UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

Oregon	93-0256820
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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

Common Stock, no par value	New York Stock Exchange
(Title of class)	(Name of exchange on which registered)

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

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

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

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

Indicate by check mark 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  [x]    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.  [x]

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.

Large accelerated filer	[x]	Accelerated filer	[ ]
Non-accelerated filer	[ ]	Smaller reporting company	[ ]

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, 2011, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $1,900,588,219. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 17, 2012, there were 75,367,284shares of common stock outstanding.

Documents Incorporated by Reference

Part III, Items 10 - 14 Portions of Portland General Electric Company’s definitive proxy statement to be filed pursuant to Regulation 14A for the 2012 Annual Meeting of Shareholders to be held on May 23, 2012.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS

Definitions		4
	PART I
Item 1.	Business.	5
Item 1A.	Risk Factors.	24
Item 1B.	Unresolved Staff Comments.	30
Item 2.	Properties.	31
Item 3.	Legal Proceedings.	33
Item 4.	Mine Safety Disclosures.	35
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	36
Item 6.	Selected Financial Data.	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	63
Item 8.	Financial Statements and Supplementary Data.	66
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	120
Item 9A.	Controls and Procedures.	120
Item 9B.	Other Information.	121
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	122
Item 11.	Executive Compensation.	122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	122
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	122
Item 14.	Principal Accounting Fees and Services.	122
	PART IV
Item 15.	Exhibits, Financial Statement Schedules.	123
	SIGNATURES	126

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DEFINITIONS

The following abbreviations or acronyms used throughout this Form 10-K are defined below:

Abbreviation or Acronym	Definition
AFDC	Allowance for funds used during construction
AUT	Annual Power Cost Update Tariff
Beaver	Beaver natural gas-fired generating plant
Biglow Canyon	Biglow Canyon Wind Farm
Boardman	Boardman coal-fired generating plant
BPA	Bonneville Power Administration
CAA	Clean Air Act
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
Coyote Springs	Coyote Springs Unit 1 natural gas-fired generating plant
Dth	Decatherm = 10 therms = 1,000 cubic feet of natural gas
DEQ	Oregon Department of Environmental Quality
EPA	United States Environmental Protection Agency
ESA	Endangered Species Act
ESS	Electricity Service Supplier
FERC	Federal Energy Regulatory Commission
IRP	Integrated Resource Plan
ISFSI	Independent Spent Fuel Storage Installation
kV	Kilovolt = one thousand volts of electricity
kW	Kilowatt = one thousand watts of electricity
kWh	Kilowatt hours
Moody’s	Moody’s Investors Service
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hours
NRC	Nuclear Regulatory Commission
NVPC	Net Variable Power Costs
OATT	Open Access Transmission Tariff
OEQC	Oregon Environmental Quality Commission
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
Port Westward	Port Westward natural gas-fired generating plant
REP	Residential Exchange Program
RPS	Renewable Portfolio Standard
S&P	Standard & Poor’s Ratings Services
SEC	United States Securities and Exchange Commission
SIP	Oregon Regional Haze State Implementation Plan
Trojan	Trojan nuclear power plant
USDOE	United States Department of Energy
VIE	Variable interest entity

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PART I

ITEM 1.     BUSINESS.

General

Portland General Electric Company (PGE or the Company) was incorporated in 1930 and 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 on the forecasted cost to serve retail customers, and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). The Company’s retail load requirement is met with both Company-owned generation and power purchased in the wholesale market. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in order to obtain reasonably-priced power for its retail customers. PGE is publicly-owned, with its common stock listed on the New York Stock Exchange, and operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis.

PGE’s 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 2011 its service area population was 1.7 million, comprising approximately 44% of the state’s population. During 2011, the Company added 1,790 customers and as of December 31, 2011, served a total of 822,466 retail customers.

PGE had 2,634 employees as of December 31, 2011, with 840 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 804 and 36 employees and expire in February 2015 and August 2014, respectively.

Available Information

PGE’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 United States Securities and Exchange Commission (SEC). It is not intended that PGE’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

PGE is subject to both federal and state regulation, which can have a significant impact on the operations of the Company. 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), the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), and the Nuclear Regulatory Commission (NRC).

FERC Regulation

The Company is a “licensee,” a “public utility,” and a “user, owner and operator of the bulk power system,” 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 projects, accounting policies and practices, short-term debt issuances, and certain other matters.

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 in June 2013.

Transmission—PGE offers transmission service pursuant to its 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, also known as OASIS. As of December 31, 2011, PGE owned approximately 1,100 circuit miles of transmission lines. For additional information, see the Transmission and Distribution section in this Item 1. and in Item 2.—“Properties.”

Reliability and Cyber Security Standards—Pursuant to the Energy Policy Act of 2005 (EPAct 2005), the FERC has adopted mandatory reliability standards for owners, users and operators of the bulk power 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. These standards include Critical Infrastructure Protection standards, a set of cyber security standards that provide a framework to identify and protect critical cyber assets used to support reliable operation of the bulk power system.

Pipeline—The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide the FERC authority in matters related to the 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 79.5% ownership interest in and is the operator of record of the Kelso-Beaver Pipeline, a 17-mile interstate pipeline that provides natural gas to its Port Westward and Beaver plants. As the operator of record, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety standards, operator qualification standards and public awareness requirements.

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 the consideration of numerous natural resource issues and environmental conditions. PGE holds FERC licenses for the Company’s projects on the Deschutes, Clackamas, and Willamette Rivers. 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

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Uniform System of Accounts and published accounting releases. Such financial statements are included in annual and quarterly reports filed with the FERC.

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. The Company, pursuant to an order issued by the FERC on December 28, 2011, is authorized to issue up to $700 million of short-term debt through February 6, 2014.

NRC Regulation

The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s Trojan nuclear power plant (Trojan), 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 (USDOE) 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 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 securities, 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. For additional information on the integrated resource planning process, see Power Supply section of this Item 1.

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. The seven volunteer members of the EFSC are appointed to four-year terms by the state’s governor, with staff support provided by the Oregon Department of Energy.

Integrated Resource Plan—Unless the OPUC directs otherwise, PGE is required to file with the OPUC an Integrated Resource Plan (IRP) within two years of its previous IRP acknowledgment order. The IRP guides the utility on how it will meet future customer demand and describes the Company’s future energy supply strategy, 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.

Ratemaking—Under Oregon law, the OPUC is required to ensure that prices and terms of service are fair, non-discriminatory, and provide regulated companies an opportunity to earn a reasonable return on their investments. Customer prices are determined through formal ratemaking proceedings that generally include testimony by participating parties, discovery, 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.

• General Rate Cases. PGE periodically evaluates the need to change its retail electric price structure to sufficiently cover its operating costs and provide a reasonable rate of return. Such changes are requested pursuant to a comprehensive general rate case process that includes a forecasted test year, debt-to-equity

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capital structure, return on equity, and overall rate of return. Revenue requirements and retail customer price changes are proposed based upon such factors. PGE’s most recent general rate case was the 2011 General Rate Case, which became effective on January 1, 2011. For additional information, see the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

• Power Costs. In addition to price changes resulting from the general rate case process, the OPUC has approved the following mechanisms by which PGE can adjust retail customer prices to cover the Company’s NVPC, which consists of the cost of power and fuel (including related transportation costs) less revenues from wholesale power and fuel sales: 

▪ Annual Power Cost Update Tariff (AUT). Under this tariff, customer prices are adjusted annually to reflect the latest forecast of NVPC. Such forecasts assume average regional hydro conditions (based on seventy years of stream flow data covering the period 1928 - 1998) and current hydro operating parameters. The NVPC forecasts also assume average wind conditions (based on wind studies completed in connection with the permitting process of the wind farm) for PGE-owned wind generation and normal operating conditions for thermal generating plants. An initial NVPC forecast, submitted to the OPUC by April 1st each year, is updated during the year and finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, become effective at the beginning of the next calendar year; and 

▪ Power Cost Adjustment Mechanism (PCAM). Customer prices can also be adjusted to reflect a portion of the difference between each year’s forecasted NVPC included in prices and actual NVPC for the year. Under the PCAM, PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and that included in base prices (baseline NVPC). The PCAM utilizes an asymmetrical deadband range within which PGE absorbs cost variances, with a 90/10 sharing of such variances between customers and the Company outside of the deadband. Annual results of the PCAM are subject to application of a regulated earnings test, under which a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE. A collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. A final determination of any customer refund or collection is made by the OPUC through a public filing and review typically during the second half of the following year. The OPUC order in PGE’s 2011 General Rate Case provides for a fixed deadband range of $15 million below, to $30 million above, forecasted NVPC, beginning in 2011. For additional information, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 

• Renewable Energy. The 2007 Oregon Renewable Energy Act (the Act) established a Renewable Portfolio Standard (RPS) which requires that PGE serve at least 5% of its retail load with renewable resources by 2011, 15% by 2015, 20% by 2020, and 25% by 2025. PGE has sufficient renewable resources to meet the 2011 - 2014 requirements of the Act. Further, the Company expects to have sufficient resources to meet the 2015 requirements with additional resources included in its most recent Integrated Resource Plan (IRP). It is anticipated that requirements for subsequent years will be met by the acquisition of additional renewable resources, as determined pursuant to the Company’s integrated resource planning process. The Act also allows Renewable Energy Credits, resulting from energy generated from qualified renewable resources placed in service after January 1, 1995, to be carried forward, with any excess of what is required to meet the Company’s compliance obligation used to fulfill RPS requirements of future years. For additional information, see the Power Supply section in this Item 1.

The Act also provides for the recovery in customer prices of all prudently incurred costs required to comply with the RPS. 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 prices. Under the RAC, PGE submits a filing by April 1st of each year for new renewable resources

8

expected to be placed in service in the current year, with prices to become effective January 1st of the following year. In addition, the RAC provides for the deferral and subsequent recovery 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.

Retail Customer Choice Program—PGE’s commercial and industrial customers have access to pricing options other than cost-of-service, including direct access and daily market based pricing. All commercial and industrial customers are eligible for direct access, whereby customers purchase their electricity from an Electricity Service Supplier (ESS), and PGE continues to deliver the energy to the customers. Large commercial and industrial customers may elect to be served by PGE on a daily market based price. Certain large commercial and industrial customers may elect to be removed from cost-of-service pricing for a fixed three-year or a minimum five-year term, to be served either by an ESS or under a market price option.

The retail customer choice program has no material impact on the Company’s financial condition or operating results. Revenue changes resulting from increases or decreases in electricity sales to direct access customers are substantially offset by changes in the Company’s cost of purchased power and fuel. Further, the program provides for “transition adjustment” charges or credits to direct access and market based pricing customers that reflect the above- or below-market cost of energy resources owned or purchased by the Company. Such adjustments are designed to ensure that the costs or benefits of the program do not unfairly shift to those customers that continue to purchase their energy requirements from the Company.

Residential and small commercial customers can purchase electricity from PGE among a portfolio of price options that include basic cost-of-service, time-of-use, and renewable resource prices.

Energy Efficiency Funding—Oregon law 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. Approximately $51 million was collected from customers for this charge in 2011. The Company estimates that $47 million will be collected from customers in 2012.

In addition to the public purpose charge, PGE also remits to the ETO amounts collected under an Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. This charge was approximately 1.8% in 2011 and increased to 2.7% effective January 1, 2012, for applicable customers. Under the tariff, approximately $28 million was collected from eligible customers in 2011. The Company estimates that $42 million will be collected in 2012.

Decoupling—The decoupling 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. The mechanism provides for customer collection if weather adjusted use per customer is lower than levels included in the Company’s most recent general rate case; it also provides for customer refunds if weather adjusted use per customer exceeds levels included in the general rate case.

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During 2011, PGE recorded an estimated refund of $2 million, which resulted primarily from actual weather adjusted use per customer being slightly higher than levels included in the 2011 General Rate case. Pending review and approval by the OPUC, any resulting refund to customers would be expected over a one-year period beginning June 1, 2012. For 2010, the Company recorded an estimated collection of $8 million, as weather adjusted use per customer was less than levels included in the 2009 General Rate Case. After review, the OPUC approved collections from customers over a one-year period that began June 1, 2011.

As part of the Company’s 2011 General Rate Case, the OPUC authorized the continued use of the decoupling mechanism through December 31, 2013.

Regulatory Accounting

PGE is subject to accounting principles generally accepted in the United States of America, and as a regulated public utility, the effects of rate regulation are reflected 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 prices. 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 reflected in future prices, 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 in Item 8.—“Financial Statements and Supplementary Data.”

Customers and Revenues

PGE conducts retail electric operations exclusively in Oregon within a service area approved by the OPUC. Retail customers are generally classified within one of the following three categories: i) residential; ii) commercial; or iii) industrial. Within its service territory, the Company competes with: i) the local natural gas distribution company for the energy needs of residential and commercial space heating, water heating, and appliances, and ii) fuel oil suppliers, primarily for residential customers’ space heating needs. In addition, the Company distributes power to commercial and industrial customers that choose to purchase their energy supply from an ESS.

In 2011, three ESSs were registered with PGE to transact business with the Company and its customers and provided an average of 242 direct access customers with a total retail load of 988 thousand megawatt hours (MWh) representing 8.5% of PGE’s commercial and industrial retail energy deliveries and 5.1% of the Company’s total retail energy deliveries for the year. In 2010, ESSs supplied an average of 221 direct access customers with a total retail load representing 9.3% of PGE’s commercial and industrial retail energy deliveries and 5.6% of the Company’s total retail energy deliveries for the year.

Beginning in January 2012, two ESSs are registered with PGE to transact business with the Company and its customers and are expected to supply energy to 484 direct access customers with an estimated annual load representing 11% of the Company’s expected commercial and industrial load and 6% of total retail deliveries. Of these direct access customers, a total of 137, with an estimated annual retail load requirement representing 8% of the Company’s expected commercial and industrial load and 5% of total retail deliveries, will be served on a three- or five-year basis.

The Company includes direct access customers in its customer counts and energy delivered to such customers in its total retail energy deliveries although Retail revenues reflect only delivery charges and transition adjustments for these customers.

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PGE’s Revenues are comprised of the following (dollars in millions):

	Years Ended December 31,
	2011					2010				2009
	Amount			%		Amount		%		Amount			%
Retail:
Residential	$	877		48	%	$	803	45	%	$	856		47	%
Commercial	635			35		601		34		642			36
Industrial	226			13		221		12		166			9
Subtotal	1,738			96		1,625		91		1,664			92
Other accrued revenues, net	(16		)	(1	)	39		2		(7		)	—
Total retail revenues	1,722			95		1,664		93		1,657			92
Wholesale revenues	60			3		87		5		112			6
Other operating revenues	31			2		32		2		35			2
Revenues	$	1,813		100	%	$	1,783	100	%	$	1,804		100	%

Certain averages for retail customers who purchase their energy requirements from the Company^* are as follows: 

	Years Ended December 31,
	2011			2010		2009
Average usage per customer (in kilowatt hours):
Residential	10,740			10,384		11,059
Commercial	68,835			68,040		70,853
Industrial	14,932,550			12,986,466		9,343,838
Average revenue per customer (in dollars):
Residential	$	1,160		$	1,049	$	1,111
Commercial	6,091			5,769		6,127
Industrial	919,764			859,251		660,839
Average revenue per kilowatt hour (in cents):
Residential		10.80	¢	10.10¢		10.05¢
Commercial	8.85			8.48		8.65
Industrial	6.16			6.62		7.07

^*  Excludes customers who purchase their energy requirements from ESSs.

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 classified as residential, commercial, or industrial, with no single customer representing more than 4% 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 12% of total retail revenues in 2011, they represented nine different groups, including high technology, paper manufacturing, metal fabrication, health services, and governmental agencies.

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Averages over the past three-year period by customer class are as follows, with energy deliveries and revenues expressed as a percentage of the totals:

	Average Number of Customers	Energy Deliveries	Revenues
Residential	717,358	40%	51%
Commercial	102,148	39	37
Industrial	264	21	12

In accordance with state regulations, PGE’s retail customer prices are determined through general rate case proceedings and various tariffs filed with the OPUC from time to time, and are based on the Company’s cost of service. Additionally, the Company offers different pricing options. Under PGE’s daily market price option, the Company delivered electricity to 185 commercial and industrial customers in 2011, representing 1.5% of commercial and industrial deliveries and less than 1% of total retail energy deliveries.

Under the renewable energy options, approximately 85,000, residential and small commercial customers were enrolled compared to 77,000 and 82,000 as of December 31, 2010, and 2009, respectively. Under time-of-use options, approximately 4,500 customers were enrolled compared to 2,100, and 2,130 as of December 31, 2010, and 2009, respectively.

For additional information on customer options, see “Retail Customer Choice Program” within the Regulation and Rates section of this Item 1. Additional information on the customer classes follows.

Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), mobile homes, and small farms.

Residential demand is sensitive to the effects of weather, with demand historically highest during the winter heating season. Due to the increased use of air conditioning in PGE’s service territory, the summer peaks have increased in recent years. Economic conditions can also affect demand from the Company’s residential customers, as historical data suggests that high unemployment rates contribute to a decrease in demand. Residential demand is also impacted by energy efficiency measures; however, the Company’s decoupling mechanism is intended to mitigate the financial effects of such measures.

During 2011, total residential deliveries increased 3.8% compared to 2010 as a result of cooler weather during the heating season, and an increase in the average number of customers. During 2010, total residential deliveries decreased 5.7% compared to 2009, with milder weather conditions accounting for nearly half of the decrease.

Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. This customer class consists of most businesses, including small industrial companies, and public street and highway lighting accounts.

Demand from the Company’s commercial customers is less susceptible to weather conditions than the residential class. Economic conditions and fluctuations in total employment in the region can also lead to corresponding changes in energy demand from commercial customers. Commercial demand is also impacted by energy efficiency measures, the financial effects of which are partially mitigated by the Company’s decoupling mechanism.

In 2011, favorable weather effects combined with the addition of an average of nearly 700 new customers contributed to the 2% increase in deliveries to commercial customers. During 2011, non-farm employment increased 1.6% in Oregon.

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During 2010, as the Oregon economy lost approximately 0.9% of its payroll, the Company’s commercial energy deliveries decreased 3.7% compared to 2009 with milder weather, including a very cool summer in 2010, contributing about one-third of the decline.

Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers, with pricing based on the amount of electricity delivered and the applicable tariff. Demand from industrial customers is primarily affected by economic conditions, with weather having little impact on this customer class.

A change in economic activity in Oregon and the United States can also lead to a change in energy demand from the Company’s industrial customers. In 2011, industrial deliveries rose 4.7% as demand increased from certain paper production customers, and the general economic conditions improved. In 2010, the Company’s industrial energy deliveries rose 3.3% compared to 2009, driven by increased demand from certain paper production customers in the latter half of 2010.

Other accrued revenues, net include items that are not currently in customer prices, but are expected to be in prices in a future period. Such amounts include deferrals recorded under regulatory mechanisms for the renewable adjustment clause, the power cost adjustment, and decoupling. See “State of Oregon Regulation” in the Regulation and Rates section of this Item 1 for further information on these items.

Other accrued revenues also include deferrals recorded pursuant to the 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 that are expected to continue until the year 2028. PGE receives monthly payments from BPA under the program and passes such payments along to eligible customers in the form of monthly billing credits. For the twelve months ended September 30, 2011, PGE received payments totaling $55 million and received $44 million during each of the twelve month periods ended September 30, 2010 and 2009. Payments for the twelve month period ending September 30, 2012 are expected to be approximately $58 million, with such benefits to be credited to eligible customers.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. In doing so, the Company attempts to secure reasonably priced power, manage risk, and administer its current long-term wholesale contracts through economic dispatch decisions for its own generation. 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, hydro conditions, and daily and seasonal retail demand.

The majority of PGE’s wholesale electricity sales is to utilities and power marketers and is 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 operating revenues consist primarily of the sale of excess natural gas and oil, as well as revenues from transmission services, excess transmission capacity resales, pole contact rentals, and other electric services provided to customers.

Seasonality

Demand for electricity by PGE’s residential customers is affected by seasonal weather conditions, as discussed above. The Company uses heating and cooling degree-days to determine the effect of weather on the demand for

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electricity. Heating and cooling degree-days provide cumulative variances in the average daily temperature from a baseline of 65 degrees, over a period of time, to indicate the extent to which customers are likely to use, or have used, 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 for the most recent year provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-Days	Cooling Degree-Days
2011	4,650	362
2010	4,187	314
2009	4,391	627
15-year average for 2011	4,219	464

PGE’s all-time high net system load peak of 4,073 Megawatts (MW) occurred in December 1998. The Company’s all-time “summer peak” of 3,949 MW occurred in July 2009. The following table presents the Company’s average winter and summer loads for the periods indicated along with the corresponding peak load and month in which it occurred:

		Average Load		Peak Load
		MW	Month	MW
2011	Winter	2,612	January	3,555
	Summer	2,233	September	3,340
2010	Winter	2,445	November	3,582
	Summer	2,220	August	3,544
2009	Winter	2,658	December	3,851
	Summer	2,267	July	3,949

The Company tracks and evaluates both base load growth and peak capacity for purposes of long-term load forecasting and integrated resource planning as well as for preparing general rate case assumptions. Behavior patterns, conservation, energy efficiency initiatives and measures, weather effects, and demographic changes all play a role in determining expected future customer demand and the resulting resources the Company will need to adequately meet those loads and maintain adequate capacity reserves.

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Power Supply

PGE relies upon its generating resources as well as short- and long-term power and fuel 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 a wind farm located at Biglow Canyon in eastern Oregon. The volume of electricity the Company generates is dependent upon, among other factors, the capacity and availability of its generating resources. Capacity of the thermal plants 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. Capacity of both hydro and wind generating resources represent the nameplate MW, which varies from actual energy expected to be received as these types of generating resources are highly dependent upon river flows and wind conditions, respectively. Availability represents the percentage of the year the plant was available for operations, which reflects the impact of planned and forced 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 its energy requirements and enhance customers’ ability to manage their energy use more efficiently.

PGE’s resource capacity (in MW) was as follows:

	As of December 31,
	2011			2010			2009
	Capacity	%		Capacity	%		Capacity	%
Generation:
Thermal:
Natural gas	1,172	28	%	1,157	24	%	1,175	26	%
Coal	670	16		670	14		670	15
Total thermal	1,842	44		1,827	38		1,845	41
Hydro	489	12		489	10		489	11
Wind *	450	11		450	9		275	6
Total generation	2,781	67		2,766	57		2,609	58
Purchased power:
Long-term contracts:
Capacity/exchange	190	4		540	11		640	14
Mid-Columbia hydro	335	8		507	10		548	12
Confederated Tribes hydro	150	4		150	3		150	3
Wind	44	1		44	1		35	1
Other	210	5		221	5		233	5
Total long-term contracts	929	22		1,462	30		1,606	35
Short-term contracts	458	11		612	13		315	7
Total purchased power	1,387	33		2,074	43		1,921	42
Total resource capacity	4,168	100	%	4,840	100	%	4,530	100	%

 * Capacity represents nameplate and differs from expected capacity, which is expected to range from 135 MW to 180 MW, dependent upon wind conditions.

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For information regarding actual generating output and purchases for the years ended December 31, 2011, 2010 and 2009, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Generation

That portion of PGE’s retail load 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, the market price of electricity, and wind variability.

Thermal PGE has a 65% ownership interest in Boardman, which it operates, and a 20% ownership interest in Colstrip Units 3 and 4. These two coal-fired generating facilities provided approximately 21% of the Company’s total retail load requirement in 2011, compared to 26% in 2010 and 20% in 2009. The Company’s three natural gas-fired generating facilities, Port Westward, Beaver, and Coyote Springs, provided approximately 11% of its total retail load requirement in 2011 and 24% in 2010 and 2009.

The thermal plants, which have a combined capacity of 1,842 MW, provide reliable power for the Company’s customers with plant availability, excluding Colstrip, of 90% in 2011, 94% in 2010, and 84% in 2009 and Colstrip plant availability of 84% in 2011, 95% in 2010, and 68% in 2009.

Hydro The Company’s FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), four plants on the Clackamas River, and one on the Willamette River. The licenses for these projects expire at various dates from 2035 to 2055. These plants, which have a combined capacity of 489 MW, provided 10% of the Company’s total retail load requirement in 2011, 2010 and 2009, with availability of 100% in 2011 and 99% in both 2010 and 2009. Northwest hydro conditions have a significant impact on the region’s power supply, with water conditions significantly impacting PGE’s cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases.

