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•	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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•	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:

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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

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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.”

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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.

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*	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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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.

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.

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.

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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.

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.

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•	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.

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•	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.”

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•	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.

•	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.

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•	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.

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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.

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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.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS.

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(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.

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•	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.

•	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.

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

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

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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.

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*	In thousands of MWh.

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•	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.

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•	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.

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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.

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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.

•	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.

•	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.

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•	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;

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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.

•	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;

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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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•	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.

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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.

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•	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.

•	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).

•	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;

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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.

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•	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.

•	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;

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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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•	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.

•	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.

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•	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

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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.

•	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.

•	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).

•	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

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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.”

•	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.

•	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.

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(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.

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•	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.

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•	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.

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(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.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

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

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

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

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(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.

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•	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.

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

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*	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.

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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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*	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.

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•	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.

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(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.

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

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(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.

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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

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*	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.”

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SCHEDULE 1	PRICING SCHEDULE

SCHEDULE 2	COMMITMENTS

SCHEDULE 3	INDEBTEDNESS EXCEPTIONS

SCHEDULE 5.2	LITIGATION

SCHEDULE 5.9	SUBSIDIARIES

SCHEDULE 13.1	NOTICE ADDRESSES

EXHIBIT A	FORM OF ASSIGNMENT AGREEMENT

EXHIBIT B	FORM OF OPINION OF BORROWER'S COUNSEL

EXHIBIT C	FORM OF COMPLIANCE CERTIFICATE

EXHIBIT D	FORM OF NOTE

EXHIBIT E	FORM OF BORROWING NOTICE

EXHIBIT F	FORM OF CONVERSION/CONTINUATION NOTICE

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1.	I have reviewed this Annual Report on Form 10-K of Portland General Electric Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

1.	I have reviewed this Annual Report on Form 10-K of Portland General Electric Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.