10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2014

OR

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

For the Transition period from to

Commission File Number 001-05532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

121 S.W. Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  [x]    No  [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [x]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

As of June 30, 2014, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $2,699,904,749. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 10, 2015, there were 78,228,827shares of common stock outstanding.

Documents Incorporated by Reference

Part III, Items 10 - 14 Portions of Portland General Electric Company’s definitive proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 6, 2015.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2014

TABLE OF CONTENTS

Definitions		4
	PART I
Item 1.	Business.	5
Item 1A.	Risk Factors.	23
Item 1B.	Unresolved Staff Comments.	29
Item 2.	Properties.	30
Item 3.	Legal Proceedings.	31
Item 4.	Mine Safety Disclosures.	34
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	35
Item 6.	Selected Financial Data.	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	59
Item 8.	Financial Statements and Supplementary Data.	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	119
Item 9A.	Controls and Procedures.	119
Item 9B.	Other Information.	119
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	120
Item 11.	Executive Compensation.	120
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	120
Item 14.	Principal Accounting Fees and Services.	120
	PART IV
Item 15.	Exhibits, Financial Statement Schedules.	121
	SIGNATURES	124

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DEFINITIONS

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

Abbreviation or Acronym	Definition
AFDC	Allowance for funds used during construction
ARO	Asset retirement obligation
AUT	Annual Power Cost Update Tariff
Beaver	Beaver natural gas-fired generating plant
Biglow Canyon	Biglow Canyon Wind Farm
Boardman	Boardman coal-fired generating plant
BPA	Bonneville Power Administration
CAA	Clean Air Act
Carty	Carty Generating Station natural gas-fired generating plant
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
Coyote Springs	Coyote Springs Unit 1 natural gas-fired generating plant
CWIP	Construction work-in-progress
Dth	Decatherm = 10 therms = 1,000 cubic feet of natural gas
DEQ	Oregon Department of Environmental Quality
EFSA	Equity forward sale agreement
EPA	United States Environmental Protection Agency
ESS	Electricity Service Supplier
FERC	Federal Energy Regulatory Commission
FMB	First Mortgage Bond
GRC	General Rate Case for a specified test year
IRP	Integrated Resource Plan
ISFSI	Independent Spent Fuel Storage Installation
kV	Kilovolt = one thousand volts of electricity
Moody’s	Moody’s Investors Service
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hours
NRC	Nuclear Regulatory Commission
NVPC	Net Variable Power Costs
OATT	Open Access Transmission Tariff
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
PW1	Port Westward Unit 1 natural gas-fired generating plant
PW2	Port Westward Unit 2 natural gas-fired flexible capacity generating plant
RPS	Renewable Portfolio Standard
S&P	Standard & Poor’s Ratings Services
SEC	United States Securities and Exchange Commission
Trojan	Trojan nuclear power plant
Tucannon River	Tucannon River Wind Farm
USDOE	United States Department of Energy

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PART I

ITEM 1.     BUSINESS.

General

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

PGE’s state-approved service area allocation of approximately 4,000 square miles is located entirely within Oregon and includes 52 incorporated cities, of which Portland and Salem are the largest. The Company estimates that at the end of 2014 its service area population was 1.8 million, comprising approximately 46% of the state’s population. During 2014, the Company added 6,203 customers and as of December 31, 2014, served a total of 842,273 retail customers.

PGE had 2,600 employees as of December 31, 2014, with 780 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 743 and 37 employees and expire in February 2016 and August 2017, respectively.

Available Information

PGE’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available and may be accessed free of charge through the Investors section of the Company’s website at PortlandGeneral.com as soon as reasonably practicable after the reports are electronically filed with, or furnished to, the United States Securities and Exchange Commission (SEC). It is not intended that PGE’s website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K. Information may also be obtained via the SEC website at sec.gov.

Regulation

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

Federal Regulation

Several federal agencies, including the Federal Energy Regulatory Commission (FERC), the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), and the Nuclear Regulatory Commission (NRC) have regulatory authority over certain of PGE’s operations and activities.