PGE has a 66.67% ownership interest in the 450 MW Pelton/Round Butte hydroelectric project on the Deschutes River, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The Tribes have an option to purchase an additional undivided 16.66% interest in Pelton/Round Butte at its discretion no sooner than December 31, 2021. The Tribes have a second option to purchase an undivided 0.02% interest in Pelton/Round Butte at its discretion no sooner than April 1, 2041. If both options are exercised by the Tribes, the Tribes’ ownership percentage would exceed 50%.

Wind Biglow Canyon Wind Farm (Biglow Canyon), located in Sherman County, Oregon, is PGE’s largest renewable energy resource with 217 wind turbines with a total installed capacity of approximately 450 MW. It was completed and placed in service in three phases between December 2007 and August 2010. In 2011, Biglow Canyon provided 6% of the Company’s total retail load requirement, compared to 4% in 2010 and 3% in 2009, with availability of 97% in 2011 and 96% in both 2010 and 2009. The energy received from wind resources differs from the nameplate capacity and is expected to range from 135 MW to 180 MW for Biglow Canyon, dependent upon wind conditions.

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, 2011, there were 31 projects that together can provide approximately 69 MW of diesel-fired capacity at peak times. In addition, there were 12 projects under construction that are expected to provide an additional 30 MW.

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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, and option contracts to manage its exposure to volatility in natural gas prices.

Coal Boardman—PGE has fixed-price purchase agreements that provide coal for Boardman into 2014. The coal is obtained from surface mining operations in Wyoming and Montana and is delivered by rail under two separate ten-year transportation contracts which extend through 2013.

PGE expects to begin seeking requests for proposal in mid-2012 for the purchase of coal to fill open positions for 2013 and beyond. The terms of any contracts and quality of coal are expected to be staged in alignment with the timing of the installation of required emissions controls. For additional information on Boardman’s emissions controls, see the Capital Requirements section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.” PGE believes that sufficient market supplies of coal are available to meet anticipated operations of Boardman for the foreseeable future.

Natural Gas Port Westward and Beaver—PGE manages the price risk of natural gas supply for Port Westward through financial contracts up to 60 months in advance. Physical supplies for Port Westward and Beaver are generally purchased within 12 months of delivery and based on anticipated operation of the plants. PGE owns 79.5%, and is the operator of record, of the Kelso-Beaver Pipeline, which directly connects both generating plants to the Northwest Pipeline, an interstate natural gas pipeline operating between British Columbia and New Mexico. Currently, PGE transports gas on the Kelso-Beaver Pipeline for its own use under a firm transportation service agreement, with capacity offered to others on an interruptible basis to the extent not utilized by the Company. PGE has access to 103,305 Dth per day of firm gas transportation capacity to serve the two plants.

PGE also has contractual access through April 2017 to natural gas storage in Mist, Oregon, from which it can draw in the event that gas supplies are interrupted or if economic factors require its use. This storage may be used to fuel both Port Westward and Beaver. PGE believes that sufficient market supplies of gas are available to meet anticipated operations of both plants for the foreseeable future.

The Beaver generating plant has the capability to operate on No. 2 diesel fuel oil when it is economical or if the plant’s natural gas supply is interrupted. PGE had an approximate 7-day supply of ultra-low sulfur diesel fuel oil at the plant site as of December 31, 2011. The current operating permit for Beaver limits the number of gallons of fuel oil that can be burned daily, which effectively limits the daily hours of operation of Beaver.

Coyote Springs—PGE manages the price risk of natural gas supply for Coyote Springs through financial contracts up to 60 months in advance, while physical supplies are generally purchased within 12 months of delivery and based on anticipated operation of the plant. Coyote Springs utilizes 41,000 Dth per day of natural gas when operating at full capacity, with firm transportation capacity on three pipeline systems accessing gas fields in Alberta, Canada. PGE believes that sufficient market supplies of gas are available for Coyote Springs for the foreseeable future, based on anticipated operation of the plant. Although Coyote Springs was designed to also operate on fuel oil, such capability has been deactivated in order to optimize natural gas operations.

Purchased Power

PGE supplements its own generation with power purchased in the wholesale market to meet its retail load requirements. The Company utilizes short- and long-term wholesale power purchase contracts in an effort to provide the most favorable economic mix on a variable cost basis. Such contracts have original terms ranging from one month to 30 years and expire at varying dates through 2036.

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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 mitigates a portion of the potential future volatility in the average cost of purchased power and fuel.

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—PGE has three contracts that provide PGE with firm capacity to help meet the Company’s peak loads. The contracts range from 10 MW to 150 MW and expire at various dates from February 2012 through December 2016. They include a seasonal exchange contract with another western utility that helps meet winter--peaking requirements.

Mid-Columbia hydro—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of three hydroelectric projects on the mid-Columbia River. These contracts expire at various dates from 2017 through 2052. Although the projects currently provide a total of 335 MW of capacity, actual energy received is dependent upon river flows.

Confederated Tribes—PGE has a long-term agreement under which the Company purchases, at market prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides 150 MW of capacity, actual energy received is dependent upon river flows. The term of the agreement coincides with the term of the FERC license for this project, which expires in 2055.

Wind—The Company has three long-term contracts, which extend to various dates between 2028 and 2035, that provide for the purchase of renewable wind-generated electricity. Although these contracts provide a total of 44 MW of capacity, actual energy received is dependent upon wind conditions.

Other—These primarily consist of long-term contracts to purchase power from various counterparties, including other Pacific Northwest utilities, over terms extending into 2036.

Other also includes contracts that provide for the purchase of renewable solar-powered electricity as follows:

• PGE operates three photovoltaic solar power projects installed in the Portland area, with a combined installed capacity of 3.6 MW. PGE purchases 100% of the energy generated from two of the facilities and purchases any excess energy generated from one facility pursuant to a net metering arrangement with the Oregon Department of Transportation (ODOT);

• PGE has two 25-year purchase agreements for the power generated from two photovoltaic solar projects installed near Salem, Oregon. The construction of the projects was completed in mid-2011, with PGE then purchasing the power generated from these facilities, which have a combined generating capacity of 2.8 MW.

In January 2012, PGE completed the construction of a 1.75 MW photovoltaic solar power project, which was sold and simultaneously leased-back from a financial institution. The Company operates the project and receives 100% of the power generated by the facility.

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 30 minutes 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 in Item 8.—“Financial Statements and Supplementary Data.”

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Future Energy Resource Strategy

PGE’s most recent IRP was acknowledged by the OPUC on November 23, 2011. The IRP includes an action plan 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 needs 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. The projected energy gap increases by approximately 374 MW with the cessation of coal-fired operations at Boardman in 2020.

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

• Acquisition of 214 MWa of energy efficiency through continuation of Energy Trust of Oregon programs, with funding to be provided from the existing public purpose charge and through enabling legislation included in Oregon’s RPS;

• An additional 101 MWa of wind or other renewable resources necessary to meet requirements of Oregon’s RPS by 2015;

• Transmission capacity additions to interconnect new and existing energy resources in eastern Oregon to PGE’s services territory. For additional information on the Cascade Crossing Transmission Project (Cascade Crossing), see the Transmission and Distribution section in this Item 1;

• New natural gas generation facilities to help meet additional base load requirements estimated at 300 to 500 MW, which is expected to be available in the 2015 to 2017 timeframe;

• New natural gas generation facilities to help meet peak capacity requirements estimated at up to 200 MW, bi-seasonal peaking supply of 200 MW and winter-only peaking supply of 150 MW, all of which are expected to be available in the 2013 to 2015 timeframe; and

• Continued operations of the Boardman plant, including the addition of certain emissions controls and the continuation of coal-fired operation of the plant through 2020. 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 Operations.”

In January 2012, PGE requested that the OPUC acknowledge a draft request for proposals (RFP) that is expected to be issued in the second quarter of 2012, seeking electric power generating resources to help meet PGE’s capacity and energy needs, as outlined in the IRP discussion above. PGE expects to file a second RFP, for renewable resources, later in 2012.

The Company has filed with the OPUC a motion for a one-year extension to file its next IRP. If the motion is approved as submitted, PGE would be required to file its next IRP no later than November 2013. If not approved as submitted, PGE may be required to file its next IRP as early as November 2012.

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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 2011, PGE delivered approximately 20 million MWh in its balancing authority area through approximately 1,100 circuit 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 relies on transmission contracts with BPA to transmit a significant amount of the Company’s generation to its distribution system. 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’ energy 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:

• On property owned or leased by PGE; 

• Under or over streets, alleys, highways and other public places, the public domain and national forests, and state lands under franchises, easements or other rights that are generally subject to termination; 

• Under or over private property as a result of easements obtained primarily from the record holder of title; or 

• Under or over Native American reservations under grant of easement by the Secretary of the Interior or lease or easement by Native American tribes.

PGE’s wholesale transmission activities are regulated by the FERC. In accordance with its OATT, PGE offers several transmission services to wholesale customers:

• Network integration transmission service, a service that integrates generating resources to serve retail loads;

• Short- and long-term firm point-to-point transmission service, a service with fixed delivery and receipt points; and

• Non-firm point-to-point service, an “as available” service with fixed delivery and receipt points.

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

PGE’s current acknowledged IRP includes a proposal for an approximate 210-mile, 500 kV transmission project (the Cascade Crossing Transmission Project) that would help meet future electricity demand and improve future grid reliability by transmitting power from new and existing energy resources in eastern Oregon to the Company’s service territory. PGE continues to work with other stakeholders in the region in planning the project and is actively engaged in the federal, state, and tribal permitting processes. Subject to obtaining all necessary approvals, the expected in-service date would be late 2016 or early 2017. In October 2011, Cascade Crossing was selected as one of seven transmission projects in the nation to participate in the federal inter-agency Rapid Response Team for Transmission program to improve agency collaboration and expedite federal permitting.

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 can be assessed for failure to attain required performance levels, with amounts dependent upon the extent to which actual results fail to meet such requirements.

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For additional information regarding the Company’s transmission and distribution facilities, see Item 2.—“Properties.”

Environmental Matters

PGE’s operations are subject to a wide range of environmental protection laws and regulations, which pertain to air quality (including climate change), water quality, endangered species and wildlife protection, and hazardous waste. Environmental matters that relate to the siting and operation of generation, transmission, and substation facilities and the handling, accumulation, cleanup, and disposal of toxic and hazardous substances fall under the jurisdiction of various state and federal agencies. In addition, certain of the Company’s hydroelectric projects and transmission facilities are located on property under the jurisdiction of federal and state agencies, and/or tribal entities that have authority in environmental protection matters. The following discussion provides further information on certain regulations that affect the Company’s operations.

Air Quality

Clean Air Act—PGE’s operations, primarily its thermal generating plants, are subject to regulation under the federal Clean Air Act (CAA), which addresses, among other things, sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon monoxide, particulate matter, hazardous air pollutants, and greenhouse gas emissions (GHGs). Oregon and Montana, the states in which PGE facilities are located, also implement and administer certain portions of the CAA and have set standards that are at least equal to federal standards.

In June 2011, the United States Environmental Protection Agency (EPA) approved revised rules to reduce SO₂ and NO_x emissions at Boardman that have resulted in the installation of certain emissions controls during 2011. To further reduce SO₂ emissions, plans call for the use of lower sulfur coal and the addition of a Dry Sorbent Injection system to Boardman in 2014, at an estimated capital cost to the Company of $27 million, including AFDC. The revised rules also provide for coal-fired operation at Boardman to cease no later than December 31, 2020. Construction or acquisition costs of replacement generating capacity will be considered in future customer prices.

In December 2011, the EPA issued new emissions limits under the CAA’s National Emission Standards for Hazardous Air Pollutants (NESHAP) regulating hazardous air pollutant emissions, from coal- and oil-fired electric generating units. Emission limits included in the NESHAP are based on the application of maximum achievable control technology (MACT). Based on its review of the rules and the preliminary full-scale test results, the Company believes the Boardman plant should be able to meet the MACT requirements with the installation of the currently planned controls. The operator of the Colstrip plant has provided the Company with estimated costs for emission control modifications to Units 3 and 4 that may be necessary to meet the MACT requirements. Based on this estimate, the Company expects that its share of these costs, as a 20% owner of Units 3 and 4, will not exceed $10 million.

Regulation of mercury emissions is contemplated under NESHAP. However, the states of Oregon and Montana have previously adopted regulations concerning mercury emissions that have had an impact on the Company as follows:

Oregon—The Oregon Environmental Quality Commission (OEQC) has adopted final rules that pertain to mercury emissions from Boardman. Such rules require compliance with stated mercury limits by July 1, 2012, In 2011, PGE installed controls that are expected to eliminate 90% of the mercury emissions from the plant to comply with the rules.

Montana—The Montana Board of Environmental Review adopted final rules on mercury emissions from coal-fired generating plants, including Colstrip. With the installation of additional mercury control systems, Colstrip is in compliance with these requirements.

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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.”

PGE manages its air emissions by the use of low sulfur fuel, emissions and combustion controls and monitoring, and SO₂ allowances awarded under the CAA. The current allowance inventory and expected future annual SO₂ allowances, along with the recent and planned installation of emissions controls, are anticipated to be sufficient to permit the Company to continue to meet its compliance requirements and operate its thermal generating plants at forecasted capacity for at least the next several years.

Climate Change—State, regional, and federal legislative efforts continue with respect to establishing regulation of

greenhouse gas (GHG) emissions and their potential impacts on climate change. Recent or pending environmental measures include the following:

• In 2007, the State of Oregon adopted a non-binding policy guideline that sets a goal to reduce GHG emissions to 10% below 1990 levels by 2020. The guideline does not mandate reductions by any specific entity nor does it include penalties for failure to meet the goal.

• In 2009, the U.S. House of Representatives approved legislation that seeks to establish a cap and trade system for GHG emissions. However, the U.S. Senate did not act and it is uncertain whether a cap and trade system will move forward in the near term.

• Effective January 1, 2010, the EPA required mandatory measurement and reporting of GHG emissions. PGE is subject to these requirements and is meeting the monitoring and reporting requirements. Reported data will be used to establish a baseline for measuring progress toward any future emissions reduction targets in the United States.

• In 2010, the EPA finalized rules creating GHG thresholds that apply to the permitting process for stationary sources, such as electric generating facilities, under the Prevention of Significant Deterioration and Title V operating permit programs. The EPA has also issued guidance under these rules relating to Best Available Control Technology (BACT) requirements for new and modified stationary sources. In April 2011, the OEQC approved new state rules to implement these federal requirements and in December 2011, the rules were approved by the EPA. As a result of these rules, new or modified generating facilities may need to satisfy BACT requirements for limiting GHG emissions. The specific requirements applicable to a particular facility would be determined in connection with the permitting process.

• In December 2010, the EPA announced a proposed settlement agreement with states and environmental groups that would require the EPA to set GHG New Source Performance Standards (NSPS) for new and modified fossil fuel-based power plants, and guidelines for state-developed NSPS for existing sources. The deadlines for setting these standards and guidelines have been delayed and the timing is now unclear.

Any laws that impose mandatory reductions in GHG emissions may 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 ownership interest in Boardman and Colstrip coal-fired facilities, provide approximately 66% of the Company’s net generating capacity. If PGE were to incur incremental costs as a result of changes in the regulations regarding GHGs, the Company would seek recovery in customer prices.

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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 obtained permits where required, and has certificates of compliance for its hydroelectric operations under the FERC licenses.

Threatened and Endangered Species and Wildlife

Fish Protection—The federal Endangered Species Act (ESA) has granted protection to many populations of migratory fish species in the Pacific Northwest that have declined significantly over the last several decades. Long-term recovery plans for these species have caused major operational changes to many of the region’s hydroelectric projects. Over the years, these changes have resulted in reductions in hydroelectric generation capacity and shifts in the seasonality of much of the generation due to the timing of stored water releases, both of which can affect the price of power in the regional wholesale market. PGE purchases power in the wholesale market to serve its retail load requirements and has contracts to purchase power generated at some of the affected facilities on the mid-Columbia River in central Washington.

PGE is implementing a series of fish protection measures at its hydroelectric 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 licenses, the Deschutes River and Willamette River projects have been certified as low impact hydro, with 50 MWa of their output included as part of the Company’s renewable energy portfolio used to meet the requirements of Oregon’s RPS. Conditions required with the new operating licenses are expected to result in a minor reduction in power production and increase capital spending to modify the facilities to enhance fish passage and survival.

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. Because PGE operates electric transmission lines and wind generation facilities that can pose risks to a variety of such birds, the Company is required to have an avian protection plan. PGE has developed and implemented such a plan for its transmission and distribution facilities and is in the process of developing a plan for its wind facilities 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 (RCRA). In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, are regulated under the federal Toxic Substances Control Act.

The Company’s coal-fired generation facilities, Boardman and Colstrip, produce coal combustion byproducts, which have been exempt from federal hazardous waste regulations under the RCRA. The EPA is revisiting this exemption and is considering listing these residuals as hazardous wastes, which would likely have an impact on current disposal practices and could increase the Company’s cost of handling these materials and affect operations. The EPA has announced that the final rule would likely be issued in late 2012. The Company cannot predict the possible impact of this matter until the EPA provides further guidance on the proposed rules. If PGE were to incur incremental costs as a result of changes in the regulations, the Company would seek recovery in customer prices.

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PGE is also subject to regulation under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA), commonly referred to as Superfund. The CERCLA provides authority to the EPA to assert joint and several liability for investigation and remediation costs for designated Superfund sites. PGE is listed by the EPA as a Potentially Responsible Party (PRP) at two Superfund sites 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 sixty­nine PRPs, including PGE, which has historically owned or operated property near the river. In 2008, the EPA

requested further information from various parties, including PGE, concerning property several miles beyond the original river segment and, as a result, the PRPs now number over one hundred.

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 and PGE was included among fourteen PRPs.

For additional information on these EPA actions, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Under the Nuclear Waste Policy Act of 1982, the 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 from 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 former plant site. The spent nuclear fuel is expected to remain in 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. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

ITEM 1A.     RISK FACTORS.

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 PGE charges for its retail services, as authorized by the OPUC, are a major factor in determining the Company’s operating income, financial position, liquidity, and credit ratings. As a general matter, the Company will seek to recover in customer prices most of the costs incurred in connection with the operation of its business, including, among other things, the costs of compliance with legislative and regulatory requirements and the costs of damage from storms and other natural disasters. However, there can be no assurance that such recovery will be granted. The OPUC has the authority to disallow the recovery of any costs that it considers excessive or imprudently incurred. Further, the regulatory process does not guarantee 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 the interpretation of this standard.

In both PGE’s 2009 and 2011 general rate cases, overall price increases approved by the OPUC were less than the Company’s initial proposals. PGE attempts to manage its costs at levels consistent with the reduced price increases.

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However, if the Company is unable to do so, or if such cost management results in increased operational risk, the Company’s financial and operating results could be adversely affected. 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 Operations.”

The risk of volatility in power costs is partially mitigated through the Annual Power Cost Update Tariff (AUT) and the PCAM. PGE files an annual AUT with an update of PGE’s forecasted net variable power costs (baseline NVPC) to be reflected in customer prices. The PCAM provides a mechanism by which the Company can adjust future customer prices to reflect a portion of the difference between each year’s baseline NVPC included in customer prices and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband.” The OPUC order in PGE’s 2011 General Rate Case provides for a fixed deadband range of $15 million below, to $30 million above, baseline NVPC, beginning in 2011. Application of the PCAM requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, the PCAM is expected to only partially mitigate the potentially adverse financial impacts of forced generating plant outages, reduced hydro and wind availability, interruptions in fuel supplies, and volatile wholesale energy prices.

A continued weakening of the economy could reduce the demand for electricity and impair the financial stability of some of PGE’s customers, which could affect the Company’s results of operations.

The weak economy in Oregon over the past several years has resulted in reduced demand for electricity, which could continue. Further reduction in demand could affect the Company’s results of operations and cash flows. The weak economy could also result in an increased level of uncollectable customer accounts. Additionally, the Company’s vendors and service providers could experience cash flow problems and be unable to perform under existing or future contracts.

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, which ultimately could have an adverse effect on the Company’s liquidity and results of operations.

As part of its normal business operations, PGE purchases power and natural gas in the open market or under short-term, long-term, or variable-priced contracts. 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 regulatory and legislative processes 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 fair value of derivative instruments and cash requirements to purchase power and natural gas. If power and natural gas prices decrease from those contained in the Company’s existing purchased power and natural gas agreements, PGE may be required to provide increased collateral, which could adversely affect the Company’s liquidity. 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. 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.

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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. Variations in temperatures can affect customer demand for electricity, with warmer-than-normal winters or cooler-than-normal summers reducing energy sales and revenues. Weather conditions are the dominant cause of usage variations from normal seasonal patterns, particularly for residential customers. Severe weather can also disrupt energy delivery and damage the Company’s transmission and distribution system.

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

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 impacts of such outages; however, the cost sharing features of the mechanism do not provide full recovery in customer prices. Inability to recover such costs in future prices could have a negative impact on the Company’s results of operations.

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

PGE’s current position as a “short” utility requires that the Company supplement its own generation with wholesale market purchases to meet its retail load requirements. In addition, long-term increases in both the number of customers and demand for energy will require continued expansion and upgrade of PGE’s generation, transmission, and distribution systems. Construction of new facilities and modifications to existing facilities could be affected by various factors, including unanticipated delays and cost increases and the failure to obtain, or delay in obtaining, necessary permits from state or federal agencies or tribal entities, which could result in failure to complete the projects and the disallowance of certain costs in the rate determination process. In addition, 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 capital projects. Credit rating agencies evaluate 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 Investors Service (Moody’s) and/or Standard and Poor’s Ratings Services (S&P) reduce their rating on PGE’s unsecured debt to below investment grade, the Company 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.

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Current capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan as currently scheduled.

Access to capital and credit markets is important to PGE’s continued ability to operate. The Company potentially faces significant capital requirements over the next three to five years and expects to issue debt and equity securities, as necessary, to fund these requirements. In addition, because of contractual commitments and regulatory requirements, the Company may have limited ability to delay or terminate certain projects. 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 strategic plan.

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 matters are subject to many uncertainties, the ultimate outcome of which management cannot predict. The final resolution of certain matters in which PGE is involved could require that the Company incur expenditures 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 Item 3.—“Legal Proceedings” and Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Reduced stream flows and unfavorable wind conditions can adversely affect generation from PGE’s hydroelectric and wind resources. The Company could be required to replace generation from these sources with higher cost power from other facilities or with wholesale market purchases, which could have an adverse effect on operating results.

PGE derives a significant portion of its power supply from its own hydroelectric facilities and from those owned by certain public utility districts in the state of Washington with which the Company has long-term 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 on wholesale power purchases, both of which could have an adverse effect on operating results.

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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 prices could have a negative impact on the Company’s results of operations, as well as a reduction in renewable energy credits and loss of production tax credits (PTCs).

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 legislation or regulations could result in 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 facilities as well as other sectors of the economy. Although no such legislation has yet been enacted, 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 offsets, fuel switching, and the replacement of high-emitting generation facilities with lower emitting 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. Although the Company cannot currently estimate the effect of future legislation or regulations on its results of operations, financial condition or cash flows, the costs of compliance with such legislation or regulations could be material.

Under certain circumstances, banks participating in PGE’s credit facilities could decline to fund advances requested by the Company or could withdraw from participation in the credit facilities.

PGE currently has unsecured revolving credit facilities with several banks for an aggregate amount of $670 million. These credit facilities are available for general corporate purposes and may be used to 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 credit facilities represent commitments by the participating banks to make loans and, in certain cases, to issue letters of credit. The Company is required to make certain representations to the banks each time it requests an advance under one of the credit facilities. However, in the event of a material adverse change in the business, financial condition or results of operations of PGE, the Company may not be able to make such 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 a loan, 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, the accelerated repayment of any outstanding loan balances.

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

The Company is subject to state and federal requirements concerning emissions from thermal generation plants. For additional information, see “Environmental Matters” in Item 1-“Business.” These requirements could adversely affect the Company’s results of operations by requiring (i) the installation of additional emissions controls at the Company’s generating plants, which could result in increased capital expenditures and (ii) changes to PGE’s operations that could increase operating costs and reduce generating capacity.

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Adverse capital market performance could result in reductions in the fair value of benefit plan assets and increase the Company’s liabilities related to such plans. Sustained declines in 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. In 2011, discount rates used to value the pension plan declined substantially. This decline, combined with an increased actuarial loss related to prior year asset under performance, contributed to an increase in pension plan’s underfunded status from $77 million as of December 31, 2010 to $147 million as of December 31, 2011.

Performance of the capital markets also affects the fair 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. As changes in the fair 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.

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 in Item 8.— “Financial Statements and Supplementary Data.”

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. The cost and availability of natural gas and coal can also impact the cost and output of the Company’s thermal generating plants.

