory proceedings, such as the Trojan litigation, the proceedings related to refunds on wholesale market transactions in the Pacific Northwest, and the investigation and any resulting remediation efforts related to the Portland Harbor site, may have an adverse effect on results of operations and cash flows for future reporting periods. For further information, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements and Item 3. - “Legal Proceedings.”

Storms and other natural disasters could damage the Company’s facilities and disrupt its delivery of electricity resulting in significant property loss or repair costs and customer dissatisfaction.

The Company has exposure to natural disasters that can cause significant damage to its generation, transmission, and distribution facilities. Such events can interrupt the delivery of electricity, increase repair and service restoration expenses, and reduce revenues. Such events, if repeated or prolonged, can also affect customer satisfaction and the level of regulatory oversight. As a regulated utility, the Company is required to provide service to all customers within its service territory and generally has been afforded liability protection against customer claims related to service failures beyond the Company’s reasonable control.

To the extent reasonably possible, PGE utilizes insurance as a means to cost effectively mitigate the risk of physical loss or damage to the Company’s property resulting from natural disasters, subject to certain coverage terms and conditions. The Company believes that the losses sustained to its transmission and distribution property relating to the December 2008 winter storm that affected Oregon will likely exhaust all remaining benefits available under the Company’s transmission and distribution property insurance policy. As a result, PGE would be responsible for any damage sustained to its transmission and distribution property related to future storms, unless additional insurance is obtained. Related losses through the end of the term of the current insurance policy, which terminates in October 2009, would increase costs. The Company would likely seek recovery of any future uninsured storm-related losses through the ratemaking process; however, there can be no assurance that any recovery would be granted. If such recovery is not granted, these increased costs could have

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an adverse effect on PGE’s results of operation in a future period. Additionally, PGE may not be able to obtain subsequent insurance policies for its transmission and distribution property with similar terms and rates.

PGE’s business is subject to extensive regulation that affects the Company’s operations and costs.

PGE is subject to regulation by the FERC and the OPUC, and by federal, state and local authorities under environmental and other laws. Such regulation significantly influences the Company’s operating environment and affects many aspects of its business. Changes to regulations are ongoing, and the Company cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s business. However, changes in these regulations could delay or adversely affect business planning and transactions, and substantially increase the Company’s costs.

PGE has an aging workforce with a significant number of employees approaching retirement age.

The Company anticipates higher averages of retirement rates over the next ten years and will likely need to replace a significant number of employees in key positions. PGE’s ability to successfully implement a workforce succession plan is dependent upon the Company’s ability to employ and retain skilled professional and technical workers. Without a skilled workforce, the Company would face greater challenges in providing quality service to its customers and meeting regulatory requirements, both of which could affect operating results.

Conditions that may be imposed in connection with the renewal of hydroelectric licenses could require large capital expenditures.

PGE is currently involved in renewing the federal license for its hydroelectric projects on the Clackamas River. The FERC, under the Federal Power Act, may impose conditions with respect to environmental, operating and other matters in connection with the renewal of PGE’s license. The Company cannot predict with certainty the requirements that might be imposed during the relicensing process, the economic impact of those requirements, whether a new license will ultimately be issued or whether PGE will be willing to meet the relicensing requirements to continue operating its Clackamas hydroelectric projects. The Company would likely seek recovery of any additional costs related to such licensing requirements through the ratemaking process.

None.

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PGE’s principal property, plant, and equipment are located on land owned by the Company in fee or land under the control of the Company pursuant to existing leases, federal or state licenses, easements or other agreements. In some cases, meters and transformers are located on customer property. The Company leases its corporate headquarters complex, located in Portland, Oregon. The Indenture securing the Company’s First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.

The Company’s service territory and generating facilities are indicated below:

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The following are generating facilities owned by PGE as of December 31, 2008:

Hydro Licensing

PGE holds FERC licenses under the Federal Power Act for its hydroelectric generating plants. The Company’s Sullivan plant operates under a FERC license that expires in 2035, while the Pelton and Round Butte plants operate under a license that expires in 2055.

The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the relicensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. The settlement agreement also provides for a collaborative process for the resolution of water temperature issues downstream of the project, which must be settled prior to the issuance of a new license. Pending approval of the new license, the project will operate under annual licenses issued by the FERC. It is expected that the FERC will issue a new license for the Clackamas River projects in 2010.

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Transmission and Distribution

PGE owns and/or has contractual rights associated with transmission lines that deliver electricity from its Oregon generation facilities to its distribution system in its service territory and also to the Western Interconnect. As of December 31, 2008, PGE owned an electric transmission and distribution system consisting of approximately:

In addition to the transmission and distribution lines presented in the table above, PGE has approximately 24,000 circuit miles of primary and secondary distribution lines that deliver electricity to its customers.

