PORTLAND GENERAL ELECTRIC CO /OR/ - Annual Report: 2009 (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, 2009

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:

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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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.

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, 2009, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $1,461,965,195. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 19, 2010, there were 75,210,580 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, 2009

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, with revenue requirements and customer prices determined based upon the forecast cost to serve retail customers, including an opportunity to earn a reasonable rate of return. PGE meets approximately 50% of its energy requirement with company-owned generation and purchases power in the wholesale market to meet its remaining requirement. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in order to 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. Following issuance of the new PGE common stock, 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 2009 its service area population was 1.7 million, comprising about 43% of the state’s population. The Company added 5,542 customers during 2009 and served a total of 815,739 retail customers as of December 31, 2009.

As of December 31, 2009, PGE had 2,708 employees, with 890 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (Local 125). Such agreements cover 856 and 34 employees and expire on February 28, 2012 and August 1, 2011, respectively.

Available Information

The Company’s Annual Reports 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 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.

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Regulation and Rates

As a public utility, PGE is subject to federal and state regulation, which can have a significant impact on the business and operations of the Company as well as prices charged for electric service. In addition to those agencies and activities discussed below, the Company is subject to regulation by certain environmental agencies, as described in the Environmental Matters section in this Item 1.

Federal Regulation

PGE is subject to regulation by several federal agencies, including the Federal Energy Regulatory Commission (FERC) and 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 in matters related to wholesale energy activities, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. The Energy Policy Act of 2005 (EPAct 2005) granted the FERC statutory authority to implement mandatory reliability standards and also authorized monetary penalties for non-compliance with such standards and other FERC regulations. EPAct 2005 also provides for enhanced oversight of power and transmission markets, including protection against market manipulation.

Wholesale Energy—PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales. Re-authorization for continued use of such rates requires the filing of triennial market power studies with the FERC. The Company’s next triennial market power study is due at the FERC in June 2010.

Transmission—Terms and conditions pursuant to which PGE offers transmission service are contained in the Company’s Open Access Transmission Tariff (OATT), which is filed with the FERC. As required by the OATT, PGE provides information regarding its transmission business on its Open Access Same-time Information System. As of December 31, 2009, PGE owned approximately 1,200 miles of transmission lines. For additional information, see the Transmission and Distribution section in this Item 1. and in Item 2.—“Properties.”

Reliability Standards—Pursuant to EPAct 2005, the FERC has adopted mandatory reliability standards for owners, users and operators of the bulk electric system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of these standards.

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 as the Company has a 79% ownership interest in the 17-mile interstate pipeline that provides natural gas to its Port Westward and Beaver plants.

Hydroelectric Licensing—Under the Federal Power Act, PGE’s hydroelectric generating plants are subject to FERC licensing requirements. These include an extensive public review process that involves numerous natural resource issues and environmental conditions. PGE holds new 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. For additional information, see the Environmental Matters section in this Item 1.

Accounting Policies and Practices—Pursuant to applicable provisions of the Federal Power Act, PGE prepares financial statements in accordance with the accounting requirements of the FERC, as set forth in its applicable Uniform System of Accounts and published accounting releases. Such financial statements are included in annual and quarterly reports filed with the FERC.

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Short-term Debt—Pursuant to applicable provisions of the Federal Power Act and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. Pursuant to an order issued by the FERC on January 29, 2010, the Company is authorized to issue up to $750 million of short-term debt through February 6, 2012.

NRC Regulation

The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s Trojan Nuclear Plant, which was closed in 1993. The NRC approved the 2003 transfer of spent nuclear fuel from a spent fuel pool to a separately licensed dry cask storage facility that will house the fuel on the plant site until a U.S. Department of Energy facility is available. Radiological decommissioning of the plant site was completed in 2004 under an NRC-approved plan, with the plant’s operating license terminated in 2005. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site and radiological decommissioning of the storage facility is completed.

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.

Following the announced resignation of Lee Beyer as Chairman of the OPUC, current commissioner Ray Baum has been appointed to serve as Chairman. In addition, John Savage, who has served on the OPUC since 2003, has been reappointed to another four-year term and Susan Ackerman has been appointed to serve the remaining two years of Chairman Beyer’s term. Such appointments are effective on March 1, 2010.

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 ratemaking 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 intervenors.

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The Act also provides for the recovery in customer rates of all prudently incurred costs required to comply with the RES. Under a renewable adjustment clause (RAC) mechanism, PGE can recover the revenue requirement of new renewable resources and associated transmission that are not yet included in rates. Under the RAC, PGE submits a filing on April 1 of each year for new renewable resources being placed in service in the current year, with rates to become effective January 1st of the following year. In addition, the RAC provides for the deferral of eligible costs incurred prior to January 1st of the following year.

For additional information, see the Legal, Regulatory and Environmental Matters discussion in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 investor-owned electric and natural gas 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

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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.

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 actual operating income than forecast in its latest general rate case, customers are surcharged for the resulting increase in income taxes, further increasing earnings. Conversely, if the Company records lower actual operating income than forecast in its latest rate case, customers receive refunds for the resulting decrease in income taxes, further decreasing earnings.

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

Retail Customer Choice Program—This program allows PGE’s commercial and industrial customers direct access to other suppliers of electricity (Electricity Service Suppliers, or ESSs). While such customers can purchase their electricity from other suppliers, PGE continues to deliver the energy. The program provides for “transition adjustments” that reflect the above- or below-market cost of energy resources owned or purchased by the utility, with such adjustments designed to ensure that such costs or benefits do not unfairly shift to the utility’s remaining energy customers. The retail customer choice program is intended to have no material effect on the financial condition or results of operations of the Company.