FERC Regulation

PGE is a “licensee,” a “public utility,” and a “user, owner and operator of the bulk power system,” as defined in the Federal Power Act. As such, the Company is subject to regulation by the FERC in matters related to wholesale

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energy activities, transmission services, reliability and cyber security standards, natural gas pipelines, hydroelectric projects, accounting policies and practices, short-term debt issuances, and certain other matters.

Wholesale Energy—PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales. Re-authorization for continued use of such rates requires the filing of triennial market power studies with the FERC. The Company will file its next updated triennial market power study in 2016.

PGE also has reporting requirements to the FERC for any change in status that departs from the characteristics that the FERC relied upon in authorizing sales at market-based rates, including increases in net generation capacity. Pursuant to this requirement, PGE expects to file an update in mid-February 2015 to address the recent addition of generation capacity resulting from the Tucannon River Wind Farm (Tucannon River) and Port Westward Unit 2 natural gas-fired generating plant (PW2) and other minor changes in merchant transmission contracts. The Company expects the filing to demonstrate that PGE continues to satisfy the FERC’s requirements for market-based rate authority.

Transmission—PGE offers transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates and terms and conditions of service, as filed with and approved by the FERC. As required by the OATT, PGE provides information regarding its transmission business on its Open Access Same-time Information System, also known as OASIS. As of December 31, 2014, PGE owned 1,162 circuit miles of transmission lines. For additional information, see the Transmission and Distribution section in this Item 1. and in Item 2.—“Properties.”

Reliability and Cyber Security Standards—Pursuant to the Energy Policy Act of 2005, the FERC has adopted mandatory reliability standards for owners, users and operators of the bulk power system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of these standards. These standards include Critical Infrastructure Protection standards, a set of cyber security standards that provide a framework to identify and protect critical cyber assets used to support reliable operation of the bulk power system.

Pipeline—The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide the FERC authority in matters related to the construction, operation, extension, enlargement, safety, and abandonment of jurisdictional interstate natural gas pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority as the Company has a 79.5% ownership interest in, and is the operator of record of, the Kelso-Beaver Pipeline, a 17-mile interstate pipeline that provides natural gas to the Company’s natural gas-fired generating plants located near Clatskanie, Oregon: Port Westward Unit 1 (PW1); PW2; and Beaver. As the operator of record of the Kelso-Beaver Pipeline, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety standards, operator qualification standards and public awareness requirements.

Hydroelectric Licensing—Under the Federal Power Act, PGE’s hydroelectric generating plants are subject to FERC licensing requirements, which include an extensive public review process that involves the consideration of numerous natural resource issues and environmental conditions. PGE holds FERC licenses for the Company’s projects on the Deschutes, Clackamas, and Willamette Rivers. For additional information, see the Environmental Matters section in this Item 1. and the Generating Facilities section in Item 2.—“Properties.”

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

Short-term Debt—Pursuant to applicable provisions of the Federal Power Act and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. The Company, pursuant to an order

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issued by the FERC on February 3, 2014, has authorization to issue up to $900 million of short-term debt through February 6, 2016.

NRC Regulation

The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s Trojan nuclear power plant (Trojan), which was closed in 1993. The NRC approved the 2003 transfer of spent nuclear fuel from a spent fuel pool to a separately licensed dry cask storage facility that will house the fuel on the former plant site until a United States Department of Energy (USDOE) facility is available. Radiological decommissioning of the plant site was completed in 2004 under an NRC-approved plan, with the plant’s operating license terminated in 2005. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site and radiological decommissioning of the storage facility is completed. For additional information on spent nuclear fuel storage activities, see Note 7, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

State of Oregon Regulation

PGE is subject to the jurisdiction of the OPUC, which is comprised of three members appointed by Oregon’s governor to serve non-concurrent four-year terms.

The OPUC reviews and approves the Company’s retail prices (see “Economic Regulation” below) and establishes conditions of utility service. In addition, the OPUC reviews the Company’s generation and transmission resource acquisition plans, pursuant to a bi-annual integrated resource planning process. The OPUC also regulates the issuance of securities, prescribes accounting policies and practices, and reviews applications to sell utility assets, to engage in transactions with affiliated companies, and to acquire substantial influence over public utilities.