The Company also has an ownership in and other contractual rights associated with transmission lines that deliver electricity as follows:

The California-Oregon AC Intertie and the Pacific DC Intertie are primarily used for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

As of December 31, 2008, PGE owned 173 transmission and distribution substations throughout its service territory.

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Citizens’ Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O’Neill v. Public Utility Commission of Oregon, Public Utility Commission of Oregon Docket Nos. DR 10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.

Following the closure of Trojan, PGE, in its 1993 general rate filing, sought OPUC approval to recover through rates future decommissioning costs and full recovery of, and a rate of return on, its Trojan investment. PGE’s request was challenged and PGE requested from the OPUC a Declaratory Ruling (Docket DR 10) regarding recovery of the Trojan investment and decommissioning costs. In August 1993, the OPUC issued a Declaratory Ruling in PGE’s favor. The Declaratory Ruling was appealed to the Marion County Circuit Court, which in November 1994 upheld the OPUC’s Declaratory Ruling. The Citizens’ Utility Board (CUB) appealed the decision to the Oregon Court of Appeals.

In PGE’s 1995 general rate case (Docket UE 88), the OPUC issued an order (1995 Order) granting PGE full recovery of Trojan decommissioning costs and 87% of its remaining undepreciated investment in the plant. The URP filed an appeal of the 1995 Order to the Marion County Circuit Court, alleging that the OPUC lacked authority to allow PGE to recover Trojan costs through its rates. The CUB also filed an appeal to the Marion County Circuit Court challenging the portion of the 1995 Order that authorized PGE to recover a return on its remaining undepreciated investment in Trojan.

In April 1996, the Marion County Circuit Court issued a decision that contradicted the Court’s November 1994 ruling. The 1996 decision found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan. The 1996 decision was appealed to the Oregon Court of Appeals, where it was consolidated with the earlier appeal of the 1994 decision.

In June 1998, the Oregon Court of Appeals ruled that the OPUC does not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan, but upheld the OPUC’s authority to allow PGE’s recovery of its undepreciated investment in Trojan and its costs to decommission Trojan (1998 Decision). The court remanded the matter to the OPUC for reconsideration of its 1995 Order in light of the court’s decision (1998 Remand).

In August 1998, PGE and the URP each filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the 1998 Decision relating to PGE’s return on its undepreciated investment in Trojan. On November 19, 2002, the Oregon Supreme Court dismissed both Petitions for Review.

In September 2000, PGE, CUB, and the OPUC Staff settled proceedings related to PGE’s recovery of its investment in the Trojan plant (Settlement). The URP did not participate in the Settlement and filed a complaint with the OPUC, challenging PGE’s application for approval of the accounting and ratemaking elements of the Settlement.

In March 2002, after a full contested case hearing (Docket UM 989), the OPUC issued an order (Settlement Order) denying all of the URP’s challenges and approving PGE’s application for the accounting and ratemaking elements of the Settlement. The URP appealed the Settlement Order to the

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Marion County Circuit Court. On November 7, 2003, the Marion County Circuit Court remanded the case to the OPUC to reduce rates or order refunds (2003 Remand). The opinion did not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC each appealed the 2003 Remand to the Oregon Court of Appeals.

On October 10, 2007, the Oregon Court of Appeals issued an opinion that reversed the Settlement Order and remanded the Settlement Order to the OPUC for reconsideration. The Oregon Court of Appeals also vacated the 2003 Remand.

As a result of its reconsideration of the Settlement Order, on September 30, 2008, the OPUC issued an order that requires PGE to refund $33.1 million to customers.

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

On October 22, 2008, the URP and the Class Action Plaintiffs (described in the Dreyer proceeding below) separately appealed the September 30, 2008 order to the Oregon Court of Appeals.

On December 1, 2008, the OPUC issued an order that suspended the requirements imposed on PGE by the refund methodology outlined in the September 30, 2008 order for 60 days. On January 24, 2009, counsel for the URP and the Class Action Plaintiffs filed a motion with the Oregon Court of Appeals requesting a stay of the refund pending final disposition of their appeal. On February 2, 2009, the OPUC issued Order No. 09-039, which suspended the requirements imposed on PGE by the refund methodology, pending the Court of Appeals decision on the Motion for Stay filed by the URP and Class Action Plaintiffs. Based on the OPUC orders and request for stay, the timing of the refunds to customers is uncertain, but could occur during 2009.

Management cannot predict the ultimate outcome of the above matter. However, it believes that this matter 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 operation and cash flows in a future reporting period.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10639; and Morgan v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10640.