In addition to opting-out of cost-of-service for terms of one year or less to be served by an ESS, PGE also offers an option by which certain large non-residential customers may elect to be removed from cost-of-service pricing for a fixed three-year or a minimum five-year term. In 2009, ESSs supplied PGE customers with a total average load of approximately 221 MWa, representing 17% of PGE’s non-residential load and 10% of the Company’s total retail load for the year. In early 2010, the four ESSs registered to transact business with PGE supply an average load of approximately 134 MWa, representing 10% of the Company’s non-residential load and 6% of total retail load.

Daily and monthly market price options are also available to PGE’s commercial and industrial customers. At the end of 2009, PGE served customers with a total load of 12 MWa under such options, representing 1% of nonresidential load and less than 1% of total retail load. PGE served the remaining 82% of nonresidential load under cost-of-service or other portfolio options.

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, 2009, approximately 82,000 customers were enrolled in renewable energy options, with 2,130 enrolled in time-of-use options. As of December 31, 2008, approximately 71,000 customers were enrolled in renewable energy options, with 2,058 enrolled in time-of-use options.

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 2009 and 2008, approximately $48 million and $47 million, respectively, were billed to customers for this charge.

PGE also remits to the ETO amounts collected under an Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. The tariff, which became effective on June 1, 2008, included an approximate 1% charge for eligible customers, providing about $14 million annually for measures that enable customers to reduce their energy use. Effective January 1, 2010, the charge was increased to approximately 1.5%, which is expected to provide about $21 million annually.

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Decoupling—Pursuant to OPUC authorization in PGE’s most recent general rate case (2009 General Rate Case), the Company is deferring, for later ratemaking treatment, amounts associated with a new decoupling mechanism. The mechanism is intended to provide for recovery of reduced revenues resulting from a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. It also provides for customer refunds if weather adjusted use per customer exceeds that approved in the rate case. For 2009, PGE accrued a refund to customers of $6.8 million, as weather adjusted use per customer for the year exceeded that approved in the rate case.

Regulatory Accounting

As a regulated public utility, PGE is subject to generally accepted accounting principles for regulated operations to reflect the effects of rate regulation in its financial statements. These principles provide for the deferral as regulatory assets of certain actual or anticipated costs that would otherwise be charged to expense, based on expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE records regulatory assets or liabilities if it is probable that they will be allowed for recovery or refund in future rates, based on regulatory orders or other available evidence.

The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future rate environment and related accounting guidance. For additional information, see Regulatory Assets and Liabilities in Note 2, Summary of Significant Accounting Policies, and Note 6, Regulatory Assets and Liabilities, 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. For additional information on customer choice, see Retail Customer Choice Program within the Regulation and Rates section in this Item 1.

The following table summarizes PGE’s revenues for the years presented, with dollars in millions, except as indicated. Certain averages for retail customers who purchase their energy requirements from the Company are also reflected below:

For additional information, see Results of Operations in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Retail Revenues

Retail customers are categorized into residential, commercial, and industrial classes, with no single customer representing more than 1% of PGE’s total retail revenues or 5% of total retail deliveries. Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest commercial and industrial customers constituted 8% of total retail revenues in 2009, they represented nine different groups, including retail, high technology, paper manufacturing, metal fabrication, health services and governmental agencies. Additional information on these customer classes follows.

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Residential customers include single family housing, multiple family housing (such as apartments, duplexes and townhomes), mobile homes, and small farms. Pricing of service to the residential class is based on the costs PGE incurs to provide electric service, unless the customer has selected time-of-use or renewable resource pricing. On average for the last three years, residential customers have comprised 88% of total customers, provided 49% of total retail revenues, and accounted for 40% of total retail energy deliveries.

Residential demand is sensitive to the effects of weather, with demand historically highest during the winter heating season although, due to the increased use of air conditioning in PGE’s service territory, the summer peaks have increased in recent years. The state of the economy also affects demand from the Company’s residential customers. Historical data has suggested that a 1% increase in Oregon’s unemployment rate has resulted in an approximate 0.4% decrease in total demand from the Company’s residential customers. During 2009, however, when the unemployment rate increased about 5%, total residential deliveries remained comparable to 2008.

Commercial customers consist of non-residential customers who accept delivery at voltages equivalent to that delivered to residential customers. This customer class includes most commercial businesses, as well as small industrial customers and public street and highway lighting, with pricing based on the amount of electricity used. On average for the last three years, commercial customers comprised 12% of total customers, provided 39% of total retail revenues, and accounted for 39% of total retail energy deliveries.

Demand from the Company’s commercial customers is generally not affected significantly by weather; however, demand can be affected by total employment in the region. Typically, a 1% change in Oregon’s total employment can lead to an approximate 0.6% change in demand from the Company’s commercial customers. During 2009, as the Oregon economy lost about 5.1% of its payroll, the Company’s commercial energy deliveries decreased 3.6% compared to 2008.

Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers, with pricing based on the amount of electricity used and applicable tariff rate. On average for the last three years, industrial customers have comprised less than 1% of total customers, provided 10% of total retail revenues, and accounted for 21% of total retail energy deliveries.

Demand from industrial customers is primarily affected by national and global economic conditions. Weather has little impact on this customer class. Typically, a 1% change in Oregon’s total employment can lead to an approximate 0.2% change in demand from the Company’s industrial customers. Although the Oregon economy lost about 5.1% of its payroll in 2009, total energy deliveries to industrial customers decreased 9.3% in 2009 compared to 2008.

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, net of transition adjustments, is included in Other retail revenues. PGE served an average of 262 direct access customer accounts in 2009, 417 in 2008, and 322 in 2007. The number of ESS customers, deliveries, and revenues are included among the figures discussed above for the Company’s total commercial and industrial customers.

