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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 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. In February 2013, PGE filed a general rate case with a 2014 test year (2014 General Rate Case). For additional information, see the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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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 Net Variable Power Costs (NVPC), which consist of the cost of purchased power and fuel used in generation (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 expected operating conditions for thermal generating plants. An initial NVPC forecast, submitted to the OPUC by April 1st each year, is updated during such year and finalized in November of the same year. 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 (baseline NVPC) 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 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. The deadband range is fixed at $15 million below, to $30 million above, baseline NVPC. 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. For additional information, see the Results of Operations section in 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 met the 2011 requirement and expects to have sufficient resources to meet the 2015 requirements with additional resources included in its most recent IRP. The Act also allows Renewable Energy Credits, resulting from energy generated from qualified renewable resources placed in service after January 1, 1995 and certified low impact hydroelectric power resources, to be used to meet the Company’s RPS compliance obligation. For additional information, see the Power Supply section in this Item 1.

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(1)	Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 195 MWa to 245 MWa, dependent upon river flows.

(2)	Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 135 MWa to 180 MWa, 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 (Colstrip), which is operated by a third party. These two coal-fired generating facilities provided approximately 19% of the Company’s total retail load requirement in 2012, compared with 21% in 2011 and 26% in 2010. The Company’s three natural gas-fired generating facilities, Port Westward, Beaver, and Coyote Springs, provided approximately 15% of its total retail load requirement in 2012, compared with 11% in 2011 and 24% in 2010.

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 ranging from 2035 to 2055. Although these plants have a combined capacity of 489 MW, actual energy received is dependent upon river flows. Energy from these resources provided 10% of the Company’s total retail load requirement in 2012, 2011, and 2010, with availability of 99% in 2012, compared with 100% in 2011 and 99% in 2010. 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 nameplate capacity of approximately 450 MW. It was completed and placed in service in three phases between December 2007 and August 2010. The energy from Biglow Canyon provided 6% of the Company’s total retail load requirement in both 2012 and 2011, and 4% in 2010. Availability for Biglow Canyon was 98% in 2012, compared with 97% in 2011 and 96% in 2010. The expected energy from wind resources differs from the nameplate capacity and is expected to range from 135 MWa to 180 MWa 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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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. The contract representing 159 MW of capacity expires in 2018 and the contract representing 181 MW of capacity expires in 2052. Although the projects currently provide a total of 340 MW of capacity, actual energy received is dependent upon river flows.

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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. The Tribes may elect to sell its output to another party with a one year notice to PGE.

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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;

•	Approximately 100 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 service territory. For additional information on the Cascade Crossing Transmission Project (Cascade Crossing), see “Capital Requirements and Financing” in the Overview section contained in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations”;

•	New natural gas generation facilities to help meet additional base load requirements estimated at 300 to 500 MW;

•	New natural gas generation facilities to help meet peak capacity requirements estimated at up to 200 MW;

•	Seasonal peaking resources, consisting of 200 MW of bi-seasonal (winter and summer) peaking supply and 150 MW of winter-only peaking supply; and

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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 “Capital Requirements” in the Liquidity and Capital Resources 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 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 emissions standard for new gas and coal fired electric generating units was proposed in April 2012 and is

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The State of Oregon has established a non-binding policy guideline that sets a goal to reduce GHG emissions to 10% below 1990 levels by 2020. Although the guideline does not mandate reductions by any specific entity nor include penalties for failure to meet the goal, the Company is required to report to the DEQ the amount of GHG emissions produced along with the total amount of energy produced or purchased by PGE for consumption in Oregon.

•	During 2012, the Company submitted the first required GHG emissions report applicable to its transmission and distribution system to both the EPA and the DEQ.

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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, a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border. The California-Oregon AC Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

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

•	200 MW of firm BPA transmission from mid-Columbia projects in Washington to the northern end of the California-Oregon AC Intertie, near John Day, Oregon, and 100 MW to the northern end of the Pacific DC Intertie, near Celilo, Oregon.

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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 proceedings, 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;

•	economic conditions that result in 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 could affect customer demand for power and 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;

•	the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, which could result in the Company’s inability to recover project costs;

•	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;

•	capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper, 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;

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•	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 fuels, including natural gas, coal and oil, and the impact of such changes on the Company’s power costs, and changes in the availability and price of wholesale power;

•	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;

•	declines in the fair value of equity securities held for the 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 or information technology systems, or result in the release of confidential customer and proprietary information;

•	employee workforce factors, including a significant number of employees approaching retirement, potential strikes, work stoppages, and transitions in senior management;

•	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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•	For 2012, actual NVPC was $17 million below baseline NVPC, and $2 million above the lower deadband threshold, resulting in a potential refund due to customers. However, based on results of the regulated earnings test, no estimated refund to customers was recorded as of December 31, 2012.

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For 2011, actual NVPC was $34 million below baseline NVPC, which is $19 million above the lower deadband threshold, resulting in a potential refund to customers. As of December 31, 2011, PGE recorded an estimated refund to customers of approximately $10 million, which was reduced from the potential refund based on the application of the regulated earnings test. During 2012, the estimated refund to customers was further reduced to $6 million after the application of an updated regulated earnings test.