On January 17, 2003, two class action suits were filed in Marion County Circuit Court against PGE on behalf of two classes of electric service customers. The Dreyer 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 Morgan 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, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers.

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On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of the Class Action Plaintiffs’ claims. On December 14, 2004, the Judge granted the Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. On March 3, 2005, PGE filed a Petition for a Writ of Mandamus with the Oregon Supreme Court asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed. On March 29, 2005, PGE filed a second Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court seeking to overturn the Class Certification.

On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions for Alternative Writ of Mandamus abating these class action proceedings until the OPUC responded with respect to the certain issues that had been remanded to the OPUC by the Marion County Circuit Court in the proceeding described above.

On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions for one year.

On October 17, 2007, the plaintiffs in the class action suits filed a motion with the Marion County Circuit Court to lift the abatement.

At a status conference on October 15, 2008, the Circuit Court set a schedule for the filing of briefs on the plaintiffs’ motion to lift the abatement. Oral argument occurred on January 12, 2009. A decision on the motion to lift the abatement is pending.

Management cannot predict the ultimate outcome of the above matter. However, it believes that this matter 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 operation and cash flows in a future reporting period.

Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission, Docket Nos. EL01-10-000, et seq. (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. 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 on appeal, 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

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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 did not rule on the FERC’s ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.

On May 17, 2007, the FERC approved a settlement between PGE and certain parties in the California refund case in Docket No. EL00-95, et seq. This resolves the 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. The settlement with the California parties does not resolve potential claims from other market participants relating to transactions in the Pacific Northwest.

Management cannot predict the outcome of 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 operation and cash flows in a future reporting period.

Sierra Club et al. v. Portland General Electric Company, U.S. District Court for the District of Oregon, Case No. CV 08-1136-HA.

On January 15, 2008, plaintiffs sent PGE a sixty-day notice of intent to sue for alleged violations of the federal Clean Air Act (CAA), Oregon’s State Implementation Plan (SIP) at PGE’s Boardman Coal Plant, and the Plant’s CAA Title V permit. On September 30, 2008, the plaintiffs sued PGE for these and additional alleged violations of various environmental related regulations.

The plaintiffs seek injunctive relief that includes permanently enjoining PGE from operating the Boardman Coal Plant except in accordance with the CAA, Oregon’s SIP, and the Plant’s Title V Permit. In addition, plaintiffs seek civil penalties against PGE including $27,500 per day per alleged violation for violations occurring before March 15, 2004 and $32,500 per day per alleged violation occurring thereafter. The total amount of monetary penalties and damages asserted in the complaint cannot be determined with certainty. However, based solely on the complaint, the Company estimates that the amount is approximately $60 million. The Company believes that it has strong defenses to the plaintiffs’ claims and intends to vigorously defend against this lawsuit.

General

From time to time in the normal course of business, PGE is subject to various other regulatory proceedings, lawsuits, claims and other matters, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. Management currently does not believe any of these other matters will have a material adverse effect on the Company’s financial position, results of operation or cash flows.

None.

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PART II

PGE’s common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol “POR”. As of February 20, 2009, there were 1,252 holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $16.74 per share. The following table sets forth, for the periods indicated, the highest and lowest sales prices of PGE’s common stock as reported on the NYSE.

While PGE expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration depends upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGE’s results of operation and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

As required by Section 303A.12 of the NYSE Listed Company Manual, Peggy Y. Fowler, the Chief Executive Officer of the Company, certified to the NYSE on May 29, 2008 that she was not aware of any violation by the Company of the NYSE’s corporate governance listing standards.

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The following consolidated selected financial data should be read in conjunction with Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and Item 8. - “Financial Statements and Supplementary Data.”

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Information Regarding 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, cash flows from operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, growth in demand for energy, future capital expenditures, market conditions, long-term earnings growth, the cost, completion and benefits of capital projects, future events, liquidity 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.

Overview

PGE is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale sale of electricity and natural gas in the western United States and Canada. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The Company’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected by the condition of the local economy), and the availability and price of purchased power and fuel. PGE is a winter peaking utility that typically experiences its highest retail energy sales during the winter heating season, with a slightly lower peak in the summer that generally results from air conditioning demand.

General Rate Case Results - On January 23, 2009, the OPUC issued its final order concerning PGE’s general rate case and proposed tariffs, which became 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, compared to the 7.3% average price increase approved by the OPUC. The OPUC approved a cost of capital that provides for a capital structure of 50% equity and 50% debt and a return on equity of 10.1%. The order authorizes $121 million of increased revenues, consisting of approximately $95 million for NVPC and $26 million for other costs. Certain customer credits, including those related to 2007 results of the Company’s PCAM, reduced the average price increase to approximately 5.6%. The OPUC also authorized PGE to file tariffs to implement a decoupling mechanism. For further information, see Decoupling Mechanism in “Legal, Regulatory and Environmental Matters” in this Item. Management is taking measures to manage costs in response to the final results of this general rate case.