Residential Exchange Program (REP)—Under the REP, the Bonneville Power Administration (BPA) provides federal hydropower benefits to residential and small farm customers of certain investor-owned electric utilities. Under the program, PGE receives monthly payments from BPA and passes such payments along to eligible customers in the form of monthly billing credits. In May 2007, the BPA suspended payments under the program, which resulted in an approximate 14% average price increase to the Company’s eligible customers. Benefits were partially restored on a temporary basis in April 2008, which reduced prices for residential and small farm customers by an average of 6.3%.

In September 2008, the BPA and PGE entered into an agreement that provides for monthly payments through the term of the agreement, which extends to September 2011. For the twelve month period ended September 30,

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2009, PGE received payments totaling approximately $40 million. Payments for the twelve month periods ending September 30, 2010 and 2011 are expected to be approximately $48 million and $49 million, respectively, with benefits to be credited to eligible customers. The Company will continue to pursue ongoing benefits for its customers under the REP.

Wholesale Revenues

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.

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 Operating Revenues

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

Seasonality

Seasonal demand for electricity by PGE’s residential customers is affected by weather conditions, as discussed above. Heating and cooling degree-days are common measures used to analyze the effect of weather on the demand for electricity. Heating and cooling degree-days, which measure how much the average daily temperature varies from 65 degrees, indicate the extent to which customers are likely to use electricity for heating or air conditioning. The higher the numbers of degree-days, the greater the expected demand for heating or cooling.

The following table indicates the heating and cooling degree-days for the most recent three-year period, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

The table indicates that during 2009, demand for heating was greater than the 15-year average, but less than what it was in 2008. Demand for electricity for air conditioning was also greater in 2009 than it was in 2008, which was a near average cooling-degree year.

The Company tracks both base load growth and peak capacity for purposes of long-term load forecasting and resource planning. PGE’s all-time high net system load peak of 4,073 MW occurred in December 1998. The Company’s all-time “summer peak” of 3,949 MW, driven by unusually warm weather, occurred in July 2009 and exceeded the December 2009 winter peak of 3,851 MW. PGE’s average load was 2,658 MWa for the winter and 2,267 MWa for the summer in 2009, compared to 2,691 MWa for the winter and 2,324 MWa for the summer in 2008.

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Power Supply

PGE relies upon its generating resources as well as short- and long-term power purchase contracts to meet its customers’ energy requirements. The Company executes economic dispatch decisions concerning its own generation, and participates in the wholesale market as a result of those economic dispatch decisions, in an effort to obtain reasonably priced power for its retail customers.

PGE’s base generating resources consist of five thermal plants, seven hydroelectric plants, and wind farms located at Biglow Canyon. The volume of electricity the Company generates is dependent upon, among other factors, the capacity and availability of its generating resources. Capacity of a given plant represents the MW the plant is capable of generating under normal operating conditions, net of electricity used in the operation of the plant. The capacity of the Company’s thermal generating resources is also affected by ambient temperatures. Availability represents the percentage of the year the plant was available for operations, which reflects the impact of planned, forced and maintenance outages. For a complete listing of these facilities, see Item 2.—“Properties.”

The Company also promotes 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 capacity (in MW) for the last three years:

For information regarding actual generating output and purchases for the years ended December 31, 2009, 2008 and 2007, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Generation

That portion of PGE’s energy requirements generated by its plants varies 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.

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, 2009, there were 23 projects that together can provide approximately 48 MW of diesel-fired capacity at peak times.

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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.

Purchased Power

PGE supplements its own generation with power purchased in the wholesale market to meet its energy requirements. The Company utilizes short- and long-term wholesale power purchase contracts to provide the most favorable economic mix on a variable cost basis. Such contracts have terms ranging from one month to 30 years and expire at varying dates through 2035.

PGE’s medium term power cost strategy helps mitigate the effect of price volatility on its customers due to changing energy market conditions. The strategy allows the Company to take positions in power and fuel markets up to five years in advance of physical delivery. By purchasing a portion of anticipated energy needs for future years over an extended period, PGE attempts to mitigate volatility in the average cost of purchased power and fuel from year to year.

The Company’s major power purchase contracts consist of the following (also see the preceding table which summarizes the average resource capabilities related to these contracts):

Capacity/exchange—These five 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 February 2010 through December 2016. They include seasonal exchange contracts with other western utilities that help meet both winter- and summer-peaking requirements.

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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 548 MW of firm capacity, with actual energy received dependent upon river flows. 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 long-term agreement that requires the Company to purchase, at market prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project.

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.

PGE also utilizes spot purchases of power in the open market to secure the energy required to serve its retail customers. Such purchases are made under contracts that range in duration from one hour to less than one month. For additional information regarding PGE’s power purchase contracts, see Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements.

Solar—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 (ODOT) and was placed in service in December 2008. PGE purchases any excess energy generated from this facility pursuant to a net metering arrangement with ODOT. The second project, with a total installed capacity of approximately 1,095 kW, is located on the rooftops of three distribution warehouses in Portland and was placed in service between December 2008 and January 2009. PGE purchases 100% of the energy generated from this facility. PGE serves as managing member for both 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.

Future Energy Resource Strategy

Periodically, PGE is required to file with the OPUC an Integrated Resource Plan (IRP), which guides the utility on how it will meet future customer demand and describes the Company’s energy supply strategy for the coming years, reflecting new technologies, market conditions, and regulatory requirements. 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, provides the best combination of expected cost and associated risks and uncertainties for PGE and its customers.

On November 5, 2009, PGE filed a new IRP that includes a four-year strategy for the acquisition of new resources and a 20-year strategy that outlines long-term expectations for resource needs and portfolio performance. PGE projects that it will need 873 MWa of new resources by 2015, increasing to 1,396 MWa by 2020, to meet expected customer demand. Such projected energy gaps are driven primarily by continued load growth and the expiration of certain long-term power supply contracts and will be updated periodically for any changes in underlying assumptions.