Operational changes 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 consists of generation from hydroelectric and wind projects. Operation of these projects is subject to regulation related to the protection of fish and wildlife. The listing of various species of salmon, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, laws relating to the protection of migratory birds and other wildlife could impact the development and operation of transmission lines and wind projects. Also, 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 or wind generation available to meet the Company’s energy requirements.

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PGE could be vulnerable to cyber security attacks, data security breaches or other similar events that could disrupt its operations, require significant expenditures or result in claims against the Company.

In the normal course of business, PGE collects, processes and retains sensitive and confidential customer and employee information, as well as proprietary business information, and operates systems that directly impact the availability of electric power and the transmission of electric power in its service territory. Despite the security measures in place, the Company’s systems, and those of third-party service providers, could be vulnerable to cyber security attacks, data security breaches or other similar events that could disrupt operations or result in the release of sensitive or confidential information. Such events could cause a shutdown of service or expose the Company to liability. In addition, the Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches. The Company maintains insurance coverage against some, but not all, potential losses resulting from these risks. However, insurance may not be adequate to protect the Company against liability in all cases. In addition, PGE is subject to the risk that insurers will dispute or be unable to perform their obligations to the Company.

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.

In PGE’s 2011 General Rate Case, the OPUC authorized the Company to collect $2 million annually from retail customers for such damages and to defer any amount not utilized in the current year. The deferred amount, along with the annual collection, would be available to offset potential storm damage costs in future years.

PGE utilizes insurance, when possible, to mitigate the cost of physical loss or damage to the Company’s property. As cost effective insurance coverage for transmission and distribution line property (poles & wires) is currently not available, however, the Company would likely seek recovery of large losses to such property through the ratemaking process.

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

PGE is subject to regulation by the FERC, the OPUC, and by certain federal, state and local authorities under environmental and other laws. Such regulation significantly influences the Company’s operating environment and can have an effect on many aspects of its business. Changes to regulations are ongoing, and the Company cannot predict with certainty the future course of such changes or the ultimate effect that they might have on its business. However, changes in 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

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ITEM 2.     PROPERTIES.

PGE’s principal property, plant, and equipment are located on land owned by the Company 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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Generating Facilities

The following are generating facilities owned by PGE as of December 31, 2011:

Facility	Location	Net Capacity (1)
Wholly-owned:
Hydro:
Faraday	Clackamas River	46	MW
North Fork	Clackamas River	58
Oak Grove	Clackamas River	44
River Mill	Clackamas River	25
T.W. Sullivan	Willamette River	18
Natural Gas/Oil:
Beaver	Clatskanie, Oregon	516
Port Westward	Clatskanie, Oregon	410
Coyote Springs	Boardman, Oregon	246
Wind:
Biglow Canyon	Sherman County, Oregon	450
Jointly-owned (2):
Coal:
Boardman (3)	Boardman, Oregon	374
Colstrip (4)	Colstrip, Montana	296
Hydro:
Pelton (5)	Deschutes River	73
Round Butte (5)	Deschutes River	225
Total net capacity		2,781	MW

(1) Represents net capacity of generating unit as demonstrated by actual operating or test experience, net of electricity used in the operation of a given facility. For wind-powered generating facilities, nameplate ratings are used in place of net capacity. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer.

(2) Reflects PGE’s ownership share.

(3) PGE operates Boardman and has a 65% ownership interest.

(4) PPL Montana, LLC operates Colstrip and PGE has a 20% ownership interest.

(5) PGE operates Pelton and Round Butte and has a 66.67% ownership interest.

PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the Federal Power Act. The licenses for the hydroelectric projects on the three different rivers expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055. The FERC approved a 40-year license term for the Company’s hydroelectric project on the Clackamas River in December 2010 and in March 2011, issued an Order on Rehearing that increased the license period to 45 years.

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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 Interconnection. As of December 31, 2011, PGE owned an electric transmission system consisting of approximately 730 circuit miles of 500-kV line and 360 circuit miles of 230-kV line. The Company also has approximately 24,000 circuit miles of primary and secondary distribution lines that deliver electricity to its customers.

The Company also has an ownership interest in the following transmission facilities:

• Approximately 14% of the Montana Intertie from the Colstrip plant in Montana to BPA’s transmission system; and

• Approximately 19% of the California-Oregon AC Intertie (COI), a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border.

In addition, the Company has contractual rights to the following transmission capacity:

• Approximately 3,100 MW of firm BPA transmission from remote resources and markets on BPA’s system to PGE’s service territory in Oregon;

• 200 MW of firm BPA transmission from mid-Columbia projects to the California-Oregon AC Intertie and 100 MW to the DC Intertie; and

• 100 MW of the Pacific DC Intertie between Celilo, Oregon and Sylmar, in southern California. These rights expire after June 30, 2012.

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.

ITEM 3.     LEGAL PROCEEDINGS.

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.

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, but in August 1993, the OPUC issued a Declaratory Ruling in PGE’s favor. The Citizens’ Utility Board (CUB) appealed the decision to the Oregon Court of Appeals.

In PGE’s 1995 general rate case, 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 Utility Reform Project (URP) filed an appeal of the 1995 Order to the Marion County Circuit Court. 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 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.

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. The court remanded the matter to the OPUC for reconsideration of its 1995 Order in light of the court’s decision.

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

In March 2002, 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. Following various appeals and proceedings, the Oregon Court of Appeals issued an opinion in October 2007 that reversed the Settlement Order and remanded the Settlement Order to the OPUC for reconsideration.

As a result of its reconsideration of the Settlement Order, the OPUC issued an order in September 2008 that required PGE to refund $33.1 million to customers. The Company completed the distribution of the refund to customers, plus accrued interest, as required.

In October 2008, the URP and the Class Action Plaintiffs (described in the Dreyer proceeding below) separately appealed the September 2008 OPUC order to the Oregon Court of Appeals. Oral arguments were made on February 3, 2012 and a decision by the Oregon Court of Appeals remains pending.

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.

In January 2003, two class action suits were filed in Marion County Circuit Court against PGE. 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 charged its customers.

In April 2004, the Class Action Plaintiffs filed a Motion for Partial Summary Judgment and in July 2004, PGE also moved for Summary Judgment in its favor on all of the Class Action Plaintiffs’ claims. In December 2004, the Judge granted the Class Action Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. In March 2005, PGE filed two Petitions with the Oregon Supreme Court asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints, or to show cause why they should not be dismissed, and seeking to overturn the Class Certification.

In August 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions 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.

In October 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.

In October 2007, the Class Action Plaintiffs filed a Motion with the Marion County Circuit Court to lift the abatement. In February 2009, the Circuit Court judge denied the Motion to lift the abatement.

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).

In July 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

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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).

In August 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, in April 2009, the Ninth Circuit issued an order that denied the requests for rehearing and issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC.

In October 2011, the FERC issued an Order on Remand establishing an evidentiary hearing to determine whether any seller had engaged in unlawful market activity in the Pacific Northwest spot markets during the December 25, 2000 through June 20, 2001 period by violating specific contracts or tariffs, and, if so, whether a direct connection existed between the alleged unlawful conduct and the rate charged under the applicable contract. FERC held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome before a refund could be ordered. FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Certain parties claiming refunds filed requests for rehearing of the Order on Remand, contesting, among other things, the applicable refund period reflected in the Order, the use of the Mobile-Sierra standard, any restraints in the Order on the type of evidence that could be introduced in the hearing, and the lack of market-wide remedy. The rehearing requests remain pending.

In its October 2011 Order on Remand, the FERC held the hearing procedures in abeyance pending the results of settlement discussions, which it ordered be convened before a FERC settlement judge. The settlement proceedings are ongoing.

In May 2007, the FERC approved a settlement between PGE and certain parties in the California refund case in Docket No. EL00-95, et seq. This resolved the claims 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 20, 2001. The settlement with the California parties did not resolve potential claims from other market participants relating to transactions in the Pacific Northwest.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

PGE’s common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol “POR”. As of February 17, 2012, there were 1,105holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $25.14per 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.

	High		Low		Dividends Declared Per Share
2011
Fourth Quarter	$	25.54	$	22.27	$	0.265
Third Quarter	26.00		21.29		0.265
Second Quarter	26.05		23.30		0.265
First Quarter	24.00		21.64		0.260
2010
Fourth Quarter	$	22.65	$	20.13	$	0.260
Third Quarter	20.63		18.08		0.260
Second Quarter	20.60		18.10		0.260
First Quarter	20.66		17.46		0.255

While PGE expects to pay comparable quarterly dividends on its common stock in the future, 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 deems 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.

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ITEM 6.     SELECTED FINANCIAL DATA.

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.”

	Years Ended December 31,
	2011			2010			2009			2008			2007
	(In millions, except per share amounts)
Statement of Income Data:
Revenues, net	$	1,813		$	1,783		$	1,804		$	1,745		$	1,743
Gross margin	58		%	54		%	48		%	50		%	50		%
Income from operations	$	309		$	267		$	208		$	217		$	269
Net income	147			121			89			87			145
Net income attributable to Portland General Electric Company	147			125			95			87			145
Earnings per share—basic and diluted	1.95			1.66			1.31			1.39			2.33
Dividends declared per common share	1.055			1.035			1.010			0.970			0.930
Statement of Cash Flows Data:
Capital expenditures	300			450			696			383			455
	As of December 31,
	2011			2010			2009			2008			2007
	(Dollars in millions)
Balance Sheet Data:
Total assets	$	5,733		$	5,491		$	5,172		$	4,889		$	4,108
Total long-term debt	1,735			1,808			1,744			1,306			1,313
Total Portland General Electric Company shareholders’ equity	1,663			1,592			1,542			1,354			1,316
Common equity ratio	48.6		%	46.7		%	46.9		%	47.3		%	50.0		%

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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 include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future operations, business prospects, expected changes in future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained in records and other data available from third parties, but there can be no assurance that PGE’s expectations, beliefs or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

• governmental policies and regulatory audits, investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;

• the effects of weak economies in the state of Oregon and the United States, including decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;

• the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;

• unseasonable or extreme weather and other natural phenomena, which can affect customer demand for power and could significantly affect PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;

• operational factors affecting PGE’s power generation facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, which may cause the Company to incur repair costs, as well as increased power costs for replacement power;

• volatility in wholesale power and natural gas prices, which could require the Company to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to existing power and natural gas purchase agreements;

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• capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper and the availability and cost of capital, as well as changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayments of maturing debt;

• future laws, regulations, and proceedings that could increase the Company’s costs or affect the operations of the Company’s thermal generating plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;

• changes in wholesale prices for natural gas, coal, oil, and other fuels and the impact of such changes on the Company’s power costs and the availability and price of wholesale power in the western United States;

• changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE’s service territory;

• the effectiveness of PGE’s risk management policies and procedures and the creditworthiness of customers and counterparties;

• the failure to complete capital projects on schedule and within budget;

• declines in the fair value of equity securities held by defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;

• changes in, and compliance with, environmental and endangered species laws and policies;

• the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

• new federal, state, and local laws that could have adverse effects on operating results;

• cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities, information technology systems, or result in the release of confidential customer and proprietary information;

• employee workforce factors, including aging, potential strikes, work stoppages, and transitions in senior management;

• general political, economic, and financial market conditions;

• natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;

• financial or regulatory accounting principles or policies imposed by governing bodies; and

• acts of war or terrorism.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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Overview

Operating Activities—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 United States and Canada. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The Company’s revenues and income from operations can fluctuate during the year due to the impacts of seasonal weather conditions on demand for electricity. Price changes and customer usage patterns (which can be affected by the economy) also have an effect on revenues while the availability and price of purchased power and fuel can affect income from operations. 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.

Customers and Demand—Continued customer growth and significantly higher demand from a certain paper production customer during 2011 has resulted in a 3.3% increase in retail energy deliveries over 2010. Energy efficiency and conservation efforts by retail customers continue to influence total deliveries, although the financial effects of such efforts are intended to be mitigated by the decoupling mechanism. On a weather adjusted basis, retail energy deliveries in 2011 increased 1.4% compared to 2010, with 1% attributable to the paper production sector.

The following table indicates the average number of retail customers, including those customers who purchase their energy from an ESS, and deliveries, by customer class, during the past two years:

	2011		2010		Increase/ (Decrease) in Energy Deliveries
	Average Number of Customers	Energy Deliveries *	Average Number of Customers	Energy Deliveries *
Residential	719,977	7,733	717,719	7,452	3.8	%
Commercial	102,940	7,419	102,282	7,277	2.0
Industrial	255	4,193	265	4,004	4.7
Total	823,172	19,345	820,266	18,733	3.3	%

 * In thousands of MWh.

PGE projects that weather adjusted retail energy deliveries for 2012 will increase approximately 0.9% from 2011 weather adjusted levels, after allowing for energy efficiency and conservation efforts. Excluding certain paper production customers, PGE projects that retail energy deliveries for 2012 will increase approximately 1% to 1.5% from 2011 weather adjusted levels. One of these paper customers ceased operation early in 2011 and a second can purchase its incremental energy requirements based on market conditions, which can cause significant load volatility.

Average seasonally adjusted unemployment rates are as follows:

	United States		Oregon		Portland/Salem
2011	9.0	%	9.6	%	9.6	%
2010	9.6		10.6		10.5

The majority of the Company’s service territory lies within the Portland/Salem metropolitan area. The state of Oregon, which continues to experience in-migration, forecasts that the average Oregon unemployment rate for 2012 is expected to be approximately 9.2%.

Power Operations—To meet the energy needs of its retail customers, the Company utilizes a combination of its

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own generating resources and wholesale market transactions. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, PGE makes economic dispatch decisions continuously in an effort to obtain reasonably-priced power for its retail customers. In addition, PGE’s thermal generating plants require varying levels of annual maintenance, during which the respective plant is unavailable to provide power. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

During the second quarters of 2011 and 2010, such annual maintenance was performed, with more extensive planned service maintenance completed in 2011 compared to 2010. Availability of the plants PGE operates approximated 93%, 95%, and 89% for the years ended December 31, 2011, 2010, and 2009, respectively, with the availability of Colstrip, which PGE does not operate, approximating 84%, 95%, and 68%, respectively. The decrease in Colstrip’s availability in 2011 was due to the plant’s planned maintenance, which included the installation of a new rotor for Unit 3.

During the year ended December 31, 2011, the Company’s generating plants provided approximately 48% of its retail load requirement, compared to 64% in 2010 and 57% in 2009. Although the level of service maintenance on the Company’s generating plants was greater in 2011 than in 2010, the decrease in the relative volume of power generated to meet the Company’s retail load requirement was primarily due to the economic displacement of a significant amount of thermal generation by increased energy received from hydro resources and lower cost purchased power during 2011.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increased 14% in 2011 compared to 2010. These resources provided approximately 25% of the Company’s retail load requirement for 2011, and 23% for 2010 and 25% for 2009. Energy received from these sources exceeded projections (or “normal”) included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 13% during 2011, compared to falling short of such projections by approximately 8% during 2010 and 2009. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year. ‘Normal’ represents the level of energy forecasted to be received from hydroelectric resources for the year and is based on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy from hydro resources is expected to be below normal for 2012.

Energy expected to be received from wind generating resources is projected annually in the AUT and is based on wind studies completed in connection with the permitting process of the wind farm. Any excess in wind generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy received from wind generating resources fell short of that projected in PGE’s AUT by 13% in 2011 and 27% in 2010.

Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in prices (baseline NVPC) and actual NVPC for the year, to the extent such difference is outside of a pre-determined “deadband.” The PCAM provides for 90% of actual NVPC above or below the deadband to be collected from or refunded to customers, respectively, subject to a regulated earnings test. Any estimated collection from or refund to customers pursuant to the PCAM is recorded in Revenues in the Company’s statements of income in the period of accrual. Starting in 2011, the deadband ranges from $15 million below to $30 million above baseline NVPC.

For the year ended December 31, 2011, actual NVPC was approximately $34 million below baseline NVPC, which is $19 million below the lower deadband threshold. For 2011, PGE recorded an estimated refund to customers of approximately $10 million pursuant to the PCAM, reduced from the $17 million potential refund as the result of the regulated earnings test. For 2010, actual NVPC was approximately $12 million below baseline NVPC, with no refund to customers recorded as actual NVPC was within the established deadband range of $17 million below to $35 million above baseline NVPC. For 2009, actual NVPC was approximately $22 million above baseline NVPC,

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with no collection from customers recorded as actual NVPC was within the established deadband range of $15 million below to $29 million above baseline NVPC.

Capital Requirements and Financing—PGE’s capital requirements in 2011 primarily related to ongoing capital expenditures for the upgrade, replacement, and expansion of transmission, distribution and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing. Included in such capital expenditures were the installation of the first of planned emissions controls at Boardman and the replacement of the cooling tower structure and upgrades to the gas turbine and exhaust system components at Coyote Springs during their annual maintenance outages. Capital expenditures were $300 million in 2011 and are expected to approximate $328 million in 2012.

Although there were no contractual maturities of long-term debt, PGE redeemed $73 million of long-term debt in 2011. Contractual maturities of long-term debt are $100 million in 2012.

During 2011, cash from operations of $453 million funded the Company’s capital requirements and redemptions of long-term debt. For 2012, PGE expects to fund estimated capital requirements and contractual maturities of long-term debt with cash from operations, which is expected to approximate $500 million. For further information, see the Liquidity and Debt and Equity Financings sections of this Item 7.

In accordance with PGE’s Integrated Resource Plan (IRP) and pursuant to the OPUC’s competitive bidding guidelines, the Company plans to issue two RFPs for additional resources during 2012, with one for capacity and energy resources and another for renewable resources. The RFP for capacity and energy resources is expected to seek approximately 300 MW to 500 MW of base load energy resources, 200 MW of year-round flexible and peaking resources, 200 MW of bi-seasonal peaking supply, and 150 MW of winter-only peaking supply. The flexible and peaking resources are expected to be available in the 2013 to 2015 timeframe, with the base load energy resources expected to be available in the 2015 to 2017 timeframe. The RFP for renewable resources would seek approximately 101 MWa of renewable resources, which would be expected to be available to meet PGE’s 2015 requirements under Oregon’s renewable energy standard.

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

Legal, Regulatory and Environmental Matters—PGE is a party to certain proceedings, the ultimate outcome of which could have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, matters related to:

• Recovery of the Company’s investment in its closed Trojan plant;

• Claims for refunds related to wholesale energy sales during 2000 - 2001 in the Pacific Northwest Refund proceeding; and

• An investigation of environmental matters at Portland Harbor.

For additional information regarding the above and other matters, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

The following discussion highlights certain regulatory items, which have impacted the Company’s revenues, results of operations, or cash flows for 2011, and some have affected customer prices, as authorized by the OPUC. In some cases, the Company deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

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Retail revenue adjustments, as approved by the OPUC, became effective during 2011, pursuant to the processes or mechanisms described below:

• General Rate Case—Effective January 1, 2011, the OPUC approved an increase in PGE’s annual revenues of $65 million, which represented an approximate 3.9% overall increase in customer prices, and included a reduction in power costs of $35 million under the AUT.

The OPUC also approved a tariff that provides a mechanism for future consideration of customer price changes related to the recovery of the Company’s remaining investment in the Boardman generating plant over a shortened operating life. The Company plans to cease coal-fired operation at Boardman at the end of 2020, consistent with revised rules adopted by the Oregon Environmental Quality Commission in December 2010 and approved by the EPA in June 2011.

Pursuant to the tariff, the OPUC approved recovery of increased depreciation expense reflecting a change in the retirement date of Boardman from 2040 to 2020 and an updated decommissioning cost estimate, with new prices effective July 1, 2011, which provided an incremental revenue requirement for the last six months of 2011 of $7 million. The tariff provides for annual updates to the revenue requirements with revised prices to take effect each January 1.

• Power Costs—Pursuant to the AUT process, PGE annually files an estimate of its forecasted power costs, with new prices to become effective January 1st of the following year. In the event a general rate case is filed in any given year, forecasted power costs would be included in such filing. Effective January 1, 2012, rate adjustments under the AUT are estimated to reduce annual retail revenues by $22 million due to a reduction in power costs.

• Renewable Resource Costs—Pursuant to a renewable adjustment clause (RAC) mechanism, PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The mechanism impacts results of operations only to the extent of providing a return on the Company’s investments. It will, however, result in an increase in cash flows during future years to provide for the recovery of the initial capital expenditures for the renewable resources. The Company may submit a filing to the OPUC by April 1st each year, with prices to become effective January 1st of the following year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.

The Company did not submit a RAC filing in 2011, as it did not anticipate an approved renewable resource addition would be placed into service during the year.

• Decoupling Mechanism—The decoupling mechanism provides for customer collection or refund if weather adjusted use per customer is less than or more than that approved in the Company’s most recent general rate case. In the Company’s 2011 General Rate Case, the OPUC extended the mechanism through 2013.

• In May 2010, the OPUC authorized the Company to refund to retail customers approximately $3 million related to the twelve month period ended January 31, 2010, as weather adjusted use per customer exceeded levels included in the 2009 General Rate Case. Revenues were adjusted during the corresponding period, while credits to customers began June 1, 2010 and continued over a one-year period.

• In 2010, the Company recorded an estimated collection of $8 million, as weather adjusted use per customer was less than levels included in the 2009 General Rate Case. Collection from customers is to occur over a one-year period, which began June 1, 2011.

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• During 2011, the Company recorded a $2 million refund to customers, which resulted primarily from slightly higher weather adjusted use per customer than that approved in the 2011 General Rate Case.

Pending review and approval by the OPUC, any resulting refunds to customers would be expected over a one-year period beginning June 1, 2012.

• Refund of tax credits—In January 2011, PGE began providing credits to customers over a one year period for pollution control tax credits the Company had accumulated related to the Independent Spent Fuel Storage Installation (ISFSI). During 2011, the Company provided $18 million in customer credits.

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.

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

	Years Ended December 31,
	2011				2010					2009
	Amount		As % of Rev		Amount			As % of Rev		Amount			As % of Rev
Revenues, net	$	1,813	100	%	$	1,783		100	%	$	1,804		100	%
Purchased power and fuel	760		42		829			46		944			52
Gross margin	1,053		58		954			54		860			48
Operating expenses:
Production and distribution	201		11		174			10		178			10
Administrative and other	218		12		186			11		179			10
Depreciation and amortization	227		13		238			13		211			12
Taxes other than income taxes	98		5		89			5		84			4
Total operating expenses	744		41		687			39		652			36
Income from operations	309		17		267			15		208			12
Other income:
Allowance for equity funds used during construction	5		—		13			1		18			1
Miscellaneous income, net	1		—		4			—		3			—
Other income, net	6		—		17			1		21			1
Interest expense	110		6		110			6		104			6
Income before income taxes	205		11		174			10		125			7
Income taxes	58		3		53			3		36			2
Net income	147		8		121			7		89			5
Less: net loss attributable to noncontrolling interests	—		—		(4		)	—		(6		)	—
Net income attributable to Portland General Electric Company	$	147	8	%	$	125		7	%	$	95		5	%

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Revenues, energy deliveries (based in MWh), and average number of retail customers consist of the following for the years presented:

	Years Ended December 31,
	2011					2010				2009
Revenues(1) (dollars in millions):
Retail:
Residential	$	877		48	%	$	803	45	%	$	856		47	%
Commercial	635			35		601		34		642			36
Industrial	226			13		221		12		166			9
Subtotal	1,738			96		1,625		91		1,664			92
Other accrued revenues, net	(16		)	(1	)	39		2		(7		)	—
Total retail revenues	1,722			95		1,664		93		1,657			92
Wholesale revenues	60			3		87		5		112			6
Other operating revenues	31			2		32		2		35			2
Total revenues	$	1,813		100	%	$	1,783	100	%	$	1,804		100	%
Energy deliveries(2) (MWh in thousands):
Retail:
Residential	7,733			36	%	7,452		35	%	7,901			36	%
Commercial	7,419			35		7,277		34		7,559			34
Industrial	4,193			19		4,004		19		3,876			17
Total retail energy deliveries	19,345			90		18,733		88		19,336			87
Wholesale energy deliveries	2,142			10		2,580		12		2,896			13
Total energy deliveries	21,487			100	%	21,313		100	%	22,232			100	%
Average number of retail customers:
Residential	719,977			87	%	717,719		88	%	714,377			88	%
Commercial	102,940			13		102,282		12		101,221			12
Industrial	255			—		265		—		271			—
Total	823,172			100	%	820,266		100	%	815,869			100	%

(1)	Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.
(2)	Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

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PGE’s sources of energy, including total system load and retail load requirement, for the years presented are as

follows:

	Years Ended December 31,
	2011				2010				2009
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	4,125		19	%	4,984		23	%	3,760		18	%
Natural gas	2,138		10		4,460		21		4,500		21
Total thermal	6,263		29		9,444		44		8,260		39
Hydro	1,933		9		1,830		9		1,800		8
Wind	1,216		6		833		4		499		2
Total generation	9,412		44		12,107		57		10,559		49
Purchased power:
Term	6,252		29		3,984		19		6,145		29
Hydro	2,897		13		2,417		11		2,801		13
Wind	269		1		297		1		292		1
Spot	2,763		13		2,618		12		1,641		8
Total purchased power	12,181		56		9,316		43		10,879		51
Total system load	21,593		100	%	21,423		100	%	21,438		100	%
Less: wholesale sales	(2,142	)			(2,580	)			(2,896	)
Retail load requirement	19,451				18,843				18,542

Net income attributable to Portland General Electric Company for the year ended December 31, 2011 was $147 million, or $1.95 per diluted share, compared to $125 million, or $1.66 per diluted share, for the year ended December 31, 2010. The $22 million, or 18%, increase in net income was primarily due to the combined effects of a 3% increase in total retail energy deliveries, a 4% increase in customer prices, and a 9% decrease in average variable power cost. Decreased average variable power cost was driven by the economic displacement of a significant amount of thermal generation with lower cost purchased power and increased energy received from lower cost hydro and wind resources. As a result of decreased NVPC, PGE recorded an estimated refund to customers of $10 million pursuant to the PCAM, as actual NVPC was below baseline NVPC in 2011, with no refund or collection from customers recorded in 2010. Offsetting these increases to net income were higher employee-related costs.