•	For 2010, actual NVPC was approximately $12 million below baseline NVPC, but within the established deadband range; accordingly, no refund to customers was recorded as of December 31, 2010.

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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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•	An $18 million increase as a result of credits provided to customers in 2011 (offset in Depreciation and amortization), with no comparable refund in 2012. The customer credits were the result of tax credits the Company had accumulated over several years in relation to the Independent Spent Fuel Storage Installation located at the former Trojan site;

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A $14 million increase related to the PCAM, as an estimated refund to customers in the amount of $10 million was recorded in 2011 compared with a $4 million reduction in the estimated PCAM refund for the 2011 year recorded in 2012. No estimated refund or collection was recorded under the PCAM related to the 2012 year. For further discussion of the PCAM, see “Purchased power and fuel expense,” below; and

•	A $17 million increase resulting from supplemental tariffs and several small regulatory items, which are primarily offset in other line items in the statements of income and thus have no effect on income. The largest contributors amounted to $5 million for the recovery of costs under the solar Feed-In Tariff and $3 million for the recovery of expenses related to the Trojan refund; offset by

•	A $34 million decrease related to the volume of retail energy sold and delivered. Residential volumes were down 3%, primarily driven by warmer temperatures during the heating season in 2012. Deliveries to industrial customers were up 2% due largely to increased demand from the high technology sector; and

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A $15 million decrease related to changes in the average retail price, resulting primarily from tariff changes effective January 1, 2012 as authorized by the OPUC including lower anticipated power costs included in the AUT partially offset by a $7 million net annual increase related to the tariff for recovery of Boardman over a shortened operating life. Incremental revenues under the Boardman tariff for the full year 2012 were $14 million compared with $7 million for the last six months of 2011.

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•	A $14 million decrease related to a 22% decline in the average wholesale price the Company received, driven by lower electricity market prices due to the relatively low price of natural gas and a surplus of hydro generation in the region; partially offset by

•	A $3 million increase due to a 5% increase in wholesale energy sales volume.

•	A $49 million decrease in the cost of purchased power, consisting of $30 million related to a 6% decrease in average cost and $19 million related to a 4% decrease in purchases. The decrease in average cost was primarily driven by lower wholesale power prices resulting from favorable hydro conditions and low natural gas prices; partially offset by

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A $19 million increase in the cost of generation, primarily due to an increase in the proportion of power provided by the Company’s natural gas-fired generating plants, meeting 15% of PGE’s retail load requirement in 2012 compared to 11% in 2011. Energy from natural gas-fired generation increased 35% and the average cost of such generation decreased 16% on lower natural gas prices. The average cost of power generated increased 5% in 2012 compared to 2011.

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•	A $4 million increase due to higher maintenance costs of the Company’s generating plants and distribution system;

•	A $3 million increase due to an insurance recovery related to the Selective Water Withdrawal project recorded in 2011; and

•	A $3 million increase due to higher delivery system labor costs.

•	A $6 million decrease due to expenses related to information technology upgrades in 2011;

•	A $3 million decrease related to higher write-offs of uncollectible customer accounts in 2011;

•	A $2 million decrease in compensation expense primarily due to lower incentive compensation in 2012; partially offset by

•	A $7 million increase in employee pension expenses resulting from a lower discount rate and lower return on pension trust assets; and

•	A $3 million increase due to the amortization of deferred expenses related to the Trojan refund (offset in Revenues).

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•	An $18 million increase related to the amortization of customer refunds for the ISFSI tax credits in 2011(offset in Revenues);

•	A $13 million increase in depreciation expense related to a shorter operating life for the Boardman plant (effective July 2011 and offset in Revenues), and other capital additions including emissions control retrofits at the Boardman plant;

•	A $5 million increase in amortization related to the Solar Feed-In Tariff (offset in Revenues); partially offset by

•	A $15 million decrease related to the 2012 deferral of costs related to four capital projects as approved in the 2011 General Rate Case.

•	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;

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•	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 (Senate Bill 408) primarily due to an adjustment recorded in 2010 that pertained to the 2009 liability, which was included in Other accrued revenues. Senate Bill 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.

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

•	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.

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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

•	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

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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 customers 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 interests through the Net loss attributable to the noncontrolling interest. 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”; partially offset by

•	A $21 million increase in depreciation related to the August 2010 completion of the third and final phase of Biglow Canyon wind farm, 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.

•	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 third and final phase of Biglow Canyon wind farm; 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.

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

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•	A $400 million syndicated credit facility, which is scheduled to terminate in November 2017; and

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•	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, 2012.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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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.

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

(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)	Includes $1 million of realized losses, net.

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

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

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

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(1)	As of December 31, 2012.

(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)	Recovery period not yet determined.

(6)	Of the total other unamortized regulatory asset balances, a return is recorded on $15 million and $21 million as of December 31, 2012 and 2011, respectively.

(7)	Included in rate base for ratemaking purposes.

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

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•	A $400 million syndicated credit facility, which is scheduled to terminate in November 2017; and

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

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

•	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; and

•	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.

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

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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.

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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.

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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.