To meet the projected energy gap, the IRP includes energy efficiency measures, new renewable resources, new transmission capability, new generating plants, and improvements to existing generating plants as follows:

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As part of this IRP, PGE plans to install emissions controls at its Boardman plant to reduce the plant’s haze-causing emissions, including airborne mercury. After filing the IRP, PGE determined that it will consider an alternative operating plan for Boardman, under which the plant will either discontinue the use of pulverized coal as a fuel source, or cease operations in 2020 and be replaced with a new base load resource. As a result, the Company requested that the OPUC delay consideration of the IRP to allow for additional analysis. The Company intends to file an addendum to its IRP during March 2010, following the presentation of the Company’s proposal to intervenors in this matter. The Company has also agreed to submit a final proposed IRP schedule following discussions with intervenors. Pursuant to the final schedule, the OPUC will review PGE’s IRP and accept public comments before issuing an order concerning acknowledgment of the plan.

For additional information about emissions controls for the Boardman plant, see the Capital Requirements section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

Transmission and Distribution

Transmission systems deliver energy from generating facilities to distribution systems for final delivery to customers. PGE schedules energy deliveries over its transmission system in accordance with FERC requirements and operates one balancing authority area (an electric system bounded by interchange metering) in its service territory. In 2009, PGE delivered approximately 22 million MWh in its balancing authority area through approximately 1,200 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 is subject to the reliability rules of the WECC and the NERC. PGE’s transmission system, together with contractual rights to 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. The Company’s transmission and distribution systems are located as follows:

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PGE’s wholesale transmission activities are regulated by the FERC pursuant to the Company’s OATT, which 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 equal access to PGE’s transmission system. In accordance with the FERC’s Standards of Conduct, PGE’s transmission business is managed and operated independently from its power marketing business.

PGE’s current IRP filing includes a 200-mile, 500 kV transmission project (the Cascade Crossing Transmission Project) that would help meet growing demand by interconnecting new and existing energy resources in eastern Oregon to the Company’s service territory. PGE is coordinating with other utilities and the WECC in planning the project and is currently exploring potential routes.

PGE continues to meet state regulatory requirements related to power distribution service quality and reliability. Such requirements are reflected in specific indices that measure outage duration, outage frequency, and momentary power interruptions. The Company is required to include performance results related to service quality measures in annual reports filed with the OPUC. Specific monetary penalties are provided for failure to attain required performance levels, with amounts dependent upon the extent to which actual results fail to meet such requirements.

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

Environmental Matters

PGE’s operations are subject to a wide range of environmental protection laws, including those related to air and water quality, climate change, noise, endangered species, and waste disposal. Various state and federal agencies have jurisdiction over environmental matters that include the siting and operation of generation, transmission, and substation facilities and the accumulation, cleanup, and disposal of toxic and hazardous substances. In addition, certain of the Company’s hydroelectric projects and transmission system facilities are located on property under the jurisdiction of federal, tribal, and/or state agencies which have authority in environmental protection matters.

Air Quality Standards

Clean Air Act—PGE’s operations, primarily its thermal generating 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, including Oregon, also monitor and administer certain portions of the CAA and must set standards that are at least equal to federal standards.

PGE manages its air emissions by the use of low sulfur fuel, emissions controls and 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 generating plants at forecasted capacity for at least the next several years within the limitations of current SO₂ emissions requirements.

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Mercury Rules—The states in which PGE facilities are located have adopted the following regulations concerning mercury emissions that are likely to have an impact on the Company’s Boardman and Colstrip plants:

Regional Haze Rules—In accordance with federal regional haze rules aimed at visibility impairment in certain federally protected areas, the DEQ conducted an assessment of emission sources that has indicated that Boardman contributes to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology Determination, as required under the CAA.

In June 2009, the OEQC adopted a rule that would require the installation of emissions controls at Boardman in phases, with estimated completion by 2017. The OEQC rule has been submitted to the Environmental Protection Agency (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 2010.

Based on requirements outlined in the OEQC’s rule and current market conditions for air quality equipment, PGE estimates that the approximate cost of the controls required by the rule would be between $520 million and $560 million (100% of total costs, excluding Allowance for Funds Used During Construction, or AFDC). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. PGE will seek recovery of such costs through the ratemaking process.

In PGE’s November 2009 IRP filing, given the options provided by the OEQC of either ceasing operation of Boardman or installing controls and continuing operations, the Company recommended the continued operation of Boardman through 2040 with the addition of the controls required by the OEQC.

Continuing discussions with IRP stakeholders indicate support for the analysis of an alternative strategy regarding Boardman. The Company is committed to seeking the best plan for providing reliable and reasonably priced electricity for customers. Accordingly, PGE has informed the OPUC that the Company intends to pursue an alternative operating plan for Boardman that would allow the operation of Boardman through 2020 with only the mercury controls and low nitrogen oxide burners. PGE has requested, and the OPUC has granted, suspension of the IRP proceedings to allow the Company sufficient opportunity to prepare an alternative Boardman operating plan for inclusion in the IRP. For additional information, see Boardman emissions controls in the Capital Requirements section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The alternative plan, using a 2020 timeline, would allow the Company time to plan and implement an appropriate replacement strategy for Boardman if the plant were to close. Current options under consideration include construction of a new plant or the use of an alternative fuel to operate Boardman.

PGE would seek to recover in future rates its remaining investment in Boardman (approximately $125 million as of December 31, 2009) plus the cost of the mercury controls, low nitrogen oxide burners and decommissioning and other costs related to the plant’s closure, as well as the construction or acquisition costs of replacement generating capacity.