Net income attributable to Portland General Electric Company for the year ended December 31, 2010 was $125 million, or $1.66 per diluted share, compared to $95 million, or $1.31 per diluted share, for the year ended December 31, 2009. The $30 million, or 32%, increase in net income was primarily due to the following:

• Improved power supply operations, resulting from increases in plant availability along with lower natural gas prices relative to those included in the AUT. Additionally, during 2009 approximately $16 million of incremental replacement power costs were incurred to replace the output of both Colstrip and Boardman during extended maintenance and repair outages;

• A $17 million increase in Other accrued revenues related to the regulatory treatment of income taxes (SB 408), which is primarily the result of a $13 million refund to customers recorded in 2009 and a $4 million reduction to that amount recorded in 2010. For 2009, taxes authorized for collection in customer prices exceeded the amount paid by PGE, resulting in a future refund to customers. For the tax year 2010, no amount related to SB 408 was recorded; and

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• An $18 million decrease in Purchased power and fuel expense, related to the write-off in 2009 of previously deferred excess replacement power costs associated with Boardman’s forced outage from late 2005 to early 2006.

2011 Compared to 2010

Revenues increased $30 million, or 2%, in 2011 compared to 2010 as a result of the net effect of the items discussed below.

Total retail revenues increased $58 million, or 3%, due primarily to the following items:

• A $62 million increase related to the volume of retail energy sold. Residential volumes were up 4%, primarily driven by cooler temperatures in the heating seasons. In addition, commercial and industrial deliveries were up 3% due largely to increased demand from the paper sector;

• A $61 million increase related to changes in average retail price that resulted primarily from the 3.9% overall increase effective January 1, 2011 authorized by the OPUC in the Company’s 2011 General Rate Case and an increase effective July 1, 2011 related to the recovery of Boardman over a shortened operating life; partially offset by

• An $18 million decrease as a result of the ISFSI tax credits refund recorded in 2011 (offset in Depreciation and amortization), with no comparable refund in 2010;

• An $18 million decrease related to the deferral of revenue requirements for Biglow Canyon in 2010, which was included in Other accrued revenues. In 2011, the recovery of Biglow Canyon is included in the average retail price discussed above as a result of the 2011 General Rate Case;

• A $10 million decrease related to the decoupling mechanism, which is included in Other accrued revenues. In 2011, a $2 million refund to customers was recorded, which resulted primarily from slightly higher weather adjusted use per customer than that approved in the 2011 General Rate Case. Among other things, the 2011 General Rate Case reset the baseline used for the decoupling mechanism. An $8 million collection from customers was recorded in 2010, resulting from lower weather adjusted use per customer than that approved in the 2009 General Rate Case;

• A $10 million decrease related to an estimated refund to customers, pursuant to the PCAM, recorded in 2011 and included in Other accrued revenues, with no amount recorded in 2010. For further discussion of the PCAM, see Purchased power and fuel expense, below;

• A $7 million decrease related to the regulatory treatment of income taxes (SB 408) primarily due to an adjustment recorded in 2010 that pertained to the 2009 liability, which was included in Other accrued revenues. SB 408 was repealed in 2011 and no longer applies to tax years after 2009; and

• A $5 million decrease due to the 2010 reversal of a deferral for customer refunds pursuant to an OPUC order related to the 2005 Oregon Corporate Tax Kicker, which was included in Other accrued revenues.

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Heating degree-days in 2011 were 10% greater than the 15-year average and increased 11% compared to 2010, while cooling degree-days increased 15% from 2010. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport and illustrates that weather effects increased the demand for electricity in 2011 over 2010:

	Heating Degree-Days		Cooling    Degree-Days
	2011	2010	2011	2010
1st Quarter	1,974	1,629	—	—
2nd Quarter	946	861	16	18
3rd Quarter	51	117	346	296
4th Quarter	1,679	1,580	—	—
Full Year	4,650	4,187	362	314
15-year Full Year average	4,219	4,192	464	473

On a weather adjusted basis, retail energy deliveries in 2011 increased 1.4% compared to 2010, with 1% attributable to the paper production sector. Deliveries to residential, commercial, and industrial customers increased by 0.2%, 0.4%, and 5.3%, respectively.

PGE projects that weather adjusted retail energy deliveries for 2012 will increase approximately 0.9% from 2011 weather adjusted levels, after allowing for energy efficiency and conservation efforts. Excluding certain paper production customers, PGE projects that retail energy deliveries for 2012 will increase approximately 1% to 1.5% from 2011 weather adjusted levels. One of these paper customers ceased operation early in 2011 and a second can purchase its incremental energy requirements based on market conditions, which can cause significant load volatility.

Wholesale revenues result from sales of electricity to utilities and power marketers that are made in the Company’s efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.

Wholesale revenues in 2011 decreased $27 million, or 31%, from 2010 as a result of the following:

• A $13 million decrease related to a 17% decline in the average wholesale price the Company received, driven by lower electricity market prices due to abundant hydro in the region; and

• A $14 million decrease due to a 17% decline in wholesale energy sales volume.

Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. In 2011, Purchased power and fuel expense decreased $69 million, or 8%, from 2010, with $75 million related to a 9% decrease in average variable power cost, partially offset by $7 million related to a 1% increase in total system load. The average variable power cost was $35.15 per MWh in 2011 compared to $38.68 per MWh in 2010.

The decrease in Purchased power and fuel expense consisted of:

• A $71 million decrease in the cost of generation, primarily driven by a decrease in the proportion of power provided by Company-owned thermal generating resources. During 2011, a significant amount of thermal generation was economically displaced by lower cost purchased power and increased energy received from lower cost hydro and wind generating resources, relative to 2010. The average cost of power generated increased 1% in 2011 compared to 2010; and

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• A $2 million increase in the cost of purchased power, consisting of $151 million related to a 31% increase in purchases, substantially offset by $149 million related to a 23% decrease in average cost. The decrease in average cost was primarily driven by lower wholesale power prices resulting from favorable hydro conditions.

Energy from PGE-owned wind generating resources (Biglow Canyon) increased 46% from 2010, and represented 6% of the Company’s retail load requirement in 2011 compared to 4% in 2010. These increases were due to the completion of the third and final phase of Biglow Canyon in August 2010 and favorable wind conditions in 2011 relative to 2010. Energy received from wind generating resources fell short of projections included in the Company’s AUT by approximately 13% in 2011 and 27% in 2010.

Hydroelectric energy during 2011, from both PGE-owned hydroelectric projects and from mid-Columbia projects, exceeded that projected in the Company’s 2011 AUT and 2010 by 13% and 14%, respectively. Total hydroelectric energy fell short of projections included in the Company’s AUT by approximately 8% in 2010. Current forecasts indicate that regional hydro conditions in 2012 will be below normal levels.

The following table indicates the forecast of the April-to-September 2012 runoff (issued February 21, 2012) compared to the actual runoffs for 2011 and 2010 (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):

	Runoff as a Percent of Normal *
Location	2012 Forecast		2011 Actual		2010 Actual
Columbia River at The Dalles, Oregon	95	%	135	%	79	%
Mid-Columbia River at Grand Coulee, Washington	99		123		78
Clackamas River at Estacada, Oregon	92		135		124
Deschutes River at Moody, Oregon	98		120		104

* Volumetric water supply forecasts for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.

For 2011, actual NVPC was approximately $34 million below baseline NVPC, with PGE recording an estimated refund to customers of approximately $10 million pursuant to the PCAM, which was reduced from the potential refund of $17 million as a result of the regulated earnings test. Actual NVPC was approximately $12 million below baseline NVPC in 2010, but within the established deadband ranges; accordingly, no refund to customers was recorded pursuant to the PCAM.

Gross margin, which represents the difference between Revenues and Purchased power and fuel expense, is among those performance indicators utilized by management in the analysis of financial and operating results and is intended to supplement the understanding of PGE’s operating performance. It provides a measure of income available to support other operating activities and expenses of the Company and serves as a useful measure for understanding and analyzing changes in operating performance between reporting periods. It is considered a “non-GAAP financial measure,” as defined in accordance with SEC rules, and is not intended to replace operating income as determined in accordance with GAAP.

As a percent of Revenues, Gross margin was 58% in 2011 compared to 54% in 2010. The increase in Gross margin was driven by the 9% decrease in average variable power cost and increases of 3% in retail energy deliveries and 4% in retail customer prices resulting from the 2011 General Rate Case, which became effective January 1, 2011, and a tariff for the recovery of Boardman over a shortened operating life, which became effective July 1, 2011.

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Production and distribution expense increased $27 million, or 16%, in 2011 compared to 2010, primarily due to the following:

• A $10 million increase due to increased operating and maintenance expenses at the Company’s thermal generating plants (including extensive work performed during their planned annual outages) and at Biglow Canyon, the final phase of which was completed in August 2010;

• A $9 million increase to distribution system expenses primarily related to increased information technology costs and tree trimming activities; and

• An $8 million increase related to higher labor and employee benefit costs.

Administrative and other expense increased $32 million, or 17%, in 2011 compared to 2010, primarily due to the following:

• A $13 million increase primarily due to higher pension and employee benefit expenses, and increased incentive compensation related to an improvement in corporate financial and operating performance for 2011;

• A $5 million increase related to higher information technology costs;

• A $4 million increase in fees related to various legal and environmental proceedings;

• A $3 million increase in the provision and write-off of certain uncollectible customer accounts; and

• A $2 million increase related to higher OPUC regulatory fees resulting from higher prices in 2011 (fully offset in Retail revenues).

Depreciation and amortization expense decreased $11 million, or 5%, in 2011 compared to 2010, due largely to the net effect of the following:

• An $18 million decrease related to the amortization of customer refunds for the ISFSI tax credits (offset in Revenues);

• A $12 million decrease related to increases in estimated useful lives and reductions to estimated removal costs of certain long-lived assets due to an updated depreciation study;

• A $4 million decrease related to the impairment loss recognized in 2010 on photovoltaic solar power facilities, the majority of which was allocated to noncontrolling interest through the Net loss attributable to the noncontrolling interests. For additional information, see Note 16, Variable Interest Entities, in the Notes to Consolidated Financial Statements included in Item 8.—“Financial Statements and Supplementary Data.”; offset by

• A $21 million increase in depreciation related to the completion of Biglow Canyon Phase III in August 2010, Boardman shortened operating life, the Smart Meter project, and other capital additions in late 2010 and in 2011; and

• A $2 million increase in amortization related to hydroelectric licenses.

Taxes other than income taxes increased $9 million, or 10%, in 2011 compared to 2010, primarily due to higher property taxes, resulting from both increased property values and tax rates, and higher city franchise fees related to increased Retail revenues.

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Other income, net was $6 million in 2011 compared to $17 million in 2010. The decrease is primarily due to the following: 

• An $8 million decrease in the allowance for equity funds used during construction, as a result of lower construction work in progress balances during 2011, related primarily to the August 2010 completion of Biglow Canyon Phase III; and

• A $5 million decrease in income from non-qualified benefit plan trust assets, resulting from a minimal loss in the fair value of the plan assets in 2011 compared to a $5 million gain in 2010.

Interest expense in 2011 was comparable to 2010, as a $6 million decrease in the allowance for funds used during construction, related primarily to the August 2010 completion of Biglow Canyon Phase III, was offset by lower interest on long-term debt and certain regulatory liabilities.

Income taxes increased $5 million, or 9%, in 2011, compared to 2010, primarily due to higher income before taxes in 2011, partially offset by increased federal wind production tax credits (PTCs) in that year. The effective tax rates (28.3% and 30.3% for 2011 and 2010, respectively) differ from the federal statutory rate primarily due to benefits from PTCs and state tax credits. An increase in PTCs, related to increased production from the completed Biglow Canyon wind project, was partially offset by an increase in the state income tax rate and a reduction in state tax credits.

Net loss attributable to noncontrolling interests represents the noncontrolling interests’ portion of the net loss of PGE’s less-than-wholly-owned subsidiaries, the majority of which in 2010 consists of the impairment losses recognized on the photovoltaic solar power facilities, discussed previously in Depreciation and amortization.

2010 Compared to 2009

Revenues decreased $21 million, or 1%, in 2010 compared to 2009 as a result of the net effect of the items discussed below.

Total retail revenues increased $7 million, or 1%, due primarily to net effect of the following:

• A $25 million increase related to the volume of retail energy sold resulting from the net effect of:

◦ A shift in the mix of customers purchasing their energy requirements from PGE, with a certain large industrial customer choosing to purchase it energy requirements from PGE as opposed to purchasing its energy requirements from an ESS in 2009;

◦ A 3.3% increase in deliveries to industrial customers due in part to improvement in the high technology sector and an increase in production by one large industrial customer; and

◦ The addition of an average of 4,400 retail customers; partially offset by

◦ A 5.7% decrease in residential deliveries and a 3.7% decrease in commercial deliveries primarily due to milder weather conditions during 2010 and the continued effects of a weak economy; and

◦ The effects of energy efficiency programs on retail energy deliveries during 2010 relative to 2009;

• A $17 million increase related to SB 408, included in Other accrued revenues, resulting from an estimated $13 million customer refund recorded in 2009 along with a $4 million reversal of a portion of the 2009 refund recorded in 2010. As a result of the uncertainty around the application of the rules at the time, the Company recorded no collection from customers for 2010;

• A $15 million increase related to the decoupling mechanism, which is included in Other accrued revenues. In 2010, an estimated $8 million receivable from customers was recorded, resulting from lower weather adjusted use per customer than that approved in the 2009 General Rate Case, compared to a $7 million refund to customers recorded in 2009, resulting from higher weather adjusted use per customer than that approved in the 2009 General Rate Case;

• A $10 million increase resulting from a reduction in the transition adjustment credit provided to those commercial and industrial customers that purchase power from ESSs. Transition adjustment credits reflect

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the difference between the cost and market value of PGE’s power supply, as provided by Oregon’s electricity restructuring law;

• A $7 million increase related to the deferral of revenue requirements for Biglow Canyon, which is included in Other accrued revenues;

• A $5 million increase due to the reversal of a deferral for customer refunds related to the 2005 Oregon Corporate Tax Kicker, pursuant to an OPUC order issued in the third quarter of 2010, which is included in Other accrued revenues; and

• A $72 million decrease related to a 4% decline in average retail price that resulted primarily from a decrease in net variable power costs, partially offset by increases for the recovery of Biglow Canyon Phase II and Selective Water Withdrawal capital projects.

Heating degree-days in 2010 decreased 5% compared to 2009, while cooling degree-days, which were 34% less than the15-year average, decreased 50%. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-Days		Cooling   Degree-Days
	2010	2009	2010	2009
1st Quarter	1,629	2,022	—	—
2nd Quarter	861	578	18	90
3rd Quarter	117	63	296	537
4th Quarter	1,580	1,728	—	—
Full Year	4,187	4,391	314	627
15-year Full Year average	4,192	4,169	473	467

On a weather adjusted basis, retail energy deliveries decreased 1.4% in 2010 compared to 2009, with deliveries to residential and commercial customers decreasing by 2.5%, and 2.2%, respectively, and deliveries to industrial customers increasing by 2.3%.

Wholesale revenues in 2010 decreased $25 million, or 22%, from 2009 as a result of the following:

• A $13 million decrease related to a 12% decline in average wholesale prices obtained by the Company, driven by lower electricity market prices; and

• A $12 million decrease due to an 11% decline in wholesale energy sales volume.

In 2010, electricity demand from PGE’s retail customers was less than originally projected, with excess power, initially acquired to meet retail load, sold into a relatively low-priced wholesale market. A portion of the excess volume was used to offset lower than projected hydro and wind production, reducing the volume available for resale into the wholesale energy market.

Other operating revenues decreased $3 million, or 9%, primarily due to a reduction in fuel oil sales from the Company’s Beaver generating plant. Such sales were $5 million in 2010 and $8 million in 2009.

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Purchased power and fuel expense decreased $115 million, or 12%, for 2010 from 2009, primarily due to an 11% decrease in average variable power cost, which was largely driven by the shift in the mix of energy sources. The average variable power cost was $38.68 per MWh in 2010 and $43.22 per MWh in 2009. The average variable power cost for 2009 excludes the effect of the write-off of the regulatory asset discussed below.

The decrease in Purchased power and fuel consisted of:

• A $96 million decrease in the cost of purchased power, consisting of $84 million related to a 14% decrease in purchases and $12 million related to a 2% decrease in average cost. Increased purchases were required in 2009 to replace the output of Colstrip and Boardman during extended outages at these plants, resulting in incremental replacement power costs of approximately $16 million;

• An $18 million decrease related to the write-off in 2009 of a portion of a regulatory asset representing deferred excess replacement power costs associated with Boardman’s forced outage from late 2005 to early 2006; and

• A $2 million decrease in the cost of generation, consisting of $52 million related to a 13% decrease in average cost, substantially offset by $50 million related to a 15% increase in generation, resulting primarily from a 33% increase in generation at Colstrip and Boardman. In 2009, both Colstrip and Boardman had extended repair and maintenance outages. The decrease in average cost was primarily due to a 6% decrease in the average cost of natural gas-fired generation, which was driven by decreases in natural gas prices.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia projects in 2010 were up 2% and down 14%, respectively, from 2009. Additionally, energy received from hydroelectric resources also fell short of projections included in the Company’s AUT by approximately 8% in 2010 and 2009.

Gross margin was 54% in 2010 compared to 48% in 2009, an increase of 13%. Contributing to the increase was the impact of improved thermal operations, which more than offset the effect of lower retail energy sales during the year. Also contributing to the increase was the impact of SB 408 and the write-off of deferred power costs related to Boardman’s outage, which had negative impacts on Gross margin in 2009.

Production and distribution expense decreased $4 million, or 2%, in 2010 compared to 2009, due to the net effect of the following:

• A $6 million decrease related to certain capital costs expensed in 2009 for the Selective Water Withdrawal project, pursuant to a stipulation with the OPUC;

• A $5 million decrease in repair and restoration expenses, related primarily to 2009 wind storms;

• A $5 million decrease in operating and maintenance expenses at the Company’s thermal generating plants;

• A $2 million decrease related to a reserve established in 2009 for the cost of certain environmental remediation activities; and offset by

• A $7 million increase related to the deferral of certain plant maintenance costs at Boardman, Beaver, and Colstrip in 2009. As authorized by the OPUC in PGE’s 2009 General Rate Case, certain maintenance costs that exceed those covered in current prices are deferred and amortized over ten years, beginning in 2009; and

• A $7 million increase in operating and maintenance expenses related to the Company’s distribution system and Biglow Canyon.

Administrative and other expense increased $7 million, or 4%, in 2010 compared to 2009, due to the following:

• A $5 million increase in incentive compensation, related to improved corporate financial and operating performance in 2010; 

• A $5 million increase in legal expenses and reserves for asserted claims;

• A $5 million increase in employee benefit expenses, related primarily to higher pension and health care costs; and offset by

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• A $3 million decrease in the provision for uncollectible accounts, due to an improvement in the status of customer accounts;

• A $3 million decrease in insurance costs and in customer support expenses, including reductions related to implementation of the smart meter project; and

• A $2 million decrease related to OPUC revenue fees (fully offset in Retail revenues).

Depreciation and amortization expense increased $27 million, or 13%, in 2010 compared to 2009, due largely to the net effect of the following:

• A $23 million increase in depreciation related to Biglow Canyon Phases II and III, the smart meter project, the Selective Water Withdrawal project, and other capital additions in late 2009 and 2010;

• A $4 million increase related to a 2009 reduction in the deferral of certain Oregon tax credits for future ratemaking treatment, as the Company was unable to utilize such credits (offset in Income taxes);

• A $2 million increase related to the amortization of certain regulatory assets and liabilities; and offset by

• A $1 million decrease related to lower impairment losses recognized in 2010 compared to 2009 on photovoltaic solar power facilities, the majority of which was allocated to noncontrolling interests through the Net loss attributable to the noncontrolling interests. For additional information, see Note 16, Variable Interest Entities, in the Notes to Consolidated Financial Statements included in Item 8.—“Financial Statements and Supplementary Data.”

Taxes other than income taxes increased $5 million, or 6%, in 2010 compared to 2009, due primarily to higher property and payroll taxes, as well as higher city franchise fees.

Other income, net was $17 million in 2010 compared to $21 million in 2009. The decrease was due primarily to the net effect of the following:

• A $5 million decrease in the allowance for equity funds used during construction, as a result of lower construction work in progress balances during 2010, related primarily to the completion of Biglow Canyon Phases II and III;

• A $4 million decrease in income from non-qualified benefit plan trust assets, resulting from a $5 million increase in the fair value of the plan assets during 2010 compared to a $9 million increase in 2009; and offset by

• A $4 million increase resulting from reductions in corporate donations, sponsorships, and certain non-utility activities, partially offset by lower interest income on regulatory assets.

Interest expense increased $6 million, or 6%, in 2010 compared to 2009, primarily due to the net effect of the following:

• An $8 million increase resulting from a higher average long-term debt balance during 2010 compared to 2009, related primarily to issuances of first mortgage bonds in late 2009 and 2010 to fund the construction of new generating facilities. In 2010, the average balance of long-term debt outstanding was $1,776 million compared to $1,525 million in 2009;

• A $3 million increase resulting from a decrease in the allowance for funds used during construction, related primarily to the completion of the construction of Biglow Canyon Phases II and III; and offset by

• A $5 million decrease in interest on regulatory liabilities, consisting primarily of customer refunds related to the Trojan regulatory proceeding and the Company’s PCAM.

Income taxes increased $17 million, or 47%, in 2010 compared to 2009, primarily due to higher income before taxes in 2010. The effective tax rates (30.3% in 2010 and 28.8% in 2009) differ from the federal statutory rate primarily due to benefits from federal wind production tax credits (PTCs) and state tax credits. An increase in PTCs, related to increased production from the completed Biglow Canyon wind farm, was largely offset by an increase in the state income tax rate and a reduction in state tax credits.

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Net loss attributable to noncontrolling interests of $4 million in 2010 and $6 million in 2009 represents the noncontrolling interests’ portion of the net loss of PGE’s less-than-wholly-owned subsidiaries, the majority of which consists of the impairment losses recognized on the photovoltaic solar power facilities, discussed previously in Depreciation and amortization.

Liquidity and Capital Resources

Discussions, forward-looking statements and projections in this section, and similar statements in other parts of the Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “Current capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan as currently scheduled.” in Item 1A.—“Risk Factors.”

Capital Requirements

The following table indicates actual capital expenditures for 2011 and future debt maturities and projected cash requirements for 2012 through 2016 for projects that the Board of Directors has approved (in millions, excluding AFDC):

	Years Ending December 31,
	2011			2012		2013		2014		2015		2016
Ongoing capital expenditures	$	259		$	266	$	249	$	231	$	251	$	330
Hydro licensing and construction	16			24		12		29		31		15
Boardman emissions controls (1)	17			11		12		—		—		—
Cascade Crossing	13			27		4		—		—		—
Total capital expenditures	$	305	(2)	$	328	$	277	$	260	$	282	$	345
Long-term debt maturities	$	73		$	100	$	100	$	—	$	70	$	67

(1) Represents 80% of estimated total costs based on installation of controls to meet regulatory requirements. In 1985, PGE sold an undivided 15% interest in Boardman to a third party, reducing the Company’s ownership interest from 80% to 65%. The purchaser has certain rights to participate in the financing of the portion of the total capital cost attributable to its interest. If the purchaser does not exercise its rights to finance the portion of the total cost attributable to its interest, PGE’s share of the total cost for the emissions controls at Boardman is expected to be 80%. PGE would seek to recover the incremental investment in future customer prices, although there can be no guarantee such recovery would be granted.