Integrated Resource Plan—Unless the OPUC directs otherwise, PGE is required to file with the OPUC an Integrated Resource Plan (IRP) within two years of its previous IRP acknowledgment order. Based on direction from the OPUC, PGE filed its latest IRP in March 2014 (2013 IRP). The IRP guides the utility on a plan to meet future customer demand and describes the Company’s future energy supply strategy, which reflects new technologies, market conditions, and regulatory requirements. The primary goal of the IRP is to identify an acquisition plan for generation, transmission, demand-side and energy efficiency resources that, along with the Company’s existing portfolio, provides the best combination of expected cost and associated risks and uncertainties for PGE and its customers. For additional information on PGE’s most recent IRP, see “Future Energy Resource Strategy” in the Power Supply section in this Item 1.

Economic Regulation—Under Oregon law, the OPUC is required to ensure that prices and terms of service are fair, non-discriminatory, and provide regulated companies an opportunity to earn a reasonable return on their investments. Customer prices are determined through formal proceedings that generally include testimony by participating parties, discovery, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, include PGE, OPUC staff, and intervenors representing PGE customer groups. The following are the more significant regulatory mechanisms and proceedings under which customer prices are determined: 

• 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 to investors. Such changes are requested pursuant to a comprehensive general rate case process that includes revenue requirements based on a forecasted test year, debt-to-equity capital structure, return on equity, and overall rate of return. PGE’s most recent general rate case was the 2015 General Rate Case (2015 GRC), which became effective January 1, 2015. On February 12, 2015, PGE filed a general rate case with a 2016 test year (2016 GRC), for which a final order is expected to be received in December 2015. New prices are expected to be effective in 2016, with the first price change effective January 1 and an additional price change effective when the Carty Generating Station natural gas-fired generating plant (Carty) becomes operational, which is

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expected in the second quarter of 2016. For additional information, see the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

• Power Costs. In addition to price changes resulting from the general rate case process, the OPUC has approved the following mechanisms by which PGE can adjust retail customer prices to cover the Company’s 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 forecast assumes the following for the different types of PGE-owned generating resources:

▪ Thermal—Expected operating conditions;

▪ Hydroelectric—Regional hydro generation based on historical stream flow data and current hydro operating parameters; and

▪ Wind—Generation levels based on a five-year historical rolling average of the wind farm. To the extent historical information is not available for a given year, the projections are based on wind generation studies.

An initial NVPC forecast, submitted to the OPUC by April 1st each year, is updated during such year and finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, become effective at the beginning of the following calendar year; and

◦ Power Cost Adjustment Mechanism (PCAM). Customer prices can also be adjusted to absorb a portion of the difference between each year’s forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year. Under the PCAM, PGE shares a portion of the business risk or benefit associated with NVPC. The PCAM utilizes an asymmetrical deadband range within which PGE absorbs cost variances. When the variances fall outside of the deadband, the excess variance is shared, with 90% flowing to customers via the PCAM and only 10% absorbed by the Company. The deadband range is $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.”

• Decoupling—The decoupling mechanism, currently authorized through 2016, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The mechanism provides for collections from customers if weather adjusted energy use per customer is lower than levels included in the Company’s most recent general rate case; it also provides for customer refunds if weather adjusted use per customer exceeds levels included in the most recent general rate case.

The following is a summary of the impacts of the decoupling mechanism for the last three years:

◦ For 2014, the Company recorded an estimated refund of $7 million as weather adjusted energy use per customer was greater than that estimated and approved in PGE’s 2014 General Rate Case (2014 GRC). In addition, the Company recorded in 2014 a $2 million collection related to 2013 resulting from the OPUC’s review. A final determination of the 2014 estimate will be made by the OPUC through a public filing and review in 2015.

◦ For 2013, PGE recorded an estimated collection of $3 million. In addition, the Company recorded in 2013 a $2 million collection related to 2012 resulting from the OPUC’s review. A final determination

8

of the 2013 estimate was made by the OPUC through a public filing and review in 2014, which resulted in a $5 million collection for 2013.