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If agreement with all regulatory bodies cannot be reached to allow for an alternative operating plan for Boardman, PGE will continue to seek approval for installation of all required emissions controls and continued operation of the plant.

Climate Change—Greenhouse gas (GHG) emissions and their potential impacts on climate change have received increased public attention, with state, regional, and federal legislative efforts initiated to establish mandatory controls.

Recent or pending environmental measures include the following:

Any laws that impose mandatory reductions in GHG emissions could have a material impact on PGE, as the Company utilizes fossil fuels in its own power generation and other companies use such fuels to generate power that PGE purchases in the wholesale market. PGE’s Beaver, Coyote Springs, and Port Westward natural gas-fired facilities, and the Company’s interest in Boardman and Colstrip coal-fired facilities, provide approximately 70% of the Company’s net generating capacity.

The ultimate impact that the above regulatory requirements and emissions controls will have on future operations, costs, or generating capacity of PGE’s thermal generating facilities is not yet determinable and is being evaluated as part of the integrated resource planning process.

Water Quality and Endangered Species Protection

Water Quality—The federal Clean Water Act requires that any federal license or permit to conduct an activity that may result in a discharge to waters of the United States must first receive a water quality certification from the state in which the activity will occur. In Oregon, the DEQ is responsible for reviewing proposed projects under this requirement to ensure that federally approved activities will meet water quality standards and policies established by the state. PGE has certificates of compliance for its hydroelectric operations under the FERC license agreements.

Fish 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). As a result, long-term recovery plans for these species include major operational changes to the region’s hydroelectric projects, which have resulted in reductions in hydroelectric generation capacity and the seasonal shifting of hydroelectric generation from the fall and winter periods to the spring and summer periods. PGE has purchase contracts for power generated at affected facilities on the

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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 affects the availability and prices of power in the regional wholesale market.

PGE is implementing a series of fish protection measures at its hydroelectric generation projects on the Clackamas, Deschutes, and Willamette rivers that were prescribed by the U.S. Fish and Wildlife Service and the National Marine Fisheries Service under their authority granted in the ESA. As a result of measures contained in their operating license agreements, the Pelton/Round Butte and Willamette River projects have been certified as low impact hydro, with a portion of their output included as part of the Company’s renewable energy portfolio used to meet the requirements of Oregon’s Renewable Energy Standard. The following are related to conditions outlined in the Company’s FERC operating license agreements:

Decommissioning of PGE’s former Bull Run hydroelectric project, located in the Sandy River basin, has been substantially completed under a FERC Surrender Order. The project is no longer operating and remaining activity consists primarily of the removal and disposition of certain minor facilities.

Avian Protection—Various statutory authorities as well as the Migratory Bird Treaty Act have established civil, criminal, and administrative penalties for the unauthorized take of migratory birds. Operation of electric transmission lines and wind generation projects can pose risks to a variety of such birds. PGE has developed and implemented an avian protection plan to reduce risks to bird species that can result from Company operations.

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 Company 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, are 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 as follows:

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 Portland Harbor on the federal National Priority List as a Superfund site pursuant to CERCLA and listed sixty-nine PRPs, including PGE, which has historically owned or operated property near the river.

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Harbor Oil—The Harbor Oil site in north Portland is the location of a company that PGE engaged 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. In September 2003, the Harbor Oil site was included on the federal National Priority List as a federal Superfund site.

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

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 that 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. The spent nuclear fuel is expected to remain at the ISFSI until permanent off-site storage is available, which is not likely to be before 2020. Shipment of the spent nuclear fuel from the ISFSI to off-site storage is not expected to be completed prior to 2033.

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Certain risks and uncertainties that could have a significant impact on PGE’s business, financial condition, results of operations 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, but are not limited to, 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 operations.

The prices that the OPUC authorizes PGE to charge for its retail services are a 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. Although the OPUC is required to establish rates that are fair, just and reasonable, it has significant discretion in determining the application of this standard.

In PGE’s 2009 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 attempts 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. On February 16, 2010, PGE filed with the OPUC a general rate case with a 2011 test year (2011 General Rate Case). This 2011 General Rate Case seeks to more closely align customer prices with the Company’s cost structure. There can be no assurance that the OPUC will approve the rate increase sought by PGE in this case. For additional information regarding the 2011 General Rate Case, see the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

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 impacts of forced generating plant outages, severe weather, reduced hydro availability, and volatile wholesale energy prices. In 2009, PGE’s actual NVPC exceeded the baseline NVPC included in prices by $22 million. As this amount was below the threshold for recovery under the PCAM, PGE absorbed these increased costs.

The current economic downturn has reduced the demand for electricity and has impaired the financial soundness of many customers, which has adversely affected PGE’s results of operations and could continue to do so.

The economic slow-down has resulted in a rise in Oregon’s average unemployment rate to 11.4% for 2009 from 6.4% for 2008 and 5.2% for 2007, compared to the national average unemployment rate of 9.3% for 2009. Oregon’s seasonally-adjusted unemployment rate increased to 10.8% in December 2009 compared to 9% in December 2008. 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 adversely affected the Company’s results of operations and cash flow and could continue to do so. As a result of the economic slow down, PGE experienced, among other unfavorable trends, the following in 2009:

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In addition, the Company’s uncollectible customer accounts increased in 2009 compared to 2008. If customers are not successful in generating sufficient revenue or are unable to secure financing, they may not be able to pay, or may delay payment of, amounts owed to the Company. The inability of customers to pay the Company could adversely affect the Company’s results of operations 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.

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. 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.

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, including Biglow Canyon Phase III, the smart meter project, and ongoing upgrades and replacements of transmission, distribution and generation infrastructure. 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 result in higher interest rates on future long-term debt. A ratings downgrade could also restrict the Company’s access to the commercial paper market, a principal source of short-term financing, or result in higher interest costs.