(2) Amounts shown include removal costs, which are included in other net operating activities in the consolidated statements of cash flows.

The following provides information regarding the items presented in the table above.

Ongoing capital expenditures—Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections. Preliminary engineering costs, which consist of expenditures for preliminary surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects, including certain projects discussed in the Integrated Resource Plansection below, are included in Ongoing capital expenditures and amounted to $3 million in 2011. The Company expects that it will spend approximately $2 million on Preliminary engineering in 2012.

Hydro licensing and construction—PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the Federal Power Act. The licenses for the hydroelectric projects expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055. Capital spending requirements reflected in the table above relate primarily to modifications to the Company’s various hydro facilities to enhance fish passage and survival, as required by conditions contained in the operating licenses.

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Boardman emissions controls—In June 2011, the EPA approved revised rules that established new emissions limits at Boardman and provide for coal-fired operation at Boardman to cease no later than December 31, 2020.

The emissions limits imposed under the revised rules have required the addition of certain controls. The Company’s portion of capital spending on the Boardman emissions controls to date is approximately $22 million. The amount of anticipated future expenditures is reflected in the table above.

Integrated resource plan—The Company’s IRP, acknowledged by the OPUC in November 2010, included the following resource, capacity, and transmission projects:

• The addition of new generating resources and improvements to existing plants. The related RFP processes will determine the successful bidders for the new capacity, energy, and renewable resources described in the IRP and clarify the timing and total cost; and

• The construction of Cascade Crossing at an estimated total cost (in 2011 dollars) of $800 million to $1.0 billion. The Company continues to work with other stakeholders in planning the project and potential project partnerships.

Due to the uncertainty of these projects, the Capital Requirements table above does not include estimates for any amounts related to these projects beyond 2012. Certain costs related to investigating the potential construction of these facilities are currently included in Ongoing capital expenditures in the table above. For further information on the Company’s IRP and the projects subject to the RFP process, see Capital Requirements and Financing in the Overview section of this Item 2, as well as the Future Energy Resource Strategy section of Power Supply and Transmission and Distribution contained in Item 1.—Business.

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, as well as debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

The following summarizes PGE’s cash flows for the periods presented (in millions):

	Years Ended December 31,
	2011			2010			2009
Cash and cash equivalents, beginning of year	$	4		$	31		$	10
Net cash provided by (used in):
Operating activities	453			391			386
Investing activities	(299		)	(430		)	(700		)
Financing activities	(152		)	12			335
Net change in cash and cash equivalents	2			(27		)	21
Cash and cash equivalents, end of year	$	6		$	4		$	31

2011 Compared to 2010

Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, included in net income during a given period.

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The $62 million increase in cash provided by operating activities in 2011 compared to 2010 was largely due to an increase in net income after the consideration of non-cash items, as well as a decrease in margin deposit requirements pursuant to certain power and natural gas purchase and sale agreements. Such increases were partially offset by a $44 million decrease in the income tax refunds received in 2011 compared to 2010 and a $16 million contribution to the voluntary employees’ beneficiary association trusts (VEBAs) in 2011. The VEBAs fund the benefits of the Company’s non-contributory postretirement health and life insurance plans.

A significant portion of cash provided by operations consists of recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges will approximate $250 million in 2012. Combined with all other sources, cash provided by operations is estimated to be approximately $500 million in 2012. This estimate includes the return of $30 million of margin deposits held by brokers as of December 31, 2011, and is based on both the timing of contract settlements and projected energy prices. The remaining $220 million in estimated cash flows from operations in 2012 is expected from normal operating activities.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. Capital expenditures decreased $150 million in 2011 compared to 2010 due to decreased construction costs related to the completion of Biglow Canyon Phase III in August 2010, as well as a $19 million distribution from the Nuclear decommissioning trust to PGE in 2010.

The Company plans approximately $328 million of capital expenditures in 2012 related to hydro licensing and construction, Boardman emissions controls and ongoing capital expenditures related to upgrades to and replacement of transmission, distribution and generation infrastructure. PGE plans to fund the 2012 capital expenditures with the cash expected to be generated from operations during 2012, as discussed above. For additional information, see the Capital Requirements section of this Item 7.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2011, net cash used in financing activities primarily consisted of the payment of dividends of $79 million and the repayment of long-term debt of $80 million, including the premium paid, partially offset by net issuances of commercial paper of $11 million. During 2010, net cash provided by financing activities primarily consisted of proceeds received from the issuance or remarketing of long-term debt of $249 million, net issuances of commercial paper of $19 million and noncontrolling interests’ capital contributions of $10 million, partially offset by the repayment of long-term debt of $186 million and the payment of dividends of $78 million.

2010 Compared to 2009

Cash Flows from Operating Activities—The $5 million increase in cash provided by operating activities in 2010 compared to 2009 was primarily due to an increase in net income after the consideration of noncash items, the receipt of an income tax refund in 2010 that was accrued in 2009, and customer refunds in 2009 related to the Trojan regulatory proceeding. These increases were offset by an increase in margin deposit requirements pursuant to power and natural gas purchase agreements, driven by decreases in the forward market prices of power and natural gas, and a $30 million contribution to the pension plan in 2010.

Cash Flows from Investing Activities—Capital expenditures decreased $246 million in 2010 from 2009 primarily due to decreased construction costs related to Biglow Canyon and the smart meter project, as well as a decrease in construction costs related to the Selective Water Withdrawal project, which was completed in January 2010. Additionally, during 2010, a $19 million distribution was made from the Nuclear decommissioning trust to PGE.

Cash Flows from Financing Activities—During 2010, net cash provided by financing activities primarily consisted of proceeds received from the issuance or remarketing of long-term debt of $249 million and net issuances of commercial paper of $19 million, partially offset by the repayment of long-term debt of $186 million and the payment of dividends of $78 million. During 2009, net cash provided by financing activities consisted of issuances

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of long-term debt of $580 million and common stock of $170 million, partially offset by the repayment of long-term debt of $142 million, net repayment of amounts due under revolving lines of credit of $131 million, the payment of dividends of $72 million and net maturities of commercial paper of $65 million.

Dividends on Common Stock

The following table indicates common stock dividends declared in 2011:

Declaration Date	Record Date	Payment Date	Declared Per Common Share
February 16, 2011	March 25, 2011	April 15, 2011	$	0.260
May 11, 2011	June 24, 2011	July 15, 2011	0.265
August 3, 2011	September 26, 2011	October 17, 2011	0.265
October 26, 2011	December 27, 2011	January 17, 2012	0.265

While the Company expects to pay comparable quarterly dividends on its common stock in the future, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems 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.

On February 22, 2012, the Board of Directors declared a dividend of $0.265 per share of common stock to stockholders of record on March 26, 2012, payable on or before April 16, 2012.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s and S&P, with current credit ratings and outlook as follows:

	Moody’s	S&P
First Mortgage Bonds	A3	A-
Senior unsecured debt	Baa2	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale, commodity and related transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE’s consolidated balance sheet, while any letters of credit issued are not reflected in the Company’s consolidated balance sheet.

As of December 31, 2011, PGE had posted approximately $184 million of collateral with these counterparties, consisting of $80 million in cash and $104 million in letters of credit, $26 million of which is related to master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2011, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $142 million and decreases to approximately $49 million by December 31, 2012. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $337 million and decreases to approximately $128 million by December 31, 2012.

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PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing under the credit facilities would increase.

The issuance of First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2011, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $579 million of additional First Mortgage Bonds. Any issuances of First Mortgage Bonds would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65% of total capitalization (debt ratio). As of December 31, 2011, the Company’s debt ratio, as calculated under the credit agreements, was 51.5%.

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, alternatives available to investors, and other factors. The Company’s ability to obtain and renew such financing depends on its credit ratings, as well as on credit markets, both generally and for electric utilities in particular. Management believes that the availability of credit facilities, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. PGE currently does not expect to issue debt or equity securities in 2012.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $700 million through February 6, 2014 and currently has the following unsecured revolving credit facilities:

• A $370 million syndicated credit facility, with $10 million and $360 million scheduled to terminate in July 2012 and July 2013, respectively; and

• A $300 million syndicated credit facility, which is scheduled to terminate in December 2016.

These credit facilities supplement operating cash flows and provide a primary source of liquidity. Pursuant to the terms of the agreements, the credit facilities may be used for general corporate purposes, as a backup for commercial paper borrowings, and the issuance of standby letters of credit. As of December 31, 2011, PGE had no borrowings outstanding under the credit facilities, with $30 million of commercial paper outstanding and $124 million of letters of credit issued. As of December 31, 2011, the aggregate unused available credit under the credit facilities was $516 million.

Long-term Debt. In 2011, PGE redeemed $10 million of Pollution Control Revenue Bonds in January and $63 million of 6.5% Series First Mortgage Bonds in December, both of which were scheduled to mature in 2014, with no issuances of long-term debt. As of December 31, 2011, total long-term debt outstanding was $1,735 million.

PGE owns $21 million of its Pollution Control Revenue Bonds, which may be remarketed at a later date, at the Company’s option, through 2033.

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Capital Structure. PGE’s financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company’s financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 48.6% and 46.7% as of December 31, 2011 and 2010, respectively.

Contractual Obligations and Commercial Commitments

The following indicates PGE’s contractual obligations as of December 31, 2011 (in millions):

	2012		2013		2014		2015		2016		There- after		Total
Long-term debt	$	100	$	100	$	—	$	70	$	67	$	1,398	$	1,735
Interest on long-term debt (1)	99		92		89		87		83		1,106		1,556
Capital and other purchase commitments	58		18		10		10		6		73		175
Purchased power and fuel:
Electricity purchases	129		77		76		76		57		381		796
Capacity contracts	21		21		21		20		19		—		102
Public Utility Districts	7		8		8		8		7		30		68
Natural gas	49		22		22		20		12		11		136
Coal and transportation	25		19		9		—		—		—		53
Pension plan contributions (2)	—		25		35		34		32		11		137
Operating leases	9		10		9		10		10		196		244
Total	$	497	$	392	$	279	$	335	$	293	$	3,206	$	5,002

(1) Future interest on long-term debt is calculated based on the assumption that all debt remains outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect as of December 31, 2011.

(2) Contributions to the Company’s pension plan are estimated based on numerous plan assumptions, including plan funded status. A return on plan assets of 8.25% and a discount rate of 5.0% was used for all periods presented.

Other Financial Obligations

PGE has entered into long-term power purchase contracts with certain public utility districts in the state of Washington under which it has acquired a percentage of the output (Allocation) of three hydroelectric projects (the Priest Rapids, Wanapum and Wells hydroelectric projects). The Company is required to pay its proportionate share of the operating and debt service costs of the projects whether or not they are operable. The contracts further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of both the output and the operating and debt service costs of the defaulting purchaser. For the Wells project, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage Allocation. For the Priest Rapids and Wanapum projects, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.

Off-Balance Sheet Arrangements

PGE has no off-balance sheet arrangements other than outstanding letters of credit from time to time that have, or are reasonably likely to have, a material current or future effect on its consolidated financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Critical Accounting Policies

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain.

Regulatory Accounting

As a rate-regulated enterprise, PGE is required to comply with certain regulatory accounting requirements, which include the recognition of regulatory assets and liabilities on the Company’s consolidated balance sheets. Regulatory assets represent probable future revenue associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited or refunded to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Amortization of regulatory assets and liabilities is reflected in the statement of income over the period in which they are included in customer prices.

If future recovery of regulatory assets ceases to be probable, PGE would be required to write them off. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting. Discontinued application of regulatory accounting would have a material impact on the Company’s results of operations and financial position.

Asset Retirement Obligations

PGE recognizes asset retirement obligations (AROs) for legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Changes that may arise over time with regard to these assumptions and determinations can change future amounts recorded for AROs.

Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. Accretion of the ARO liability is classified as an operating expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets.

Revenue Recognition

Retail customers are billed monthly for electricity use based on meter readings taken throughout the month. At the end of each month, PGE estimates the revenue earned from the last meter read date through the last day of the month, which has not yet been billed to customers. Such amount, which is classified as Unbilled revenues in the

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Company’s consolidated balance sheets, is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current customer prices.

Contingencies

PGE has various unresolved legal and regulatory matters about which there is inherent uncertainty, with the ultimate outcome contingent upon several factors. Such contingencies are evaluated using the best information available. A material loss contingency is accrued and disclosed when it is probable that an asset has been impaired or a liability incurred and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency is disclosed to the effect that it cannot be reasonably estimated. Material loss contingencies are disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. Established accruals reflect management’s assessment of inherent risks, credit worthiness, and complexities involved in the process. There can be no assurance as to the ultimate outcome of any particular contingency.

Price Risk Management

PGE engages in price risk management activities to manage exposure to commodity and foreign currency market fluctuations and to manage volatility in net power costs for its retail customers. The Company utilizes derivative instruments, which may include forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency. These derivative instruments are recorded at fair value, or “marked-to-market,” in PGE’s consolidated financial statements.

Fair value adjustments consist of reevaluating the fair value of derivative contracts at the end of each reporting period for the remaining term of the contract and recording any change in fair value in either Net income or Other comprehensive income for the period. Fair value is the present value of the difference between the contracted price and the forward market price multiplied by the total quantity of the contract. For option contracts, a theoretical value is calculated using Black-Scholes models that utilize price volatility, price correlation, time to expiration, interest rate and forward commodity price curves. The fair value of these options is the difference between the premium paid or received and the theoretical value at the fair value measurement date.

Determining the fair value of these financial instruments requires the use of prices at which a buyer or seller could currently contract to purchase or sell a commodity at a future date (termed “forward prices”). Forward price “curves” are used to determine the current fair market value of a commodity to be delivered in the future. PGE’s forward price curves are created by utilizing actively quoted market indicators received from electronic and telephone brokers, industry publications, and other sources. Forward price curves can change with market conditions and can be materially affected by unpredictable factors such as weather and the economy. PGE’s forward price curves are validated using broker quotes and market data from a regulated exchange and differences for any single location, delivery date and commodity are less than 5%.

Pension Plan

Primary assumptions used in the actuarial valuation of the plan include the discount rate, the expected return on plan assets, mortality rates, and wage escalation. These assumptions are evaluated by PGE, reviewed annually with the plan actuaries and trust investment consultants, and updated in light of market changes, trends, and future expectations. Significant differences between assumptions and actual experience can have a material impact on the valuation of the pension benefit plan obligation and net periodic pension cost.

PGE’s pension discount rate is determined based on a portfolio of high-quality bonds that match the duration of the plan cash flows. The expected rate of return on plan assets is based on projected long-term return on assets in the plan investment portfolio.

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Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets or reduction in the discount rate would, individually, have the effect of increasing the 2011 net periodic pension expense by approximately $1 million.

Fair Value Measurements

In accordance with accounting and reporting requirements, PGE applies fair value measurements to its financial assets and liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company’s financial assets and liabilities consist of derivative instruments, certain assets held by the Nuclear decommissioning, Pension plan and Non-qualified benefit plan trusts, and long-term debt. In valuing these items, the Company uses inputs and assumptions that market participants would use to determine their fair value, utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value can require subjective and complex judgment and the Company’s assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within the fair value hierarchy reported in its financial statements.

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations or cash flows, as discussed below.

Risk Management Committee

PGE has a Risk Management Committee (RMC) which is responsible for providing oversight of the adequacy and effectiveness of corporate policies, guidelines, and procedures for market and credit risk management related to the Company’s energy portfolio management activities. The RMC consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The RMC reviews and approves adoption of policies and procedures, and monitors compliance with policies, procedures, and limits on a regular basis through reports and meetings. The RMC also reviews and recommends risk limits that are subject to approval by PGE’s Board of Directors.

Commodity Price Risk

PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company engages in price risk management activities to manage exposure to volatility in net power costs for its retail customers. The Company uses power purchase contracts to supplement its thermal, hydroelectric, and wind generation and to respond to fluctuations in the demand for electricity and variability in generating plant operations. The Company also enters into contracts for the purchase of fuel for the Company’s natural gas- and coal-fired generating plants. These contracts for the purchase of power and fuel expose the Company to market risk. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity; swap agreements, which may require payments to, or receipt of payments from, counterparties based on the differential between a fixed and variable price for the commodity; and option contracts to mitigate risk that arises from market fluctuations of commodity prices. PGE does not engage in trading activities for non-retail purposes.

For purposes of disclosure, the Company has historically used value at risk measures. However, PGE believes that tabular presentation of expected cash flows related to these market-risk sensitive instruments provides more meaningful information.

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The following table presents energy commodity derivative fair values as a net liability as of December 31, 2011 that are expected to settle in each respective year (in millions):

	2012		2013		2014		2015		Total
Commodity contracts:
Electricity	$	64	$	42	$	21	$	8	$	135
Natural gas	132		72		24		6		234
	$	196	$	114	$	45	$	14	$	369

The following table presents energy commodity derivative fair values as a net liability as of December 31, 2010 that were expected to settle in each respective year (in millions):

	2011		2012		2013		2014		Total
Commodity contracts:
Electricity	$	73	$	25	$	11	$	5	$	114
Natural gas	102		92		43		9		246
	$	175	$	117	$	54	$	14	$	360

PGE reports energy commodity derivative fair values as a net asset or liability, which combines purchases and sales expected to settle in the years noted above. As a short utility, energy commodity fair values exposed to commodity price risk are primarily related to purchase contracts, which are slightly offset by sales.

PGE’s energy portfolio activities are subject to regulation, with related costs included in retail prices approved by the OPUC. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and regulatory liabilities to reflect the effects of regulation, significantly mitigating commodity price risk for the Company. As contracts are settled, these deferrals reverse and are recognized as Purchased power and fuel in the statements of income and included in the PCAM. PGE remains subject to cash flow risk in the form of collateral requirements based on the value of open positions and regulatory risk if recovery is disallowed by the OPUC. PGE attempts to mitigate both types of risks through prudent energy procurement practices.

Foreign Currency Exchange Rate Risk

PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars in its energy portfolio. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy.

As of December 31, 2011, a 10% change in the value of the Canadian dollar would result in an immaterial change in income before income taxes for transactions that will settle over the next 12 months.

Interest Rate Risk

To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days; such issuances are supported by the Company’s unsecured revolving credit facilities. Although any borrowings under the commercial paper program subject the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carry a fixed rate during their respective terms. As of December 31, 2011, PGE had no borrowings outstanding under its revolving credit facilities and $30 million of commercial paper outstanding.

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PGE currently has no financial instruments to mitigate risk related to changes in short-term interest rates, including those on commercial paper; however, it may consider such instruments in the future as considered necessary.

As of December 31, 2011, the total fair value and carrying amounts by maturity date of PGE’s long-term debt are as follows (in millions):

	Total Fair Value		Carrying Amounts by Maturity Date
			Total		2012		2013		2014		2015		2016		There- after
First Mortgage Bonds	$	1,962	$	1,614	$	100	$	100	$	—	$	70	$	67	$	1,277
Pollution Control Revenue Bonds	129		121		—		—		—		—		—		121
Total	$	2,091	$	1,735	$	100	$	100	$	—	$	70	$	67	$	1,398

As of December 31, 2011, PGE had no long-term variable rate debt outstanding; accordingly, the Company’s outstanding long-term debt is not subject to interest rate risk exposures.

Credit Risk

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. The Company also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded to reflect credit risk related to wholesale accounts receivable.

The large number and diversified base of residential, commercial, and industrial customers, combined with the Company’s ability to discontinue service, contribute to reduce credit risk with respect to trade accounts receivable from retail sales. Estimated provisions for uncollectible accounts receivable related to retail sales are provided for such risk.

As of December 31, 2011, PGE’s credit risk exposure is $1 million for commodity activities with externally-rated investment grade counterparties and matures in 2012. The credit risk is included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

Investment grade includes those counterparties with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody’s) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance.

Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. These contracts provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2052. For additional information, see “Public Utility Districts” in Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Management believes that circumstances that could result in the nonperformance by these counterparties are remote.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The following financial statements and report are included in Item 8:

Report of Independent Registered Public Accounting Firm	67
Consolidated Statements of Income for the years ended December 31, 2011, 2010, and 2009	69
Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010, and 2009	70
Consolidated Balance Sheets as of December 31, 2011 and 2010	71
Consolidated Statements of Equity for the years ended December 31, 2011, 2010, and 2009	73
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009	74
Notes to Consolidated Financial Statements	76

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Portland General Electric Company

Portland, Oregon

We have audited the accompanying consolidated balance sheets of Portland General Electric Company and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011. We also have audited the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 23, 2012

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

	Years Ended December 31,
	2011		2010			2009
Revenues, net	$	1,813	$	1,783		$	1,804
Operating expenses:
Purchased power and fuel	760		829			944
Production and distribution	201		174			178
Administrative and other	218		186			179
Depreciation and amortization	227		238			211
Taxes other than income taxes	98		89			84
Total operating expenses	1,504		1,516			1,596
Income from operations	309		267			208
Other income:
Allowance for equity funds used during construction	5		13			18
Miscellaneous income, net	1		4			3
Other income, net	6		17			21
Interest expense	110		110			104
Income before income taxes	205		174			125
Income taxes	58		53			36
Net income	147		121			89
Less: net loss attributable to noncontrolling interests	—		(4		)	(6		)
Net income attributable to Portland General Electric Company	$	147	$	125		$	95
Weighted-average shares outstanding (in thousands):
Basic	75,333		75,275			72,790
Diluted	75,350		75,291			72,852
Earnings per share—basic and diluted	$	1.95	$	1.66		$	1.31
Dividends declared per common share	$	1.055	$	1.035		$	1.010

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Years Ended December 31,
	2011			2010			2009
Net income	$	147		$	121		$	89
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of $1 in 2011 and 2010	(1		)	1			(1		)
Comprehensive income	146			122			88
Less: comprehensive loss attributable to the noncontrolling interests	—			(4		)	(6		)
Comprehensive income attributable to Portland General Electric Company	$	146		$	126		$	94

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	As of December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	6		$	4
Accounts receivable, net	144			137
Unbilled revenues	101			93
Inventories, at average cost:
Materials and supplies	37			34
Fuel	34			22
Margin deposits	80			83
Regulatory assets—current	216			221
Other current assets	98			67
Total current assets	716			661
Electric utility plant:
Production	2,854			2,745
Transmission	393			372
Distribution	2,704			2,582
General	314			294
Intangible	331			286
Construction work in progress	120			125
Total electric utility plant	6,716			6,404
Accumulated depreciation and amortization	(2,431		)	(2,271		)
Electric utility plant, net	4,285			4,133
Regulatory assets—noncurrent	594			544
Nuclear decommissioning trust	37			34
Non-qualified benefit plan trust	36			44
Other noncurrent assets	65			75
Total assets	$	5,733		$	5,491

See accompanying notes to consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS, continued

(In millions, except share amounts)

	As of December 31,
	2011			2010
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	111		$	102
Liabilities from price risk management activities—current	216			188
Short-term debt	30			19
Current portion of long-term debt	100			10
Regulatory liabilities—current	6			25
Accrued expenses and other current liabilities	151			145
Total current liabilities	614			489
Long-term debt, net of current portion	1,635			1,798
Regulatory liabilities—noncurrent	720			657
Deferred income taxes	529			445
Liabilities from price risk management activities—noncurrent	172			188
Unfunded status of pension and postretirement plans	195			140
Non-qualified benefit plan liabilities	101			97
Other noncurrent liabilities	101			78
Total liabilities	4,067			3,892
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	—			—
Common stock, no par value, 160,000,000 shares authorized; 75,362,956 and 75,316,419 shares issued and outstanding as of December 31, 2011 and 2010, respectively	836			831
Accumulated other comprehensive loss	(6		)	(5		)
Retained earnings	833			766
Total Portland General Electric Company shareholders’ equity	1,663			1,592
Noncontrolling interests’ equity	3			7
Total equity	1,666			1,599
Total liabilities and equity	$	5,733		$	5,491

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions, except share amounts)