◦ For 2012, the Company recorded an estimated refund of $1 million. A final determination of the 2012 estimate was made by the OPUC through a public filing and review in 2013, which resulted in a collection of $1 million.

• Renewable Energy. The 2007 Oregon Renewable Energy Act (the Act) established a Renewable Portfolio Standard (RPS) which required that PGE serve at least 5% of its retail load with renewable resources by 2011, with future requirements of 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 requirement with the addition of Tucannon River, which was placed into service on December 15, 2014.

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.

The Act also provides for the recovery in customer prices of all prudently incurred costs required to comply with the RPS. Under a renewable adjustment clause (RAC) mechanism, PGE can recover the revenue requirement of new renewable resources and associated transmission that is not yet included in prices. Under the RAC, PGE submits a filing by April 1st of each year for new renewable resources expected to be placed in service in the current year, with prices to become effective January 1st of the following year. In addition, the RAC provides for the deferral and subsequent recovery of eligible costs incurred prior to January 1st of the following year. The Company submitted a RAC filing to the OPUC in 2014 with the expectation that Tucannon River would be placed into service before the end of 2014. For additional information, see the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

As needed, other ratemaking proceedings may occur and can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific OPUC authorization. Such amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs. For additional information, see the “Legal, Regulatory and Environmental Matters” discussion in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Retail Customer Choice Program—PGE’s commercial and industrial customers have access to pricing options other than cost-of-service, including direct access and daily market index-based pricing. All commercial and industrial customers are eligible for direct access, whereby customers purchase their electricity from an Electricity Service Supplier (ESS). Under the program, the Company is paid for delivery of the energy to the ESS customers. In addition, large commercial and industrial customers may elect to be served by PGE on a daily market index-based price.

Certain large commercial and industrial customers may elect to be removed from cost-of-service pricing for a fixed three-year or a minimum five-year term, to be served either by an ESS, or by the Company under a daily market index-based price. Participation in the fixed three-year and minimum five-year opt-out programs is capped at 300 average megawatts (MWa) in aggregate.

The majority of the energy supplied under PGE’s Retail Customer Choice program is provided to customers that have elected service from an ESS under the minimum five-year opt-out program. In 2014, ESSs supplied direct access customers with energy representing 9% of the Company’s total retail energy deliveries for the year, compared with 8% in 2013 and 6% in 2012. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs would represent approximately 14% of the Company’s total retail energy deliveries for 2014, 2013, and 2012.

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The retail customer choice program does not have a material impact on the Company’s financial condition or operating results as revenue changes resulting from increases or decreases in electricity sales to direct access customers are substantially offset by changes in the Company’s cost of purchased power and fuel. Further, the program provides for “transition adjustment” charges or credits to direct access and market based pricing customers that reflect the above- or below-market cost of energy resources owned or purchased by the Company. Such adjustments are designed to ensure that the costs or benefits of the program do not unfairly shift to those customers that continue to purchase their energy requirements from the Company.

In addition to cost-of-service pricing, residential and small commercial customers can select portfolio options from PGE that include time-of-use and renewable resource pricing.

Energy Efficiency Funding—Oregon law provides for a “public purpose charge” to fund cost-effective energy efficiency measures, new renewable energy resources, and weatherization measures for low-income housing. This charge, equal to 3% of retail revenues, is collected from customers and remitted to the Energy Trust of Oregon (ETO) and other agencies for administration of these programs. Approximately $51 million, $48 million and $50 million was collected from customers for this charge in 2014, 2013 and 2012, respectively.

In addition to the public purpose charge, PGE also remits to the ETO amounts collected under an Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. This charge was approximately 3.2%, 3.5% and 2.7% of retail revenues for applicable customers in 2014, 2013 and 2012, respectively. Under the tariff, approximately $48 million, $50 million and $41 million was collected from eligible customers in 2014, 2013 and 2012, respectively.