In addition, if Moody’s Investor Service (Moody’s) and/or Standard and Poor’s Ratings Services (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.

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 currently scheduled.

Access to capital and credit markets is important to PGE’s ability to operate. The Company faces significant capital requirements in 2010 and for the next few years and expects to issue debt and equity securities in order to fund certain major 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 Phase III and the smart meter project in 2010. For additional 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 Operations.”

If the capital and credit market conditions in the United States and other parts of the world deteriorate, the Company’s future cost of debt and equity capital, as well as 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 currently scheduled.

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Adverse market performance could result in reductions in the fair market value of benefit plan assets and increase the Company’s liabilities related to such plans. Sustained depreciation of the fair value of the plans’ assets could result in significant increases in funding requirements, adversely affecting PGE’s liquidity and results of operations.

Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under the Company’s defined benefit pension plan. Sustained adverse market performance could 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. During 2008, the value of the pension plan assets declined substantially, contributing to the pension plan’s underfunded status of $120 million as of December 31, 2008. During 2009, the value of the pension plan assets appreciated and changes in certain actuarial assumptions resulted in an improvement in the underfunded status of the pension plan to $85 million as of December 31, 2009. As a result, the Company expects to make no contribution to the pension plan in 2010 and a $19 million contribution in 2011, pursuant to the requirements of the federal Pension Protection Act.

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. As changes in the value of these assets are recorded in current earnings, decreases can adversely affect the Company’s operating results. In addition, such decreases can require that PGE make additional payments to satisfy its obligations under these plans. In 2008, PGE recorded a loss on the fair value of these assets of $17 million, which reduced net income by $12 million for the year ended December 31, 2008, while in 2009, PGE recorded a gain of $9 million, which increased net income by $5 million for the year ended December 31, 2009.

For additional information regarding PGE’s contribution obligations under its pension and non-qualified benefit plans, see the “Contractual Obligations and Commercial Commitments” table in the Liquidity and Capital Resources section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Pension and Other Postretirement Plans” in Note 10, Employee Benefits, in the Notes to Consolidated Financial Statements.

Market prices for power and natural gas are subject to forces that are often not predictable and which can result in price volatility, and general market disruption, adversely affecting PGE’s costs and ability to manage its energy portfolio and procure required energy supply, ultimately affecting the Company’s liquidity and results of operations.

PGE purchases power and natural gas in the open market or pursuant to short-term, long-term or variable-priced contracts as part of its normal business operations. Market prices for power and natural gas are influenced primarily by factors related to supply and demand. These factors generally 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 these markets can affect the availability, price and demand for power and natural gas.

Disruption in power and natural gas 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 power prices, and impair PGE’s ability to manage its energy portfolio. Changes in power and natural gas prices can also affect the market value of derivative instruments and cash requirements to purchase power and natural gas. Although the Company’s PCAM can be expected to partially mitigate adverse financial effects related to market conditions, cost sharing features of the mechanism do not provide for full recovery in customer prices.

If power and natural gas prices decline relative to the terms of PGE’s existing purchased power and natural gas agreements, PGE may be required to provide increased margin deposits in accordance with these purchased

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power and natural gas agreements which could adversely affect the Company’s liquidity. In the latter half of 2008 and into 2009, as a result of depressed wholesale power and natural gas prices, PGE was required to provide increased levels of margin deposits for its existing purchased power and natural gas agreements.

Conversely, if power and natural gas 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.

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 operations, 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 accruals, 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 operations. 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 operations.

There are certain pending legal and regulatory proceedings, such as those related to PGE’s recovery of its investment in Trojan, 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, that may have an adverse effect on results of operations and cash flows for future reporting periods. For additional information, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements and Item 3.—“Legal Proceedings.”

Legislative or regulatory efforts to reduce greenhouse gas emissions could lead to increased capital and operating costs and have an adverse impact on the Company’s operations or results of operations.

PGE expects that future federal, and possibly state, legislation or regulations may result in the imposition of limitations on greenhouse gas emissions from the Company’s fossil fuel-fired electric generating facilities. Legislation has been introduced in the U.S. Congress that would require greenhouse gas emission reductions from such generating facilities and other sectors of the economy. No such legislation has yet been enacted, although the House of Representatives passed climate legislation in June 2009. Compliance with any greenhouse gas emission reduction requirements could require PGE to incur significant expenditures, including those related 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 cost to comply with expected greenhouse gas emissions reduction requirements is subject to significant uncertainties, including those related to the timing of the implementation of emissions reduction rules, required levels of emissions reductions, requirements with respect to the allocation of emissions allowances, the maturation, regulation and commercialization of carbon capture and sequestration technology, and PGE’s compliance alternatives. Accordingly, the Company cannot estimate the effect of any such legislation on its results of operations, financial condition or cash flows; the cost to comply with such requirements, however, could be material. The Company would likely seek to recover such costs through the ratemaking process. However, there can be no assurance that such recovery would be granted.

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 power costs greater than those included in customer prices. As indicated above, application of the Company’s PCAM could help mitigate adverse financial

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impacts of such outages; however, full recovery is not assured. Inability to fully recover such costs in future rates could have a negative impact on the Company’s results of operations. Extended maintenance and repair outages at Colstrip Unit 4 and Boardman resulted in incremental replacement power costs of $16 million in 2009.

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 facilities.

PGE has revolving credit facilities with various banks for an aggregate amount available to the Company for general corporate purposes of $600 million. These credit facilities supplement operating cash flow and provide a primary source of liquidity. The credit facilities may also be used as backup for commercial paper borrowings. The Company is required to make certain representations to the banks each time it requests an advance under one of the credit facilities.