	Portland General Electric Company Shareholders’ Equity
	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Shares	Amount
Balance as of December 31, 2008	62,575,257	$	659	$	(5	)	$	700		$	—
Issuance of common stock, net of issuance costs of $6	12,477,500	170		—			—			—
Vesting of restricted and performance stock units	128,175	—		—			—			—
Issuance of shares pursuant to employee stock purchase plan	29,648	—		—			—			—
Noncontrolling interests’ capital contribution	—	—		—			—			7
Dividends declared	—	—		—			(76		)	—
Net income (loss)	—	—		—			95			(6		)
Other comprehensive loss	—	—		(1		)	—			—
Balance as of December 31, 2009	75,210,580	829		(6		)	719			1
Vesting of restricted and performance stock units	77,281	—		—			—			—
Issuance of shares pursuant to employee stock purchase plan	28,558	1		—			—			—
Noncontrolling interests’ capital contributions	—	—		—			—			10
Stock-based compensation	—	1		—			—			—
Dividends declared	—	—		—			(78		)	—
Net income (loss)	—	—		—			125			(4		)
Other comprehensive income	—	—		1			—			—
Balance as of December 31, 2010	75,316,419	831		(5		)	766			7
Vesting of restricted stock units	17,944	—		—			—			—
Issuance of shares pursuant to employee stock purchase plan	25,435	1		—			—			—
Issuance of shares pursuant to dividend reinvestment and direct stock purchase plan	3,158	—		—			—			—
Noncontrolling interests’ capital distributions	—	—		—			—			(4		)
Stock-based compensation	—	4		—			—			—
Dividends declared	—	—		—			(80		)	—
Net income	—	—		—			147			—
Other comprehensive loss	—	—		(1		)	—			—
Balance as of December 31, 2011	75,362,956	$	836	$	(6	)	$	833		$	3

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income	$	147		$	121		$	89
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	227			238			211
Deferred income taxes	56			67			82
Renewable adjustment clause deferrals	22			(12		)	(11		)
Regulatory deferral of settled derivative instruments	12			26			(31		)
Power cost deferrals, net of amortization	10			(1		)	(18		)
Increase (decrease) in net liabilities from price risk management activities	9			118			(145		)
Regulatory deferrals—price risk management activities	(6		)	(118		)	145
Senate Bill 408 amortization	(7		)	(13		)	—
Allowance for equity funds used during construction	(5		)	(13		)	(18		)
Decoupling mechanism deferrals, net of amortization	3			(10		)	7
Unrealized gains on non-qualified benefit plan trust assets	—			(5		)	(8		)
Other non-cash income and expenses, net	38			27			43
Changes in working capital:
(Increase) decrease in receivables and unbilled revenues	(15		)	24			11
Decrease (increase) in margin deposits	3			(27		)	133
Income tax refund received	9			53			—
Increase in income taxes receivable	—			(22		)	(53		)
Increase (decrease) in payables and accrued liabilities	5			(11		)	(16		)
Other working capital items, net	(7		)	—			2
Contribution to pension plan	(26		)	(30		)	—
Contribution to voluntary employees’ benefit association trust	(16		)	(1		)	—
Distribution of Trojan refund liability	—			—			(34		)
Other, net	(6		)	(20		)	(3		)
Net cash provided by operating activities	453			391			386
Cash flows from investing activities:
Capital expenditures	(300		)	(450		)	(696		)
Purchases of nuclear decommissioning trust securities	(50		)	(46		)	(36		)
Sales of nuclear decommissioning trust securities	46			50			36
Distribution from nuclear decommissioning trust	—			19			—
Other, net	5			(3		)	(4		)
Net cash used in investing activities	(299		)	(430		)	(700		)

See accompanying notes to consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

	Years Ended December 31,
	2011			2010			2009
Cash flows from financing activities:
Proceeds from issuance of long-term debt	$	—		$	249		$	580
Payments on long-term debt	(73		)	(186		)	(142		)
Proceeds from issuance of common stock, net of issuance costs	—			—			170
Issuances (maturities) of commercial paper, net	11			19			(65		)
Borrowings on short-term debt	—			11			—
Payments on short-term debt	—			(11		)	(7		)
Borrowings on revolving lines of credit	—			—			82
Payments on revolving lines of credit	—			—			(213		)
Dividends paid	(79		)	(78		)	(72		)
Premium paid on repayment of long-term debt	(7		)	—			—
Debt issuance costs	—			(2		)	(5		)
Noncontrolling interests’ capital (distributions) contributions	(4		)	10			7
Net cash (used in) provided by financing activities	(152		)	12			335
Change in cash and cash equivalents	2			(27		)	21
Cash and cash equivalents, beginning of year	4			31			10
Cash and cash equivalents, end of year	$	6		$	4		$	31
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	103		$	98		$	74
Cash paid for income taxes	3			—			2
Non-cash investing and financing activities:
Accrued capital additions	19			12			17
Accrued dividends payable	21			20			20
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	7			—			—

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BASIS OF PRESENTATION

Nature of Operations

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power marketers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of December 31, 2011, PGE served 822,466 retail customers with a service area population of approximately 1.7 million, comprising approximately 44% of the state’s population.

As of December 31, 2011, PGE had 2,634 employees, with 840 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 804 and 36 employees and expire in February 2015 and August 2014, respectively.

PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters.

Consolidation Principles

The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries and those variable interest entities (VIEs) where PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. Intercompany balances and transactions have been eliminated.

For entities that are determined to meet the definition of a VIE and where the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. For further information, see Note 16, Variable Interest Entities.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

Reclassifications

To conform with the 2011 presentation, PGE reclassified $67 million of accrued expenses in the 2010 consolidated balance sheet, consisting of accrued employee compensation and benefits and other, from Accounts payable to Accrued expenses and other current liabilities, and segregated Renewable adjustment clause deferrals from Other non-cash income and expenses, net in the operating activities section in the 2010 and 2009 consolidated statements of cash flows.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had none as of December 31, 2011 and 2010.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts and do not bear interest when recorded. Late payment fees on balances in arrears are first assessed 16 business days after the due date. An inactive account balance is charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the final due date.

Estimated provisions for uncollectible accounts receivable related to retail sales, charged to Administrative and other expense, are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection of customer accounts, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors.

Provisions related to wholesale accounts receivable and unsettled positions, charged to Purchased power and fuel expense, are based on a periodic review and evaluation that includes counterparty non-performance risk and contractual rights of offset when applicable. Actual amounts written off are charged to the allowance for uncollectible accounts.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities, unless they qualify for the normal purchases and normal sales exception. Changes in fair value are recognized in the statement of income, offset by the effects of regulatory accounting.

Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load meet the requirements for treatment under the normal purchases and normal sales exception. Other activities consist of certain electricity forwards, options and swaps, certain natural gas forwards, options, and swaps, and forward contracts for acquiring Canadian dollars. Such activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. Contracts that qualify for the normal purchases and normal sales exception are not required to be recorded at fair value. Unrealized gains and losses from contracts that qualify as cash flow hedges are recorded net in Other comprehensive income and contracts not designated as cash flow hedges are recorded net in Purchased power and fuel expense on the statements of income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

Physical electricity sale and purchase transactions are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while financial transactions are recorded on a net basis in Purchased power and fuel expense upon settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are classified as Margin deposits in the accompanying consolidated balance sheets and were $80 million and $83 million as of December 31, 2011 and 2010, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $104 million and $180 million as of December 31, 2011 and 2010, respectively.

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, oil, and coal. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

Electric Utility Plant

Capitalization Policy

Electric utility plant is capitalized at its original cost. Costs include direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period.

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 8% in 2011 and 2010, and 7% in 2009. AFDC from borrowed funds was $3 million in 2011, $9 million in 2010, and $12 million in 2009 and is reflected as a reduction to Interest expense. AFDC from equity funds was $5 million in 2011, $13 million in 2010, and $18 million in 2009 and is reflected as a component of Other income, net.

Costs which are disallowed for recovery in customer prices are charged to expense at the time such disallowance is probable.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.7% in 2011, 3.9% in 2010, and 3.8% in 2009. Estimated asset retirement removal costs included in depreciation expense were $49 million in the year ended December 31, 2011 and $47 million in each of the years ended December 31, 2010 and 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. On September 13, 2010, PGE received an order from the OPUC authorizing new depreciation rates to be effective January 2011.

Thermal production plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2050. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):

Production, excluding thermal:
Hydro	86
Wind	27
Transmission	53
Distribution	40
General	14

The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are charged to AROs for assets that meet the definition of a legal obligation and to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs.

On June 21, 2011, PGE received an order from the OPUC authorizing an increase in customer prices effective July 1, 2011 for depreciation expense and decommissioning costs related to the Company’s commitment to cease coal-fired operations at Boardman at the end of 2020.

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $153 million and $133 million as of December 31, 2011 and 2010, respectively, with amortization expense of $19 million in 2011, $17 million in 2010, and $16 million in 2009. Future estimated amortization expense as of December 31, 2011 is as follows: $20 million in 2012; $14 million in 2013; $12 million in 2014; $11 million in 2015; and $8 million in 2016.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.

Regulatory Accounting

Regulatory Assets and Liabilities

As a rate-regulated enterprise, the Company applies regulatory accounting, resulting in regulatory assets or regulatory liabilities. Regulatory assets represent (i) probable future revenue associated with certain costs that are expected to be recovered from customers through the ratemaking process, or (ii) probable future collections from

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established by or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the statement of income over the period in which it is included in prices.

Circumstances that could result in the discontinuance of regulatory accounting include (i) increased competition that restricts the Company’s ability to establish prices to recover specific costs, and (ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’s regulatory assets is probable.

For additional information concerning the Company’s regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities.

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband.” If the difference between actual NVPC and baseline NVPC falls within the established deadband range, PGE absorbs the incremental cost or benefit, with the difference falling outside the lower and upper thresholds of the deadband range being shared 90/10 between customers and the Company, respectively. Any customer refund or collection is also subject to a regulated earnings test. A refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE. A collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s last authorized ROE. PGE’s authorized ROE was 10% for 2011, 2010, and 2009. A final determination of any customer refund or collection is made by the OPUC through an annual public filing and review.

PGE estimates and records amounts related to the PCAM on a quarterly basis during the year. If the projected difference between baseline and actual NVPC for the year exceeds the established deadband, and if forecasted earnings exceed the level required by the regulated earnings test, a regulatory liability is recorded for any future amount payable to retail customers, with offsetting amounts recorded to Purchased power and fuel expense. If the difference is below the lower end of the deadband, a regulatory asset is recorded for any future amount due from retail customers.

For 2011, the deadband ranged from $15 million below to $30 million above baseline NVPC. PGE’s actual NVPC as determined pursuant to the PCAM for 2011 was below baseline NVPC by $34 million, which is $19 million below the lower deadband threshold. For 2011, PGE recorded an estimated refund to customers of $10 million, reduced from the $17 million potential refund to customers as a result of the regulated earnings test. A final determination regarding the 2011 PCAM results will be made by the OPUC through a public filing and review in 2012.

For 2010, the deadband ranged from $17 million below to $35 million above baseline NVPC. Although PGE’s actual NVPC as determined pursuant to the PCAM for 2010 was below baseline NVPC by $12 million, it was

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

within the established deadband range and, accordingly, no customer refund was recorded in 2010. A final determination regarding the 2010 PCAM results was made by the OPUC through a public filing and review in 2011, which concluded that no customer refund was warranted for 2010.

For 2009, the deadband ranged from $15 million below to $29 million above baseline NVPC. Although PGE’s actual NVPC as determined pursuant to the PCAM for 2009 exceeded baseline NVPC by $22 million, it was within the established deadband range and, accordingly, no customer collection was recorded in 2009. A final determination regarding the 2009 PCAM results was made by the OPUC through a public filing and review in 2010, which concluded that no customer collection was warranted for 2009.

Asset Retirement Obligations

An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. PGE recognizes those legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future removal expenditures is capitalized as an ARO on the consolidated balance sheets and revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income.

Contingencies

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

Gain contingencies are recognized when realized and are disclosed when material.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position as of December 31, 2011 and 2010.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated

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statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxesand totaled $41 million in 2011, $39 million in 2010, and $38 million in 2009.

Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices.

As a rate-regulated utility, there are situations in which PGE accrues revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “Regulatory Assets and Liabilities” in this Note 2.

Stock-Based Compensation

The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.

Income Taxes

Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $87 million and $95 million as of December 31, 2011 and 2010, respectively, and will be included in prices when the temporary differences reverse.

Investment tax credits utilized were deferred and amortized to income over the lives of the related properties, and were fully amortized by the end of 2011.

Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet.

PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

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Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2010-06, Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU 2010-06) requires, among other matters, separate reporting about purchases, sales, issuances, and settlements for Level 3 fair value measurements. For additional information on Level 3, see Note 4, Fair Value of Financial Instruments. In accordance with the provisions of ASU 2010-06, PGE adopted this requirement of ASU 2010-06 on January 1, 2011, which did not have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows. All other requirements of ASU 2010-06 were adopted on January 1, 2010 in accordance with ASU 2010-06.

In May 2011, ASU 2011-04, Fair Value Measurements and Disclosures (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04) was issued. Many of the amendments in ASU 2011-04 change the wording used to describe principles and requirements to align with International Financial Reporting Standards as issued by the International Accounting Standards Board, and are not intended to change the application of Topic 820. Some of the amendments clarify the Financial Accounting Standards Board’s intent on the application of existing fair value guidance or change a particular principle or requirement for measuring fair value or fair value disclosures. The amendments in ASU 2011-04 are to be applied prospectively and are effective for interim and annual periods beginning after December 15, 2011 for public entities, with early application not permitted. PGE will adopt the amendments contained in ASU 2011-04 on January 1, 2012, which are not expected to have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In June 2011, ASU 2011-05, Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU 2011-05) was issued. The amendments of ASU 2011-05 require, among other things, that an entity report items of other comprehensive income in one of two ways: (i) a single statement with components of net income and total net income, the components of other comprehensive income and total other comprehensive income, and a total for comprehensive income; or (ii) two statements with components of net income and total net income in the first statement, immediately followed by a statement that presents the components of other comprehensive income, a total for other comprehensive income, and a total for comprehensive income. The amendments in ASU 2011-05 are to be applied retrospectively and are effective for interim and annual periods beginning after December 15, 2011, with early application permitted. PGE adopted the amendments contained in ASU 2011-05 on December 31, 2011, which had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In December 2011, ASU 2011-12, Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU 2011-12) was issued and defers only the changes in ASU 2011-05 that relate to the presentation of reclassification adjustments, which pertain to how and where reclassification adjustments are presented. ASU 2011-12 is effective at the same time as ASU 2011-05. Accordingly, PGE adopted the amendments contained in ASU 2011-12 on December 31, 2011, which had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

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NOTE 3: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million and $5 million as of December 31, 2011 and 2010, respectively. The following is the activity in the allowance for uncollectible accounts (in millions):

	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	5		$	5		$	4
Increase in provision	11			7			9
Amounts written off, less recoveries	(10		)	(7		)	(8		)
Balance as of end of year	$	6		$	5		$	5

Trust Accounts

PGE maintains two trust accounts as follows:

Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and represent amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein.

Non-qualified benefit plan trust—Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and represents contributions made by the Company less qualified expenditures plus any realized and unrealized gains and losses on the investment held therein.

The trusts are comprised of the following investments as of December 31 (in millions):

	Nuclear     Decommissioning Trust				Non-Qualified Benefit     Plan Trust
	2011		2010		2011		2010
Cash equivalents	$	14	$	13	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		10		19
Debt securities	23		21		3		2
Insurance contracts, at cash surrender value	—		—		23		23
	$	37	$	34	$	36	$	44

For information concerning the fair value measurement of those assets recorded at fair value held in the trusts, see Note 4, Fair Value of Financial Instruments.

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Other Current Assets and Accrued Expenses and Other Current Liabilities

Other current assets and Accrued expenses and other current liabilities consist of the following (in millions):

	As of December 31,
	2011		2010
Other current assets:
Current deferred income tax asset	$	33	$	—
Assets from price risk management activities	19		13
Income taxes receivable	12		22
Other	34		32
	$	98	$	67
Accrued expenses and other current liabilities:
Accrued employee compensation and benefits	$	44	$	36
Accrued interest payable	24		26
Dividends payable	21		20
Other	62		63
	$	151	$	145

Other Noncurrent Assets

The Company incurs preliminary engineering costs related to potential future capital projects, which are capitalized in Other noncurrent assets in the consolidated balance sheets. Preliminary engineering costs consist of expenditures for preliminary surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects being considered. Once the project is approved for construction, such costs are reclassified to Electric utility plant. If the project is abandoned, such costs are expensed to Production and distribution expense in the period such determination is made. If any preliminary engineering costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. As of December 31, 2011 and 2010, PGE has recorded preliminary engineering costs of $10 million and $13 million, respectively. For the years ended December 31, 2011, 2010, and 2009, no material preliminary engineering costs were expensed.

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2011 and 2010, and then classified based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2—Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date.

Level 3—Pricing inputs include significant inputs which are unobservable for the asset or liability.

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

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PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels, except those net transfers out of Level 3 to Level 2 presented in this note, for the years ended December 31, 2011 and 2010.

The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): 

	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		11		—		11
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	7		2		—		9
International	1		—		—		1
Debt securities - domestic government	3		—		—		3
Assets from price risk management activities (1) (3):
Electricity	—		2		—		2
Natural gas	—		17		—		17
	$	14	$	55	$	—	$	69
Liabilities - Liabilities from price risk management activities(1) (3):
Electricity	$	—	$	108	$	29	$	137
Natural gas	—		201		50		251
	$	—	$	309	$	79	$	388

(1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.

(2) Excludes insurance policies of $23 million, which are recorded at cash surrender value.

(3) For further information, see Note 5, Price Risk Management.

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	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	13	$	—	$	13
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		9		—		9
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	16		—		—		16
International	2		1		—		3
Debt securities - domestic government	2		—		—		2
Assets from price risk management activities (1) (3):
Electricity	—		4		1		5
Natural gas	—		11		—		11
	$	23	$	47	$	1	$	71
Liabilities - Liabilities from price risk management activities (1) (3):
Electricity	$	—	$	102	$	17	$	119
Natural gas	—		153		104		257
	$	—	$	255	$	121	$	376

(1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.

(2) Excludes insurance policies of $23 million, which are recorded at cash surrender value.

(3) For further information, see Note 5, Price Risk Management.

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and allocated to securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors:

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds held in the Nuclear decommissioning trust are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices.

Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These securities are classified as Level 1 in the fair value hierarchy due to the highly observable nature of the pricing in an active market.

Fair values for municipal debt and corporate credit securities are classified as Level 2 as prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.

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Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE), both American stock exchanges. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs may not be directly observable in the marketplace.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign exchange rate risk, mitigate the effects of market fluctuations, and manage volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Price Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as quoted forward prices for commodities and interest rates. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include over-the-counter forwards and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term over-the-counter forward and swap derivatives. Commodity option contracts whose fair value is derived using standardized valuation techniques, such as Black-Scholes, are also classified as Level 3. Inputs into the valuation of commodity option contracts include forward commodity pricing, forward interest rates, and historic volatilities and correlations.

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows for the year ended December 31, 2011 (in millions):

Net liabilities from price risk management activities as of December 31, 2010	$	120
Net realized and unrealized losses (1)	86
Purchases	3
Settlements	(1		)
Net transfers out of Level 3 to Level 2	(129		)
Net liabilities from price risk management activities as of December 31, 2011	$	79
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	88

(1) Contains nominal amounts of realized losses, net.

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The comparable information contained in the preceding table was as follows for the years ended December 31 (in millions): 

	2010			2009
Net liabilities from price risk management activities as of beginning of year	$	154		$	123
Net realized and unrealized losses (1)	65			47
Purchases, issuances, and settlements, net	27			—
Net transfers out of Level 3 to Level 2	(126		)	(16		)
Net liabilities from price risk management activities as of end of year	$	120		$	154
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	95		$	49

(1) Contains nominal amounts of realized losses, net.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. Transfers out of Level 3 occur when the significant inputs become more observable, such as the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial instruments.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of December 31, 2011, the estimated aggregate fair value of PGE’s long-term debt was $2,091 million, compared to its $1,735 million carrying amount. As of December 31, 2010, the estimated aggregate fair value of PGE’s long-term debt was $1,968 million, compared to its $1,808 million carrying amount.

For fair value information concerning the Company’s pension plan assets, see Note 10, Employee Benefits.

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NOTE 5: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generating resources combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include fuel and power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, where adverse changes in prices and/or rates may affect the Company’s financial position, performance, or cash flow.

PGE utilizes derivative instruments in its wholesale electric utility activities to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in net power costs for its retail customers. These derivative instruments may include forward, swap, and option contracts for electricity, natural gas, oil and foreign currency, which are recorded at fair value on the consolidated balance sheet, with changes in fair value recorded in the statement of income. In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until realized. This accounting treatment defers the fair value gains and losses on derivative activities until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes.

PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists. As of December 31, 2011 and 2010, the Company had $26 million and $31 million, respectively, in collateral posted with these counterparties, consisting entirely of letters of credit.

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2015, were as follows (in millions): 

	As of December 31,
	2011			2010
Commodity contracts:
Electricity	13		MWh	9		MWh
Natural gas	79		Decatherms	93		Decatherms
Foreign currency exchange	$	6	Canadian	$	7	Canadian

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The fair values of PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): 

	As of December 31,
	2011			2010
Current assets:
Commodity contracts:
Electricity	$	2		$	4
Natural gas	17			9
Total current derivative assets	19		(1)	13		(1)
Noncurrent assets:
Commodity contracts:
Electricity	—			1
Natural gas	—			2
Total noncurrent derivative assets	—			3		(2)
Total derivative assets not designated as hedging instruments	$	19		$	16
Total derivative assets	$	19		$	16
Current liabilities:
Commodity contracts:
Electricity	$	66		$	77
Natural gas	150			111
Total current derivative liabilities	216			188
Noncurrent liabilities:
Commodity contracts:
Electricity	71			42
Natural gas	101			146
Total noncurrent derivative liabilities	172			188
Total derivative liabilities not designated as hedging instruments	$	388		$	376
Total derivative liabilities	$	388		$	376

(1) Included in Other current assets on the consolidated balance sheet.

(2) Included in Other noncurrent assets on the consolidated balance sheet.

Net realized and unrealized losses on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions):

	Years Ended December 31,
	2011		2010		2009
Commodity contracts:
Electricity	$	117	$	127	$	79
Natural Gas	98		192		101

Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2011, 2010, and 2009, $192 million, $258 million, and $98 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net

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unrealized loss recorded as of December 31, 2011 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):

	2012		2013		2014		2015		Total
Commodity contracts:
Electricity	$	64	$	42	$	21	$	8	$	135
Natural gas	132		72		24		6		234
Net unrealized loss	$	196	$	114	$	45	$	14	$	369

The Company’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s Ratings Services (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties and some other counterparties will have the right to terminate their agreements with the Company.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2011 was $321 million, for which the Company had $104 million in posted collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2011, the cash requirement to either post as collateral or settle the instruments immediately would have been $302 million.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:

	As of December 31,
	2011		2010
Assets from price risk management activities:
Counterparty A	19	%	1	%
Counterparty B	16		1
Counterparty C	13		5
Counterparty D	7		22
Counterparty E	7		23
Counterparty F	—		11
Counterparty G	—		10
	62	%	73	%
Liabilities from price risk management activities:
Counterparty E	23	%	24	%
Counterparty H	10		4
Counterparty I	7		12
	40	%	40	%

For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 4, Fair Value of Financial Instruments.

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NOTE 6: REGULATORY ASSETS AND LIABILITIES

The majority of PGE’s regulatory assets and liabilities are reflected in customer prices and are amortized over the period in which they are reflected in customer prices. Items not currently reflected in prices are pending before the regulatory body as discussed below.

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

		Weighted Average Remaining Life (1)	As of December 31,
			2011				2010
			Current		Noncurrent		Current		Noncurrent
Regulatory assets:
	Price risk management (2)	2 years	$	194	$	172	$	175	$	185
	Pension and other postretirement plans (2)	(3)	—		295		—		213
	Deferred income taxes (2)	(4)	—		87		—		95
	Deferred broker settlements (2)	1 year	11		—		24		—
	Renewable energy deferral	1 year	1		—		22		—
	Debt reacquisition costs (2)	7 years	—		28		—		23
	Other (5)	Various	10		12		—		28
	Total regulatory assets		$	216	$	594	$	221	$	544
Regulatory liabilities:
	Asset retirement removal costs (6)	(4)	$	—	$	637	$	—	$	588
	Asset retirement obligations (6)	(4)	—		36		—		33
	Power cost adjustment mechanism	(7)	—		10		—		—
	Trojan ISFSI pollution control tax credits	(7)	—		7		18		4
	Other	Various	6		30		7		32
	Total regulatory liabilities		$	6	$	720	$	25	$	657

(1) As of December 31, 2011.

(2) Does not include a return on investment.