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

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For additional information with respect to these and other matters, see “Liquidity and Capital Resources” in this Item 7. and Item 7A. - “Quantitative and Qualitative Disclosures About Market Risk.”

Customers - During 2008, PGE served an average of 811,315 retail customers compared to 800,587 during 2007, an increase of 1.3%. This customer growth, along with more extreme weather in 2008, resulted in a 1.9% increase in retail energy deliveries relative to 2007. On a weather adjusted basis, retail energy deliveries increased 0.8% from 2007.

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The slow-down of the state’s economy, including a sustained decline in the housing market, continued throughout 2008 and into 2009. Oregon’s unemployment rate rose from an average of 5.2% for 2007 to an average of 6.3% for 2008, compared to the national average unemployment rate of 5.8%. Oregon’s seasonally-adjusted unemployment rate increased to 9% in December 2008. PGE projects weather adjusted energy deliveries for 2009 will be comparable to weather adjusted energy deliveries for 2008, which is a result of the increase in the unemployment rate.

Installation of a limited number of new smart meters has begun as part of the smart meter project’s acceptance testing phase, with full deployment expected to be completed 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 remaining net investment of the meters being removed, during this period.

Capital and Financing - PGE maintains liquidity through revolving credit facilities totaling $495 million and access to the commercial paper market. As of December 31, 2008, the unused available credit under the credit facilities is $166 million, with $228 million available as of February 20, 2009.

During 2008, PGE issued $50 million and repurchased $56 million of long-term debt, and in December PGE entered into a $125 million 364-day revolving credit facility. In January 2009, PGE issued $130 million of long-term debt.

PGE has major capital projects in process, which require financing in 2009 and 2010. PGE estimates that as of December 31, 2008, and after considering the issuance of $130 million of First Mortgage Bonds in January 2009, it could issue up to $598 million of additional First Mortgage Bonds under the most restrictive issuance test as delineated in the Mortgage and Deed of Trust securing the bonds.

In May 2008, PGE’s Board of Directors approved a 4.3% increase in the Company’s quarterly common stock dividend, from $0.235 per share to $0.245 per share. Dividends declared totaled $61 million in 2008, $58 million in 2007, and $42 million in 2006.

Power Supply - PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. In 2008, the Company’s generating plants provided approximately 62% of its retail load requirement, compared to 56% in 2007 and 37% in 2006. The sequential increases are 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. Generation from PGE’s hydroelectric plants provided approximately 10% of its retail load requirement in each of the last three years (2006-2008). Current forecasts indicate below normal regional hydro conditions for 2009.

Biglow Canyon Phases II and III are currently under construction, with completion expected by the end of 2009 and 2010, respectively. 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 7.

As part of the Company’s integrated resource planning process, PGE in 2008 issued a request for proposals for 218 MWa of new renewable energy resources and has identified a final short list of bidders, with agreements expected to be completed in 2009. Such resources, which are in addition to

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Biglow Canyon, are required to become available between 2009 and 2014 to meet requirements of Oregon’s Renewable Energy Standard.

PGE is currently preparing a new IRP to be filed by late 2009. PGE expects the new IRP to further define the Company’s future energy and capacity needs and assess the economic viability of the proposed Boardman environmental retrofits.

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 18, Contingencies, in the Notes to Consolidated Financial Statements.

In December 2008, the DEQ issued a proposed plan that would require the installation of emission controls at Boardman under a phased-in approach. For further discussion of this matter, see Clean Air Standards, in “Capital Requirements” under “Liquidity and Capital Resources” in this Item 7.

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 18, Contingencies, in the Notes to Consolidated Financial Statements.

The following price adjustments, as approved by the OPUC, became effective on January 1, 2009:

The above items, combined with other miscellaneous tariff changes, result in an overall retail price increase of approximately 5.6% effective January 1, 2009.

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

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The American Recovery and Reinvestment Act of 2009 - On February 17, 2009, the American Recovery and Reinvestment Act of 2009 (the Act) was enacted. The Act provides for tax and appropriation benefits to the utility industry including the following:

PGE is currently evaluating the impact of and alternatives under the Act.

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Results of Operation

The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operation for 2008 compared to 2007, and for 2007 compared to 2006, which follow hereafter.

The consolidated statements of income for the periods presented (dollars in millions):

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Revenues, energy sold and delivered (based on MWh), and retail customers consist of the following for the periods presented (dollars in millions and MWh in thousands):