These credit facilities are commitments on the part of the banks to make loans and, in certain cases, 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 operations of PGE, the Company may not be able to make certain representations, in which case the banks would not be required to lend. PGE is also subject to the risk that one or more of the participating banks may default on their 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 credit facilities and, in certain circumstances, an acceleration of repayment of any outstanding advance.

Weather conditions that reduce stream flows, or unfavorable wind conditions, could adversely affect generation expected from PGE’s hydro and wind resources and increase the Company’s cost of generation or purchased power required to meet this energy gap.

PGE derives a portion of its power supply from its hydroelectric facilities and from hydroelectric facilities 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.

PGE also derives a portion of its power supply from wind resources, output from which is dependent upon wind conditions. Unfavorable wind conditions could require increased reliance on power from the Company’s other generating resources or purchased power from the wholesale market, both of which would have an adverse effect on operating results.

Although the application of the PCAM could help mitigate adverse financial effects from any decrease in power provided by hydroelectric and wind resources, full recovery of any increase in power costs is not assured. Inability to fully recover such costs in future rates could have a negative impact on the Company’s results of operations.

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

Weather conditions can adversely affect PGE’s revenues and costs, impacting the Company’s financial and operating results. Temperatures outside the normal range can affect customer demand for electricity, with

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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.

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 PGE’s operations that could increase operating costs, reduce generating capacity and adversely affect the Company’s results of operations.

In June 2009, the OEQC adopted a rule as part of a separate regulatory process related to haze, mercury, and the Company’s air permits that would require the installation of emissions controls at Boardman in three phases. The OEQC’s rule has been submitted to the EPA for approval as part of the SIP. The Company expects the EPA to issue a decision on the SIP in 2010. For additional 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 additional 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 such 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.

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 operations.

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

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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.

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

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 to cost effectively mitigate the risk of physical loss or damage to the Company’s property, excluding transmission and distribution property, resulting from natural disasters, subject to certain coverage terms and conditions. The Company would likely seek recovery of large storm-related losses to transmission and distribution property 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 an adverse effect on PGE’s results of operations.

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, 2009:

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. PGE anticipates that the FERC will issue a decision on approval of 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, 2009, 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 owns, or has contractual rights to, the following transmission facilities:

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

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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 did 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 Settlement allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The URP 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 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.

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As a result of its reconsideration of the Settlement Order, the OPUC issued an order on September 30, 2008 that required 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.

As of December 31, 2009, the Company had substantially completed the distribution of the $33.1 million refund, plus accrued interest, as required by the September 30, 2008 OPUC order.

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 operations 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.

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. On February 10, 2009, the Circuit Court judge denied the plaintiff’s motion to lift the abatement.

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 operations and cash flows in a future reporting period.

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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., and Ninth Circuit Court of Appeals, Case No. 03-74139 (collectively, 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 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 were filed with the court and on April 9, 2009, the Ninth Circuit issued an order that denied the requests for rehearing. On April 16, 2009, the Ninth Circuit issued a mandate giving immediate effect to its August 24, 2007 order remanding the case to the FERC.

Since issuance of the mandate, certain parties proposing refunds have filed pleadings with FERC suggesting procedures on remand, attempting to initiate new proceedings, and containing additional evidence that they assert shows market-wide manipulation that justifies refunds from early in 2000. Parties opposing refunds, including PGE, have filed various pleadings that contest allegations of market-wide manipulation and urge the FERC to reaffirm, with a more detailed explanation of its consideration of market manipulation claims, its previous decision not to initiate proceedings to order refunds.

On September 4, 2009, various parties, including PGE, filed a petition for a writ of certiorari with the U.S. Supreme Court requesting that the Supreme Court review the decision of the Ninth Circuit in the Pacific Northwest Refund proceeding. In January 2010, the Supreme Court denied the petition for a writ of certiorari.

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 operations and cash flows in a future reporting period.

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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.

On September 30, 2009, the District Court ruled on PGE’s motion to dismiss most of the claims. In summary, the court denied PGE’s motion with respect to most of the plaintiff’s claims, but granted PGE’s motion with respect to certain of the plaintiff’s claims. The principal claims that remain are (i) that PGE constructed Boardman without complying with the 1974 and 1977 federal pre-construction permitting requirements, (ii) that PGE modified Boardman in the 1990s without complying with Oregon’s pre-construction permitting requirements, and (iii) that certain modifications to Boardman triggered new source performance standards.

Management cannot predict the ultimate outcome of the above matter. However, 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 operations 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 18, 2010, there were 1,182 holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $19.10 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 operations 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, James J. Piro, the Chief Executive Officer of the Company, certified to the NYSE on June 4, 2009 that he 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 Operations” 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, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, 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, projections and forecasts are expressed in good faith and are believed by PGE to have a reasonable basis, including, but not limited to, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. There can be no assurance that PGE’s expectations, beliefs or projections and forecasts 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.

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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.

Future Energy Resource Strategy—In November 2009, PGE filed a new IRP that includes a four-year strategy for the acquisition of new resources and a 20-year strategy that outlines long-term expectations for resource needs and portfolio performance. PGE projects that it will need approximately 873 MWa of new resources by 2015, increasing to approximately 1,396 MWa by 2020, to meet customer demand. These requirements, primarily driven by continued load growth and the expiration of certain long-term power supply contracts, are expected to be met by energy efficiency measures, increased renewable resources, new transmission capability, and new generating plants.

Although the IRP as filed includes operating Boardman until 2040, the Company is exploring alternatives for the plant, including operating it until 2020 or using an alternative fuel source.

For additional information, see “Future Energy Resource Strategy” in the Power Supply section of Item 1.—“Business” and the Capital Requirements section in this Item 7.