(3) Recovery expected over the average service life of employees. For additional information, see Note 2, Summary of Significant Accounting Policies.

(4) Recovery expected over the estimated lives of the assets.

(5) Of the total other unamortized regulatory asset balances, a return is recorded on $21 million and $26 million as of December 31, 2011 and 2010, respectively.

(6) Included in rate base for ratemaking purposes.

(7) Refund period not yet determined.

As of December 31, 2011, PGE had regulatory assets of $22 million earning a return on investment at the following rates: (i) $7 million at PGE’s authorized cost of capital, currently 8.033%; (ii) $7 million at the approved rate for deferred accounts under amortization, ranging from 2.01% to 4.27%, depending on the year of approval; and (iii) $8 million earning a return by inclusion in rate base.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. During the fourth quarter of 2011, PGE received an order from the OPUC on its Annual Update Tariff for 2012 net variable power costs (NVPC). Pursuant to the order, the OPUC reduced the Company’s 2012 NVPC forecast by approximately $3 million, which is reflected as a reduction to the regulatory asset for price risk

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management as of December 31, 2011. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management.

Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic benefit cost. For further information, see Note 10, Employee Benefits.

Deferred income taxes represents income tax benefits resulting from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. For further information, see Note 11, Income Taxes.

Deferred broker settlements consist of transactions that have been financially settled by clearing brokers prior to the contract delivery date. These gains and losses are deferred for future recovery in customer prices during the corresponding contract settlement month.

Renewable energy deferral reflects the net revenue requirement related to new renewable resources and associated transmission that are not yet included in customer prices, with the majority related to Biglow Canyon Wind Farm. Recovery of net revenue requirements associated with new renewable resources, which are required by the 2007 Oregon Renewable Energy Act, is allowed under a renewable adjustment clause mechanism authorized by the OPUC.

Asset retirement removal costs represent the costs that do not qualify as AROs and are a component of depreciation expense allowed in customer prices. Such costs are recorded as a regulatory liability as they are collected in prices, and are reduced by actual removal costs incurred.

Asset retirement obligations represent the difference in the timing of recognition of (i) the amounts recognized for depreciation expense of the asset retirement costs and accretion of the ARO, and (ii) the amount recovered in customer prices.

NOTE 7: ASSET RETIREMENT OBLIGATIONS

AROs, which are included in Other noncurrent liabilities in the consolidated balance sheets, consist of the following (in millions):

	As of December 31,
	2011		2010
Trojan decommissioning activities	$	37	$	38
Utility plant	38		16
Non-utility property	12		10
Asset retirement obligations	$	87	$	64

Trojan decommissioning activities represents the present value of future decommissioning expenditures for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI is to house the spent nuclear fuel at the former plant site until permanent off-site storage is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a U.S. Department of Energy (USDOE) facility is complete, which is not expected prior to 2033.

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE

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had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs are seeking approximately $128 million in damages. PGE’s share of any recovery would be approximately 67%. A trial before the U.S. Court of Federal Claims commenced in the fourth quarter of 2011, with a decision expected during 2012. However, if the Plaintiffs were to prevail, the USDOE would likely appeal, which would defer any damage payment indefinitely. The Trojan ARO will not be impacted by the outcome of this case as such potential recovery is for past decommissioning costs and the ARO reflects only future decommissioning expenditures. Any proceeds received related to this legal matter would be returned to customers to offset amounts previously collected in relation to Trojan decommissioning activities.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets where disposal is governed by environmental regulation, as well as the Bull Run hydro project. Decommissioning work has been substantially completed at Bull Run, with only environmental monitoring continuing through 2012.

During 2011, an updated decommissioning study for PGE’s Boardman coal-fired plant was completed, which included the assumption that Boardman’s coal-fired operations cease in 2020 rather than 2040. As a result of the study, PGE increased its ARO related to Boardman by approximately $20 million, with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. Such transaction is non-cash and is excluded from investing activities in the consolidated statement cash flows for the year ended December 31, 2011.

Non-utility property primarily represents ARO’s which have been recognized for portions of unregulated properties leased to third parties.

The following is a summary of the changes in the Company’s AROs (in millions):

	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	64		$	63		$	58
Liabilities incurred	1			1			—
Liabilities settled	(4		)	(3		)	(4		)
Accretion expense	4			4			4
Revisions in estimated cash flows	22			(1		)	5
Balance as of end of year	$	87		$	64		$	63

Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. Recovery of Trojan decommissioning costs is included in PGE’s retail prices, currently at approximately $4 million annually, with an equal amount recorded in Depreciation and amortization expense.

PGE maintains a separate trust account, Nuclear decommissioning trust in the consolidated balance sheet, for funds collected from customers through prices to cover the cost of Trojan decommissioning activities. See “Trust Accounts” in Note 3, Balance Sheet Components, for additional information on the Nuclear decommissioning trust.

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The Oak Grove hydro facility and transmission and distribution plant located on public right-of-ways and on certain easements meet the requirements of a legal obligation and will require removal when the plant is no longer in service. An ARO liability is not currently measurable as management believes that these assets will be used in utility operations for the foreseeable future. Removal costs are charged to accumulated asset retirement removal costs, which is included in Regulatory liabilities on PGE’s consolidated balance sheets.

NOTE 8: REVOLVING CREDIT FACILITIES

PGE has two unsecured revolving credit facilities, with an aggregate borrowing capacity of $670 million, as follows:

• A $370 million syndicated credit facility, of which $10 million is scheduled to terminate in July 2012 and $360 million in July 2013;

• A $300 million syndicated credit facility, which is scheduled to terminate in December 2016.

Pursuant to the terms of the agreements, both credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both credit facilities require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2011, PGE was in compliance with this covenant with a 51.5% debt ratio.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the credit facilities.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt up to $700 million through February 6, 2014. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

As of December 31, 2011, PGE had no borrowings and $30 million in commercial paper outstanding under the credit facilities, with $124 million in letters of credit issued. As of December 31, 2011, the aggregate unused available credit under the credit facilities is $516 million.

Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions):

	Years Ended December 31,
	2011			2010			2009
Average daily amount of short-term debt outstanding	$	2		$	9		$	28
Weighted daily average interest rate *	0.4		%	0.4		%	1.3		%
Maximum amount outstanding during the year	$	44		$	51		$	205

* Excludes the effect of commitment fees, facility fees and other financing fees.

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NOTE 9: LONG-TERM DEBT

Long-term debt consists of the following (in millions):

	As of December 31,
	2011			2010
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.83% in 2011 and 5.85% in 2010, due at various dates through 2040	$	1,615		$	1,678
Pollution Control Revenue Bonds:
Port of Morrow, Oregon, 5% rate, due 2033	23			23
City of Forsyth, Montana, 5% rate, due 2033	119			119
Port of St. Helens, Oregon, 5.25% rate, due in 2014	—			10
Total Pollution Control Revenue Bonds	142			152
Pollution Control Revenue Bonds owned by PGE	(21		)	(21		)
Unamortized debt discount	(1		)	(1		)
Total long-term debt	1,735			1,808
Less: current portion of long-term debt	(100		)	(10		)
Long-term debt, net of current portion	$	1,635		$	1,798

First Mortgage Bonds—The Indenture securing PGE’s First Mortgage Bonds constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. On December 29, 2011, PGE redeemed $63 million of the 6.5% series due 2014.

Pollution Control Revenue Bonds—PGE has the option to remarket Pollution Control Revenue Bonds held by the Company through 2033. At the time of any remarketing, PGE can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing and could be backed by first mortgage bonds or a bank letter of credit depending on market conditions.

As of December 31, 2011, the future minimum principal payments on long-term debt are as follows (in millions):

Years ending December 31:
2012	$	100
2013	100
2014	—
2015	70
2016	67
Thereafter	1,398
	$	1,735

Interest is payable semi-annually on all long-term debt instruments.

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NOTE 10: EMPLOYEE BENEFITS

Pension and Other Postretirement Plans

Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan. The plan has been closed to most new employees since January 31, 2009 and to all new employees since January 1, 2012. Such closure did not change the benefits provided to existing participants under the plan.

The assets of the pension plan are held in a trust and are comprised of equity, debt, and alternative asset investment vehicles, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31.

During 2011 and 2010, PGE made contributions to the pension plan of $26 million and $30 million, respectively, with no contributions in 2009. No contributions to the pension plan are expected in 2012.

Other Postretirement Benefits—PGE has non-contributory postretirement health and life insurance plans, as well as Health Reimbursement Accounts (HRAs) for its employees (collectively “Other Postretirement Benefits” in the following tables). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees paying the additional cost.

The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, common stocks, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions which are reviewed annually with PGE’s consulting actuaries and trust investment consultants and updated as appropriate, with measurement dates of December 31.

Contributions to the HRAs provide for claims by retirees for qualified medical costs. For bargaining employees, the participants’ accounts are credited with 58% of the value of the employee’s accumulated sick time as of April 30, 2004, plus 100% of their earned time off accumulated at the time of retirement. For active non-bargaining employees, the Company grants a fixed dollar amount that will become available for qualified medical expenses upon their retirement.

Non-Qualified Benefit Plans—The Non-Qualified Benefit Plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan (SERP), and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. These trust assets are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified benefit plans is December 31.

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. The Company also provides two retired employees with death benefits through a split dollar life insurance policy which pays a fixed amount to the beneficiary and for which the Company has a security interest for the amount of premiums paid. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

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Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions):

	2011						2010
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	17	$	19	$	36	$	19	$	25	$	44
Non-qualified benefit plan liabilities *	25		76		101		24		73		97

* For the NQBP, excludes the current portion of $2 million in 2011 and 2010, which is classified in Other current liabilities in the consolidated balance sheets.

See “Trust Accounts” in Note 3, Balance Sheet Components, for information on the Non-qualified benefit plan trust.

Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of officers of the Company. In addition, the Board also establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation and oversight of the asset allocation. The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. The commitments to each class are controlled by an asset deployment and cash management strategy that takes profits from asset classes whose allocations have shifted above their target ranges to fund benefit payments and investments in asset classes whose allocations have shifted below their target ranges.

The asset allocations for the plans, and the target allocation, are as follows:

	As of December 31,
	2011				2010
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	68	%	67	%	68	%	67	%
Debt securities	32		33		32		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	61	%	72	%	46	%	47	%
Debt securities	39		28		54		53
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	30	%	23	%	42	%	42	%
Debt securities	7		14		5		7
Insurance contracts	63		63		53		51
Total	100	%	100	%	100	%	100	%

* The Target for the Defined Benefit Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans, these Targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average Targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools.

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The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments across the capitalization ranges and style biases, both domestically and internationally. Fixed income securities include, but are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.

The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions):  

	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	3	$	—	$	3
Equity securities:
Domestic	151		12		—		163
International	54		51		—		105
Debt securities:
Domestic government and corporate credit	—		78		—		78
Corporate credit	76		—		—		76
Private equity funds	—		—		32		32
Alternative investments	—		—		30		30
	$	281	$	144	$	62	$	487
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	12		1		—		13
International	2		2		—		4
Debt securities—Domestic government	3		—		—		3
	$	17	$	10	$	—	$	27

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	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	15	$	—	$	15
Equity securities:
Domestic	52		111		—		163
International	53		53		—		106
Debt securities—Domestic government and corporate credit	68		70		—		138
Private equity funds	—		—		23		23
Alternative investments	—		—		28		28
	$	173	$	249	$	51	$	473
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	3		2		—		5
International	1		1		—		2
Debt securities—Domestic government	2		—		—		2
	$	6	$	10	$	—	$	16

An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 4, Fair Value of Financial Instruments. The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short term treasury bills, federal agency securities, certificates of deposit, and commercial paper. Money market funds held in the trusts are classified as Level 2 instruments as they are traded in an active market of similar securities but are not directly valued using quoted prices.

Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 securities based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 securities due to pricing inputs that are not directly or indirectly observable in the marketplace.

Debt securities—PGE invests in highly-liquid United States treasury and corporate credit mutual fund securities to support the investment objectives of the trusts. These securities are classified as Level 1 instruments due to the highly observable nature of pricing in an active market.

Fair values for Level 2 debt securities, including municipal debt and corporate credit securities, mortgage-backed securities and asset-backed securities are determined by evaluating pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation if applicable.

Private equity—PGE invests in a combination of primary and secondary fund-of-funds which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, venture capital, buyout and special situations. Private equity investments are classified as Level 3 securities due to fund valuation methodologies that utilize discounted cash flow, market comparable and limited secondary market pricing to develop estimates of fund valuation. PGE valuation of individual fund performance compares stated fund performance against published benchmarks.

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Alternative investments—Investments in a portable alpha strategy are comprised of long positions in S&P 500 futures contracts and a hedge fund-of-funds comprised of diversified group, by sector and market capitalization of long only, short only and/or both long/short equity hedge funds. Valuation of hedge funds included within this vehicle is provided by fund managers using unobservable internally modeled inputs. PGE performs validation procedures of manager performance by comparing stated performance against published benchmarks. Alternative investments are classified as level 3 due to lack of observable market inputs and relative illiquidity of the fund.

Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy presented in the table above were as follows for the years ended December 31, 2011 and 2010 (in millions):

	Private equity			Alternative assets		Total Level 3
Balance as of December 31, 2009	$	17		$	23	$	40
Purchases and sales, net	4			2		6
Realized gain on sales	1			—		1
Unrealized gain on assets	1			3		4
Balance as of December 31, 2010	23			28		51
Purchases	7			—		7
Realized loss on sales	(2		)	—		(2		)
Unrealized gain on assets	4			2		6
Balance as of December 31, 2011	$	32		$	30	$	62

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The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2011 and 2010. Obligations related to the Other NQBP are not included in the following tables (dollars in millions):

	Defined Benefit Pension Plan						Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2011			2010			2011			2010			2011			2010
Benefit obligation:
As of January 1	$	550		$	491		$	79		$	77		$	25		$	27
Service cost	12			11			2			2			—			—
Interest cost	29			28			4			4			1			1
Participants’ contributions	—			—			2			2			—			—
Actuarial loss (gain)	69			42			(5		)	1			3			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	634		$	550		$	75		$	79		$	27		$	25
Fair value of plan assets:
As of January 1	$	473		$	406		$	16		$	19		$	19		$	20
Actual return on plan assets	14			59			—			1			—			2
Company contributions	26			30			16			1			—			—
Participants’ contributions	—			—			2			2			—			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	487		$	473		$	27		$	16		$	17		$	19
Unfunded position as of December 31	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)
Accumulated benefit plan obligation as of December 31	$	566		$	503		N/A			N/A			$	27		$	25
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	17		$	19
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(147		)	(77		)	(48		)	(63		)	(25		)	(23		)
Net liability	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)

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	Defined Benefit Pension Plan						Other Postretirement Benefits								Non-Qualified Benefit Plans
	2011			2010			2011				2010				2011			2010
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	97		$	22		$	(4	)		$	1			$	2		$	—
Amortization of net actuarial loss	(8		)	(3		)	(1		)		(1		)		(1		)	(1		)
Amortization of prior service cost	(1		)	(1		)	(1		)		(1		)		—			—
	$	88		$	18		$	(6	)		$	(1	)		$	1		$	(1	)
Amounts included in AOCL*:
Net actuarial loss	$	275		$	186		$	15			$	20			$	10		$	9
Prior service cost	1			2			4				5				—			—
	$	276		$	188		$	19			$	25			$	10		$	9
Assumptions used:
Discount rate used to calculate benefit obligation	5.00		%	5.47		%	3.76		%	-	4.02		%	-	5.00		%	5.47		%
							4.90		%		5.40		%
Weighted average rate of increase in future compensation levels	3.71		%	3.80		%	4.58		%		4.83		%		N/A			N/A
Long-term rate of return on plan assets	8.25		%	8.50		%	7.09		%		6.44		%		N/A			N/A

* Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets.

Net periodic benefit cost consists of the following for the years ended December 31 (in millions):

	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2011			2010			2009			2011			2010			2009			2011		2010		2009
Service cost	$	12		$	11		$	11		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	29			28			31			4			4			4			1		1		2
Expected return on plan assets	(42		)	(39		)	(43		)	(1		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	1			1			1			1			1			1			—		—		—
Amortization of net actuarial loss	8			3			—			1			1			1			1		1		—
Net periodic benefit cost	$	8		$	4		$	—		$	7		$	7		$	7		$	2	$	2	$	2

PGE estimates that $20 million will be amortized from AOCL into net periodic benefit cost in 2012, consisting of a net actuarial loss of $17 million for pension benefits, $1 million for non-qualified benefits and $1 million for other postretirement benefits, and prior service cost of $1 million for other postretirement benefits.

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The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):

	Payments Due
	2012		2013		2014		2015		2016		2017 - 2021
Defined benefit pension plan	$	31	$	32	$	34	$	36	$	37	$	209
Other postretirement benefits	4		4		4		4		5		23
Non-qualified benefit plans	2		2		2		3		2		11
Total	$	37	$	38	$	40	$	43	$	44	$	243

All of the plans develop expected long-term rates of return for the major asset classes using long-term historical returns, with adjustments based on current levels and forecasts of inflation, interest rates, and economic growth. Also included are incremental rates of return provided by investment managers whose returns are expected to be greater than the markets in which they invest.

For measurement purposes, the assumed health care cost trend rates, which can affect amounts reported for the health care plans, were as follows:

• For 2011, 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 through 2013, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019;

• For 2010, 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011 through 2013, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; and

• For 2009, 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2010, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2015.

A one percentage point increase or decrease in the above health care cost assumption would have no material impact on total service or interest cost, and would increase or decrease the postretirement benefit obligation by less than $1 million.

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees hired prior to February 1, 2009, the Company matches employee contributions up to 6% of the participating employee’s base pay. For eligible employees hired after January 31, 2009, and/or who are not otherwise covered by a defined benefit pension plan, PGE matches up to 5% of the participating employee’s base salary and, whether or not an employee contributes to the 401(k) Plan, the Company contributes 5% of the employee’s base salary.

For bargaining employees, who are subject to the International Brotherhood of Electrical Workers Local 125 agreements, the Company contributes a stated amount per compensable hour plus 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions of approximately $16 million, $15 million, and $14 million during the years ended December 31, 2011, 2010, and 2009.

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NOTE 11: INCOME TAXES

Income tax expense (benefit) consists of the following (in millions):

	Years Ended December 31,
	2011		2010			2009
Current:
Federal	$	2	$	(20	)	$	(46	)
State and local	—		—			—
	2		(20		)	(46		)
Deferred:
Federal	43		61			78
State and local	13		12			6
	56		73			84
Investment tax credit adjustments	—		—			(2		)
Income tax expense	$	58	$	53		$	36

The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows:

	Years Ended December 31,
	2011		2010		2009
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(12.7	)	(10.4	)	(8.3	)
State and local taxes, net of federal tax benefit	2.6		4.4		3.4
Flow through depreciation and cost basis differences	2.1		0.1		(1.6	)
Investment tax credit amortization	—		—		(1.5	)
Other	1.3		1.2		1.8
Effective tax rate	28.3	%	30.3	%	28.8	%

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Deferred income tax assets and liabilities consist of the following (in millions):

	As of December 31,
	2011			2010
Deferred income tax assets:
Price risk management	$	145		$	72
Employee benefits	135			98
Tax credits, net of valuation allowance	56			40
Regulatory liabilities	22			37
Tax loss carryforwards	1			17
Total deferred income tax assets	359			264
Deferred income tax liabilities:
Depreciation and amortization	572			534
Regulatory assets	274			175
Other	9			4
Total deferred income tax liabilities	855			713
Deferred income tax liability, net	$	(496	)	$	(449	)
Classification of net deferred income taxes:
Current deferred income tax asset (1)	$	33		$	—
Current deferred income tax liability (2)	—			(4		)
Noncurrent deferred income tax liability	(529		)	(445		)
	$	(496	)	$	(449	)

(1) Included in Other current assets in the consolidated balance sheets.

(2) Included in Accrued expenses and other current liabilities in the consolidated balance sheets.

Certain reclassifications have been made to the 2010 deferred income tax assets and deferred income tax liabilities presented in the preceding table to conform with the 2011 presentation and include the following: (i) an increase in Depreciation and amortization and a decrease in Regulatory liabilities of $220 million related to asset retirement obligations; (ii) an increase in Price risk management and a decrease in Regulatory liabilities of $74 million related to fair value adjustments; (iii) an increase in Employee benefits and a decrease in Regulatory assets of $73 million related to actuarial adjustments; and (iv) an increase in Regulatory assets and a decrease in Other of $8 million related to reacquired long-term debt.

As of December 31, 2011, PGE had no federal loss carryforwards and state loss carryforwards of less than $1 million, which will expire at various dates from 2016 through 2031. In addition, PGE has federal and state tax credit carryforwards of $42 million and $14 million, respectively, which will expire at various dates from 2012 through 2031.

PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2011 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2010, PGE believed the benefit from state credit carryforwards expiring in 2011 would not be realized and, in recognition of this risk, the Company recorded a valuation allowance of $2 million on the deferred tax assets relating to these state credit carryforwards. During 2011, these state credit carryforwards expired unused. The net change in the valuation allowance for the years ended December 31, 2011 and 2010 were decreases of $2 million and $1 million, respectively.

As of December 31, 2010, the amount of the Company’s unrecognized tax benefit was $2 million, including interest, resulting from a gross increase in a position taken in a prior period. During the year ended December 31, 2010, the Company recognized $1 million in interest and no penalties. During the first quarter of 2011, the

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unrecognized tax benefit of $2 million was recognized as a result of filing for a federal tax accounting method change. As of December 31, 2011, PGE has no unrecognized tax benefits.

PGE files income tax returns in the U.S. federal jurisdiction, the states of Oregon and Montana, and certain local jurisdictions. The Internal Revenue Service (IRS) performed an examination of PGE’s income tax returns for 2007 and 2008 during 2010. This audit closed in the first quarter of 2011, with no material findings. In addition, the IRS commenced examination of the 2006, 2009, and 2010 income tax returns in the fourth quarter of 2011. The Company is not currently under examination by state or local tax authorities.

NOTE 12: STOCK PURCHASE PLANS

Employee Stock Purchase Plan

PGE has an employee stock purchase plan (ESPP), under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. There are two six-month offering periods each year, January 1 through June 30 and July 1 through December 31, during which eligible employees may purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2011, there were 507,594 shares available for future issuance pursuant to the ESPP.

Dividend Reinvestment and Direct Stock Purchase Plan

On April 1, 2011, PGE’s Dividend Reinvestment and Direct Stock Purchase Plan (DRIP) became effective, under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2011, there were 2,496,842 shares available for future issuance pursuant to the DRIP.

NOTE 13: STOCK-BASED COMPENSATION EXPENSE

Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units with time-based vesting conditions (Restricted Stock Units) and performance-based vesting conditions (Performance Stock Units) to non-employee directors, officers and certain key employees. Service requirements generally must be met for stock units to vest. For each grant, the number of Stock Units is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. A total of 4,687,500 shares of common stock were registered for future issuance under the Plan, of which 3,931,204 shares remain available for future issuance as of December 31, 2011.

Restricted Stock Units vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date.

Performance Stock Units vest if performance goals are met at the end of a three-year performance period; such goals include return on equity and regulated asset base growth measures. Vesting of Performance Stock Units is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

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Outstanding Restricted and Performance Stock Units provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. DERs represent an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vest on the same schedule as the stock units. The DERs are settled in cash (for grants to non-employee directors) or shares of PGE common stock valued either at the closing stock price on the vesting date (for Performance Stock Unit grants) or dividend payment date (for all other grants). The cash from the settlement of the DERs for non-employee directors may be deferred under the terms of the Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan.

Restricted and Performance Stock Unit activity is summarized in the following table:

	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2008	360,382		25.04
Granted	243,574		14.95
Forfeited	(4,847	)	24.85
Vested	(176,846	)	23.60
Outstanding as of December 31, 2009	422,263		19.82
Granted	191,469		19.18
Forfeited	(45,081	)	23.45
Vested	(103,223	)	25.78
Outstanding as of December 31, 2010	465,428		17.88
Granted	152,657		23.84
Forfeited	(106,979	)	22.35
Vested	(19,702	)	23.34
Outstanding as of December 31, 2011	491,404		18.54

The number of vested Restricted and Performance Stock Units presented above exceed the number of shares issued for the vesting of restricted and performance stock units on the consolidated statements of equity because, upon vesting, the Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. The total value of Restricted and Performance Stock Units vested during the years ended December 31, 2011, 2010, and 2009 was $1 million, $3 million and $4 million, respectively. The weighted average fair value is measured based on the closing price of PGE common stock on the date of grant. For the years ended December 31, 2011, 2010, and 2009, PGE recorded $4 million, $2 million and $1 million, respectively, of stock-based compensation expense, which is included in Administrative and other expense in the consolidated statements of income. Such amounts differ from those reported in the consolidated statements of equity for Stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The net impact to equity from the income tax payments, partially offset by the issuance of DERs, resulted in a charge to equity of less than $1 million in 2011, 2010, and 2009, which is not included in Administrative and other expenses in the consolidated statements of income.