General Rate Case—On February 16, 2010, PGE filed with the OPUC a 2011 General Rate Case, which is based on a 2011 test year. PGE filed for a $125 million increase in annual revenues, representing an approximate 7.4% overall increase in customer prices, which includes a 2% decrease related to projected power costs. In addition, PGE is proposing a capital structure of 50% debt and 50% equity, a return on equity of 10.5%, a cost of capital of 8.289%, an average rate base of approximately $3.2 billion, and the following:

Based upon uncertainties related to the expected life and alternative operating plans for PGE’s Boardman coal plant, the Company has included a separate tariff to implement necessary rate changes resulting from decisions regarding the future operation of the plant. For additional information, see Boardman emissions controls in the Capital Requirements section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Regulatory review of the 2011 General Rate Case will continue throughout 2010, with a final order expected to be issued by the OPUC by mid-December 2010. New rates are expected to become effective January 1, 2011. Additional information regarding PGE’s 2011 General Rate Case filing, including copies of direct testimony and exhibits, is available on the Company’s Internet website at www.portlandgeneral.com. Information may also be obtained on the OPUC Internet website at www.puc.state.or.us.

Capital and Financing—PGE’s 2009 and 2010 capital requirements are related primarily to the following major Board-approved projects and debt maturities:

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To fund these projects and debt maturities, the Company issued $580 million of first mortgage bonds and 12,477,500 shares of common stock for net proceeds of $170 million in 2009. In addition, PGE expects cash from operations to be approximately $526 million in 2010 and plans to issue $250 million of long-term debt in 2010, of which $70 million was issued in January 2010.

Customers and Demand—The economic downturn resulted in an 11.4% unemployment rate in the state of Oregon as of December 31, 2009. As a result, the Company experienced an overall decrease of 3.3% in retail energy deliveries (2.4% weather adjusted) in 2009 compared to 2008. The following table indicates deliveries, by customer class, including Direct Access customers, during the past two years:

(1) - In thousands of MWh.

Wholesale energy markets were also affected by the weak economy, with prices continuing at low levels. As a result of both lower prices and a reduction in energy sales, wholesale revenues in 2009 declined 43% from 2008.

The Company projects that weather adjusted retail energy deliveries will remain flat in 2010 due to the offsetting effects of continued weak employment and a moderate rebound in deliveries to industrial customers, including those in the high technology sector.

As indicated below, seasonally adjusted 2009 unemployment rates for the United States, the state of Oregon, and the Portland/Salem metropolitan area were all higher than in 2008. Further, unemployment rates for both Oregon and the Portland/Salem area exceeded the national average in both years. The majority of the Company’s service territory lies within the Portland/Salem metropolitan area.

Power Operations—PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. In 2009, the Company’s generating plants provided approximately 57% of its retail load requirement, compared to 62% in 2008. The decrease in 2009 compared to 2008 was due to economic dispatch decisions and the following extended maintenance and repair outages in 2009:

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Availability of the plants that PGE operates approximated 89% in 2009, 92% in 2008, and 93% in 2007. The availability of Colstrip, which PGE does not operate, approximated 68% in 2009, compared to 97% in 2008 and 87% in 2007. Although generation from PGE’s hydroelectric plants provided approximately 10% of the Company’s retail load requirement in 2009, 2008 and 2007, hydro generation decreased 1% in 2009 compared to 2008, with current forecasts indicating continued below normal regional hydro conditions for 2010.

Biglow Canyon Phase II, a 150 MW wind project, was completed in August 2009, with completion of Phase III, a 175 MW wind project, expected in the third quarter of 2010. These additions to PGE’s generation portfolio are important steps in helping to meet Oregon’s Renewable Energy Standard (RES). Wind generation increased 30% in 2009 compared to 2008 and provided 3% of PGE’s retail load requirement in 2009 compared to 2% in 2008.

Legal, Regulatory and Environmental Matters—PGE is a party to certain 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 additional information regarding the above and other matters, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements.

Boardman Deferral Amortization—On February 12, 2010, PGE received an order from the OPUC that granted the recovery of 50% of the $26.4 million of deferred excess replacement power costs associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006. PGE had deferred such costs in accordance with an order issued by the OPUC on February 12, 2007, with amortization of the deferral to be determined in a future ratemaking proceeding that would include a prudency review of the Company’s actions with respect to the outage and the acquisition of replacement power. Upon completion of the review, the OPUC concluded that a partially unsecured bearing pedestal was one of several factors that resulted in the outage. As a result, the OPUC concluded that partial recovery of the replacement power costs was warranted. In its order the OPUC authorized the collection of $13.2 million, plus interest (approximately $5.3 million as of December 31, 2009), of the deferred amount. Such recovery will be offset in the first quarter of 2010 with certain credits currently owed customers related to accrued savings on prior decommissioning activities at PGE’s closed Trojan Nuclear Plant, with no impact on current customer prices. As a result of the reduction in the allowed recovery amount, the Company recorded a pre-tax write-off of approximately $18 million, including interest, in the fourth quarter of 2009.

The following retail price adjustments, as approved by the OPUC, became effective on January 1, 2010:

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The above items, combined with other miscellaneous tariff changes, result in an overall retail price decrease of approximately 1.8% effective January 1, 2010.

Rate actions pending as of January 1, 2010 include, but are not limited to, the following:

For 2009, PGE recorded an estimated $13 million refund to customers, which, if approved by the OPUC, would begin June 1, 2011.

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 includes provisions for several enhanced tax benefits, many of which are favorable to renewable energy and energy efficiency projects. For PGE’s renewable energy projects, such as Biglow Canyon, the production tax credit was extended from 2009 through 2012. In addition pursuant to the Act, PGE was able to claim bonus depreciation in 2009. Bonus depreciation equals 50% of the basis of certain assets placed in service in the given year.

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Results of Operations

The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations for 2009 compared to 2008, and for 2008 compared to 2007, which follow hereafter.

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