As of December 31, 2011, unrecognized stock-based compensation expense was $4 million, of which approximately $3 million and $1 million is expected to be expensed in 2012 and 2013, respectively. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the vesting of 121.8%, 117.9%, and 91.1% of awarded Performance Stock Units for 2011, 2010, and 2009, respectively, with an estimated 6% forfeiture rate. No stock-based compensation costs have been capitalized and the plan had no material impact on cash flows for the years ended December 31, 2011, 2010, or 2009.

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NOTE 14: EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Dilutive potential common shares consist of Restricted Stock Units and employee stock purchase plan shares. Unvested Performance Stock Units and related DERs are not included in the computation of dilutive securities because vesting of these instruments is dependent upon the attainment of required criteria over three-year performance periods. For additional information on Performance Stock Units and DERs, see Note 13, Stock-Based Compensation Expense.

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

	Years Ended December 31,
	2011		2010		2009
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	147	$	125	$	95
Denominator (in thousands):
Weighted average common shares outstanding—basic	75,333		75,275		72,790
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	17		16		62
Weighted average common shares outstanding—diluted	75,350		75,291		72,852
Earnings per share—basic and diluted	$	1.95	$	1.66	$	1.31

Basic and diluted earnings per share amounts are calculated based on actual amounts rather than the rounded amounts presented in the table above and on the consolidated statements of income. Accordingly, calculations using the rounded amounts presented for net income and weighted average shares outstanding may yield results that vary from the earnings per share amounts presented in the table above.

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NOTE 15: COMMITMENTS AND GUARANTEES

Commitments

As of December 31, 2011, PGE’s future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):

	Payments Due
	2012		2013		2014		2015		2016		Thereafter		Total
Capital and other purchase commitments	$	58	$	18	$	10	$	10	$	6	$	73	$	175
Purchased power and fuel:
Electricity purchases	129		77		76		76		57		381		796
Capacity contracts	21		21		21		20		19		—		102
Public Utility Districts	7		8		8		8		7		30		68
Natural gas	49		22		22		20		12		11		136
Coal and transportation	25		19		9		—		—		—		53
Operating leases	9		10		9		10		10		196		244
Total	$	298	$	175	$	155	$	144	$	111	$	691	$	1,574

Capital and other purchase commitments—Certain commitments have been made for capital and other purchases for 2012 and beyond. Such commitments include those related to hydro licenses, upgrades to production, distribution and transmission facilities, decommissioning activities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges.

Electricity purchases and Capacity contracts—PGE has power purchase contracts with counterparties, which expire at varying dates through 2036, and power capacity contracts through 2016. As of December 31, 2011, PGE has power sale contracts with counterparties of approximately $13 million in 2012.

Public Utility Districts—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. The Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the Public Utility Districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions):

	Revenue Bonds as of December 31, 2011		PGE Share			Contract Expiration	PGE Cost, including Debt Service
			Output		Capacity		2011		2010		2009
					(in MW)
Priest Rapids and Wanapum	$	917	8.8	%	176	2052	$	14	$	10	$	17
Wells	259		19.4		159	2018	10		7		8
Portland Hydro	11		100.0		36	2017	4		4		4

Under contracts with the public utility districts, PGE has acquired a percentage of the output (Allocation) of Priest Rapids and Wanapum and Wells. The contracts provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage Allocation. For Priest Rapids and Wanapum, PGE would

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be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.

Natural gas—PGE has agreements for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. The Company also has a natural gas storage agreement, which expires in April 2017, for the purpose of fueling the Company’s Port Westward and Beaver generating plants.

Coal and transportation—PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman, which expire at various dates through 2014.

Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities. The majority of the future minimum operating lease payments presented in the table above consist of (i) the corporate headquarters lease, which expires in 2018, but includes renewal period options through 2043, and (ii) the Port of St. Helens land lease, where PGE’s Beaver and Port Westward generating plants operate, which expires in 2096. Rent expense was $9 million in 2011 and in 2010, and $7 million in 2009.

The future minimum operating lease payments presented is net of sublease income of: $3 million in 2012; $2 million in 2013, 2014, and 2015; and $1 million in 2016. Sublease income was $3 million in 2011, 2010, and 2009.

Guarantees

PGE entered into a sale transaction in 1985 in which it sold an undivided 15% interest in Boardman and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly the Boardman Assets) to an unrelated third party (Purchaser). The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. Concurrently, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from Boardman and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The P&T Agreements expire on December 31, 2013. The payments by the Utility under the P&T Agreements exceed the payments to be made by the Lessee to the Purchaser under the lease. In exchange for PGE undertaking certain obligations of the Lessee under the lease, the Lessee reassigned to PGE certain rights, including the excess payments, under the P&T Agreements. However, in the event that the Utility defaults on the payments it owes under the P&T Agreements, PGE may be required to pay the damages owed by the Lessee to the Purchaser under the lease. Assuming no recovery from the Utility and no reduction in damages from mitigating sales or leases related to the Boardman Assets and P&T Agreements, the maximum amount that would be owed by PGE in 2012 is approximately $74 million. Management believes that circumstances that could result in such amount, or any lesser amount, being owed by the Company are remote.

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 2011, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.

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NOTE 16: VARIABLE INTEREST ENTITIES

PGE has determined that it is the primary beneficiary of three VIEs and, therefore, consolidates the VIEs within the Company’s consolidated financial statements. All three arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties and selling the energy generated by the facilities. The Company is the Managing Member and a financial institution is the Investor Member in each of the Limited Liability Companies (LLCs), holding equity interests of less than 1% and more than 99%, respectively, in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

Determining whether PGE is the primary beneficiary of a VIE is complex, subjective and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining it is the primary beneficiary of these LLCs include the following: (i) PGE has the experience to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and, therefore, PGE has control over the most significant activities of the LLCs; (ii) PGE expects to own 100% of the LLCs shortly after five years have elapsed, at which time the facilities will have approximately 75% of their estimated useful life remaining; and (iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of the expected losses of the LLCs.

During 2010 and 2009, impairment losses of $4 million and $5 million, respectively, were recognized on the photovoltaic solar power facilities held by the LLCs and classified in Depreciation and amortization expense in PGE’s consolidated statements of income. Based on PGE’s intent to ultimately acquire 100% of the LLCs and the fact that the capitalized cost of the photovoltaic solar power facilities exceeded the undiscounted cash flows of the respective facility over its estimated useful life, impairment analyses were performed. The impairment losses were equal to the excess of the carrying amounts over the estimated fair values of the photovoltaic solar power facilities. Estimated fair values were determined using the discounted cash flow method, assuming a discount rate (after taxes) of approximately 7%, which is PGE’s allowed rate of return, and estimated useful lives ranging from 20 to 25 years. The new cost basis of the photovoltaic solar power facilities are amortized over their remaining estimated useful lives. The valuation technique used to measure fair value of the photovoltaic solar power facilities at the impairment date is considered Level 3 in the fair value hierarchy, as described in Note 4, Fair Value of Financial Instruments.

As noted above, PGE has consolidated the VIEs even though it has less than a 1% ownership interest in the LLCs. The participating members are allocated their proportionate share of the LLCs net losses based on the respective members’ ownership percent. Accordingly, the majority of the impairment losses are attributable to the noncontrolling interests through the Net losses attributable to noncontrolling interests in PGE’s consolidated statements of income for the years ended December 31, 2010 and 2009.

Included in PGE’s consolidated balance sheets are LLC net assets as follows (in millions):

	As of December 31,
	2011		2010
Cash and cash equivalents	$	1	$	1
Accounts receivable	—		4
Electric utility plant, net	5		5

These assets can only be used to settle the obligations of the consolidated VIEs.

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NOTE 17: JOINTLY-OWNED PLANT

PGE has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating owner is responsible for financing its share of construction, operating and leasing costs. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.

As of December 31, 2011, PGE had the following investments in jointly-owned plant (dollars in millions):

	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	65.00	%	1980			$	467	$	292	$	2
Colstrip	20.00		1986			507		326		2
Pelton/Round Butte	66.67		1958	/	1964	206		46		11
Total						$	1,180	$	664	$	15

* Excludes asset retirement obligations and accumulated asset retirement removal costs.

NOTE 18: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which (i) the damages sought are indeterminate or the basis for the damages claimed is not clear, (ii) the proceedings are in the early stages, (iii) discovery is not complete, (iv) the matters involve novel or unsettled legal theories, (v) there are significant facts in dispute, (vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants), or (vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

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Trojan Investment Recovery

Regulatory Proceedings. In 1993, PGE closed Trojan and sought full recovery of, and a return on, its Trojan costs in a general rate case filing with the OPUC. The OPUC issued a general rate order that granted the Company recovery of, and a return on, 87% of its remaining investment in Trojan.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 1998, the Oregon Court of Appeals upheld the OPUC’s order authorizing PGE’s recovery of the Trojan investment, but held that the OPUC did not have the authority to allow PGE to recover a return on the Trojan investment and remanded the case to the OPUC for reconsideration.

In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

The OPUC then issued an order in 2008 that required PGE to refund $15.4 million, plus interest at 9.6% from September 30, 2000, to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The Company recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below have separately appealed the 2008 Order to the Oregon Court of Appeals. Oral arguments were made on February 3, 2012 and a decision by the Oregon Court of Appeals remains pending.

Class Actions. In a separate legal proceeding, two lawsuits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers. The class action lawsuits seek damages of $260 million, plus interest, as a result of PGE’s inclusion, in prices charged to customers, of a return on its investment of Trojan.

In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1, 1995 through October 1, 2000.

The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court.

Because the above matters involve unsettled legal theories and have a broad range of potential outcomes, management cannot estimate a range of potential loss. Management believes, however, that these matters will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

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Pacific Northwest Refund Proceeding

In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. In 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. Parties appealed various aspects of the FERC order to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

In August 2007, the Ninth Circuit issued its decision, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to: (i) address the new market manipulation evidence in detail and account for the evidence 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. After denying requests for rehearing, the Ninth Circuit in April 2009 issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC.

In October, 2011, the FERC issued an Order on Remand, establishing an evidentiary hearing to determine whether any seller had engaged in unlawful market activity in the Pacific Northwest spot markets during the December 25, 2000 through June 20, 2001 period by violating specific contracts or tariffs, and, if so, whether a direct connection existed between the alleged unlawful conduct and the rate charged under the applicable contract. FERC held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome before a refund could be ordered. FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Certain parties claiming refunds filed requests for rehearing of the Order on Remand, contesting, among other things, the applicable refund period reflected in the Order, the use of the Mobile-Sierra standard, any restraints in the Order on the type of evidence that could be introduced in the hearing, and the lack of market-wide remedy. The rehearing requests remain pending.

In its October 2011 Order on Remand, the FERC held the hearing procedures in abeyance pending the results of settlement discussions, which it ordered be convened before a FERC settlement judge. The settlement proceedings are ongoing.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement (including CERS) as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

Management cannot predict whether the FERC will order refunds in the Pacific Northwest Refund proceeding, which contracts would be subject to refunds, or how such refunds, if any, would be calculated. Accordingly, management cannot estimate a range of potential loss. Management believes, however, that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on PGE’s results of operations and cash flows in future reporting periods.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

EPA Investigation of 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 National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river.

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

In January 2008, the EPA requested information from various parties, including PGE, concerning properties in or near the 5.7 mile segment of the river being examined in the RI/FS, as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

The EPA will determine the boundaries of the site at the conclusion of the RI/FS in a Record of Decision in which it will document its findings and select a preferred cleanup alternative. The EPA is not expected to issue the Record of Decision until 2014.

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

EPA Investigation of Harbor Oil

Harbor Oil, Inc. operated an oil reprocessing business on a site located in north Portland (Harbor Oil), until about 1999. Subsequently, other companies have continued to conduct operations on the site. Until 2003, PGE contracted with the operators of the site to provide used oil from the Company’s power plants and electrical distribution system to the operators for use in their reprocessing business. Other entities continue to utilize Harbor Oil for the reprocessing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. In 2003, the EPA included the Harbor Oil site on the National Priority List as a federal Superfund site.

PGE received a Notice from the EPA in 2005, in which the Company was named as one of fourteen PRPs with respect to Harbor Oil. In 2007, an AOC was signed by the EPA and six other parties, including PGE, to implement an RI/FS at Harbor Oil. In 2011, the final draft of the remedial investigation report was submitted to the EPA, which has yet to issue a response.

Sufficient information is currently not available to determine the total cost of investigation and remediation of Harbor Oil or the liability of the PRPs, including PGE. Accordingly, management cannot estimate a range of potential loss. Management believes, however, that the outcome of this matter will not have a material impact on the financial condition of the Company, but may have a material impact on PGE’s results of operations and cash flows in future reporting periods.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

Revenue Bonds

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow. In connection with the repurchase, PGE paid the $5.8 million repurchase price to Lehman Brothers Inc. (Lehman) as remarketing agent for the Bonds, who in turn paid off the beneficial owner of the Bonds. As a result of the payment, PGE became the beneficial owner of the Bonds and requested that Lehman safe-keep the Bonds in Lehman’s Depository Trust Company participant account until such time as the Bonds could be remarketed. After repurchase of the Bonds, PGE removed the liability for the Bonds from its financial statements.

In September 2008, Lehman filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PGE subsequently filed a claim for return of the Bonds from Lehman. In November 2009, the trustee appointed to liquidate the assets of Lehman (Trustee) allowed PGE’s claim as a net equity claim for securities. At the time, PGE believed it would receive back the entire amount of the Bonds at some point during the bankruptcy proceedings.

It is not certain that the Company will receive the full amount of the Bonds but could, along with other claimants, potentially receive a pro-rata share of certain assets. The timing and extent of distributions on claims are subject to the ultimate disposition of numerous claims in the proceedings and certain major contingencies which the Trustee must resolve. PGE cannot currently estimate how much of the value of the Bonds will ultimately be returned to the Company or the timing of the distribution from Lehman. Management does not expect the outcome of this matter to have a material impact on the Company’s financial condition, but it may have a material impact on PGE’s results of operations and cash flows in a future interim reporting period.

Other Matters

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

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QUARTERLY FINANCIAL DATA

(Unaudited)

	Quarter Ended
	March 31		June 30		September 30		December 31
	(In millions, except per share amounts)
2011
Revenues, net	$	484	$	411	$	439	$	479
Income from operations	115		57		68		69
Net income	69		22		27		29
Net income attributable to Portland General Electric Company	69		22		27		29
Earnings per share—basic and diluted (1)	0.92		0.29		0.36		0.38
2010
Revenues, net (2)	$	449	$	415	$	464	$	455
Income from operations (2)	61		57		90		59
Net income (2)	27		24		48		22
Net income attributable to Portland General Electric Company (2)	27		24		49		25
Earnings per share—basic and diluted (1) (2)	0.36		0.32		0.65		0.34

(1) Earnings per share are calculated independently for each period presented. Accordingly, the sum of the quarterly earnings per share amounts may not equal the total for the year.

(2) Revenues for the fourth quarter of 2010 include the reversal of an estimated collection from customers that had been recorded as of September 30, 2010 in the amount of $24 million related to the regulatory treatment of income taxes (SB 408) for 2010.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A.     CONTROLS AND PROCEDURES.

(a)     Disclosure Controls and Procedures

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, the information relating to the Company (including its consolidated subsidiaries) required to be disclosed by the Company in the reports that it files or submits under the Exchange Act and are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b)     Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of the end of the period covered by this report pursuant to Rule 13a-15(c) under the Exchange Act. Management’s assessment was based on the framework established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management has concluded that, as of December 31, 2011, the Company’s internal control over financial reporting is effective.

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The Company’s internal control over financial reporting, as of December 31, 2011, has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audits the Company’s consolidated financial statements, as stated in their report included in Item 8.—“Financial Statements and Supplementary Data,” which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2011.

(c)     Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.     OTHER INFORMATION.

None.

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PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required by Item 10 is incorporated herein by reference to the relevant information under the captions “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance,” “Proposal 1: Election of Directors—The Board of Directors,” and “Executive Officers” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 23, 2012.

ITEM 11.     EXECUTIVE COMPENSATION.

The information required by Item 11 is incorporated herein by reference to the relevant information under the captions “Corporate Governance—Non-Employee Director Compensation,” “Corporate Governance—Compensation Committee Interlocks and Insider Participation,” “Compensation and Human Resources Committee Report,” “Compensation Discussion and Analysis,” and “Executive Compensation Tables” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 23, 2012.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The information required by Item 12 is incorporated herein by reference to the relevant information under the captions “Security Ownership of Certain Beneficial Owners, Directors and Executive Officers” and “Equity Compensation Plans,” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 23, 2012.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

The information required by Item 13 is incorporated herein by reference to the relevant information under the caption “Corporate Governance” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 23, 2012.

ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by Item 14 is incorporated herein by reference to the relevant information under the captions “Principal Accountant Fees and Services” and “Pre-Approval Policy for Independent Auditor Services” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 23, 2012.

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PART IV

ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)    Financial Statements and Schedules

The financial statements are set forth under Item 8 of this Annual Report on Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.

(b)    Exhibit Listing

Exhibit Number	Description
(3)	Articles of Incorporation and Bylaws
3.1*	Second Amended and Restated Articles of Incorporation of Portland General Electric Company (Form 10-Q filed August 3, 2009, Exhibit 3.1).
3.2*	Ninth Amended and Restated Bylaws of Portland General Electric Company (Form 8-K filed October 27, 2011, Exhibit 3.1).
(4)	Instruments defining the rights of security holders, including indentures
4.1*	Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945 (Form 8, Amendment No. 1 dated June 14, 1965).
4.2*	Fortieth Supplemental Indenture dated October 1, 1990 (Form 10-K for the year ended December 31, 1990, Exhibit 4) (File No. 1-05532-99).
4.3*	Fifty-sixth Supplemental Indenture dated May 1, 2006 (Form 8-K filed May 25, 2006, Exhibit 4.1).
4.4*	Fifty-seventh Supplemental Indenture dated December 1, 2006 (Form 8-K filed December 22, 2006, Exhibit 4.1).
4.5*	Fifty-eighth Supplemental Indenture dated April 1, 2007 (Form 8-K filed April 12, 2007, Exhibit 4.1).
4.6*	Fifty-ninth Supplemental Indenture dated October 1, 2007 (Form 8-K filed October 5, 2007, Exhibit 4.1).
4.7*	Sixtieth Supplemental Indenture dated April 1, 2008 (Form 8-K filed April 17, 2008, Exhibit 4.1).
4.8*	Sixty-first Supplemental Indenture dated January 15, 2009 (Form 8-K filed January 16, 2009, Exhibit 4.1).
4.9*	Sixty-second Supplemental Indenture dated April 1, 2009 (Form 8-K filed April 16, 2009, Exhibit 4.1).
4.10*	Sixty-third Supplemental Indenture dated November 1, 2009 (Form 8-K filed November 4, 2009, Exhibit 4.1).
(10)	Material Contracts
10.1*	Separation Agreement between Enron Corp. and Portland General Electric Company dated April 3, 2006 (Form 8-K filed April 3, 2006, Exhibit 10.1).
10.2*	Five Year Credit Agreement dated May 27, 2005, between Portland General Electric Company, JP Morgan Chase Bank, N.A., as Administrative Agent, and a group of lenders (Form 8-K filed June 2, 2005, Exhibit 4.1).
10.3	Credit Agreement dated December 8, 2011, between Portland General Electric Company, Bank of America, N.A., as Administrative Agent, Barclays Capital, as Syndication Agent, and a group of lenders.

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Exhibit Number	Description
Exhibits 10.4 through 10.15 were filed in connection with the Company’s 1985 Boardman/Intertie Sale:
10.4*	Long-term Power Sale Agreement dated November 5, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.5*	Long-term Transmission Service Agreement dated November 5, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 001-05532-99).
10.6*	Participation Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.7*	Lease Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.8*	PGE-Lessee Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.9*	Asset Sales Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.10*	Bargain and Sale Deed, Bill of Sale, and Grant of Easements and Licenses dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.11*	Supplemental Bill of Sale dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.12*	Trust Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.13*	Tax Indemnification Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.14*	Trust Indenture, Mortgage and Security Agreement dated December 30, 1985 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.15*	Restated and Amended Trust Indenture, Mortgage and Security Agreement dated February 27, 1986 (Form 10-K for the year ended December 31, 1985, Exhibit 10) (File No. 1-05532).
10.16*	Portland General Electric Company Severance Pay Plan for Executive Employees dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.1). +
10.17*	Portland General Electric Company Outplacement Assistance Plan dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.2). +
10.18*	Portland General Electric Company 2005 Management Deferred Compensation Plan dated January 1, 2005 (Form 10-K filed March 11, 2005, Exhibit 10.18). +
10.19*	Portland General Electric Company Management Deferred Compensation Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.1). +
10.20*	Portland General Electric Company Supplemental Executive Retirement Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.2). +
10.21*	Portland General Electric Company Senior Officers’ Life Insurance Benefit Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.3). +
10.22*	Portland General Electric Company Umbrella Trust for Management dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.4). +
10.23*	Portland General Electric Company 2006 Stock Incentive Plan, as amended (Form 10-K filed February 27, 2008, Exhibit 10.23). +

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Exhibit Number	Description
10.24*	Portland General Electric Company 2006 Annual Cash Incentive Master Plan (Form 8-K filed March 17, 2006, Exhibit 10.1). +
10.25*	Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan (Form 8-K filed May 17, 2006, Exhibit 10.1). +
10.26*	Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (Form 8-K filed February 26, 2008, Exhibit 10.1). +
10.27*	Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters (Form 8-K filed December 24, 2009, Exhibit 10.1). +
10.28*	Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters for Officers and Key Employees (Form 8-K filed February 19, 2010, Exhibit 10.1). +
10.29*	Form of Directors’ Restricted Stock Unit Agreement (Form 8-K filed July 14, 2006, Exhibit 10.1). +
10.30*	Form of Officers’ and Key Employees’ Performance Stock Unit Agreement (Form 8-K filed March 13, 2008, Exhibit 10.1). +
10.31*	Employment Agreement dated and effective May 6, 2008 between Stephen M. Quennoz and Portland General Electric Company (Form 10-Q filed May 7, 2008, Exhibit 10.3). +
(12)	Statements Re Computation of Ratios
12.1	Computation of Ratio of Earnings to Fixed Charges.
(23)	Consents of Experts and Counsel
23.1	Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP.
(31)	Rule 13a-14(a)/15d-14(a) Certifications
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
(32)	Section 1350 Certifications
32.1	Certifications of Chief Executive Officer and Chief Financial Officer.
(101)	Interactive Data File
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema Document.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document.

* Incorporated by reference as indicated.

+ Indicates a management contract or compensatory plan or arrangement.

** In accordance with Regulation S-T, the XBRL-related information in Exhibit 101 to this Annual Report on Form 10-K shall be deemed“furnished” and not “filed.”

Certain instruments defining the rights of holders of other long-term debt of the Company are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

Upon written request to Investor Relations, Portland General Electric Company, 121 SW Salmon Street, Portland, Oregon 97204, PGE will furnish shareholders with a copy of any Exhibit upon payment of reasonable fees for reproduction costs incurred in furnishing requested Exhibits.

125

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 23, 2012.

PORTLAND GENERAL ELECTRIC COMPANY
By:	/s/     JAMES J. PIRO
	James J. Piro
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 23, 2012.

Signature	Title
/s/    JAMES J. PIRO	President, Chief Executive Officer, and Director (principal executive officer)
James J. Piro
/s/     MARIA M. POPE	Senior Vice President, Finance, Chief Financial Officer, and Treasurer (principal financial and accounting officer)
Maria M. Pope
/s/    JOHN W. BALLANTINE	Director
John W. Ballantine
/s/    RODNEY L. BROWN, JR.	Director
Rodney L. Brown, Jr.
/s/    DAVID A. DIETZLER	Director
David A. Dietzler
/s/    KIRBY A. DYESS	Director
Kirby A. Dyess
/s/     PEGGY Y. FOWLER	Director
Peggy Y. Fowler
/s/    MARK B. GANZ	Director
Mark B. Ganz
/s/    CORBIN A. MCNEILL, JR.	Director
Corbin A. McNeill, Jr.
/s/    NEIL J. NELSON	Director
Neil J. Nelson
/s/    M. LEE PELTON	Director
M. Lee Pelton
/s/    ROBERT T. F. REID	Director
Robert T. F. Reid

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