Siting—Oregon’s Energy Facility Siting Council (EFSC) has regulatory and siting responsibility for large electric generating facilities, high voltage transmission lines, intrastate gas pipelines, and radioactive waste disposal sites. The responsibilities of the EFSC also include oversight of the decommissioning of Trojan. The seven volunteer members of the EFSC are appointed to four-year terms by Oregon’s governor, with staff support provided by the Oregon Department of Energy.

Regulatory Accounting

PGE is subject to accounting principles generally accepted in the United States of America (GAAP), and as a regulated public utility, the effects of rate regulation are reflected in its financial statements. These principles provide for the deferral as regulatory assets of certain actual or estimated costs that would otherwise be charged to expense, based on expected recovery from customers in future prices. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future regulatory environment and related accounting guidance. For additional information, see “Regulatory Assets and Liabilities” in Note 2, Summary of Significant Accounting Policies, and Note 6, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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Customers and Revenues

PGE generates revenue through the sale and delivery of electricity to retail customers. The Company conducts retail electric operations exclusively in Oregon within a service area approved by the OPUC. Within its service territory, the Company competes with: i) the local natural gas distribution company for the energy needs of residential and commercial space heating, water heating, and appliances; and ii) fuel oil suppliers, primarily for residential customers’ space heating needs. In addition, the Company distributes power to commercial and industrial customers that choose to purchase their energy supply from an ESS. The Company includes such “direct access” customers in its customer counts and energy delivered to such customers in its total retail energy deliveries. Retail revenues include only delivery charges and transition adjustments for these customers.

Retail Revenues

Retail customers are classified as residential, commercial, or industrial, with no single customer representing more than 5% of PGE’s total retail revenues or 7% of total retail deliveries. While the 20 largest commercial and industrial customers constituted 12% of total retail revenues in 2014, they represented nine different groups including high technology, paper manufacturing, metal fabrication, health services, and governmental agencies.

PGE’s Retail revenues (dollars in millions), retail energy deliveries (MWh in thousands), and average number of retail customers consist of the following for the years presented:

	Years Ended December 31,
	2014					2013					2012
Retail revenues(1) (dollars in millions):
Residential	$	893		51	%	$	861		51	%	$	860	50	%
Commercial	657			37		619			36		633		37
Industrial	221			12		217			13		226		13
Subtotal	1,771			100		1,697			100		1,719		100
Other accrued (deferred) revenues, net	(8		)	—		(5		)	—		4		—
Total retail revenues	$	1,763		100	%	$	1,692		100	%	$	1,723	100	%
Retail energy deliveries(2) (MWh in thousands):
Residential	7,462			39	%	7,702			40	%	7,505		39	%
Commercial	7,494			39		7,441			38		7,402		39
Industrial	4,310			22		4,276			22		4,283		22
Total retail energy deliveries	19,266			100	%	19,419			100	%	19,190		100	%
Average number of retail customers:
Residential	735,502			87	%	728,481			87	%	723,440		87	%
Commercial	105,231			13		104,385			13		103,766		13
Industrial	260			—		263			—		261		—
Total	840,993			100	%	833,129			100	%	827,467		100	%

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

(2) Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

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Additional averages for retail customers are as follows:

	Years Ended December 31,
	2014			2013			2012
Usage per customer (in kilowatt hours):
Residential	10,145			10,572			10,375
Commercial	71,216			71,284			71,343
Industrial	16,576,500			16,257,517			16,409,211
Revenue per customer (in dollars):
Residential	$	1,154		$	1,106		$	1,113
Commercial	6,187			5,840			6,041
Industrial	851,149			786,390			863,402
Revenue per kilowatt hour (in cents):
Residential		11.37	¢		10.46	¢		10.72	¢
Commercial	8.69			8.19			8.47
Industrial	5.13			4.84			5.26

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

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and are determined through general rate case proceedings and various tariff filings with the OPUC. Additionally, the Company offers different pricing options including a daily market price option, various time-of-use options, and several renewable energy options, which are offered to residential and small commercial customers. For additional information on customer options, see “Retail Customer Choice Program” within the Regulation section of this Item 1. Additional information on the customer classes follows.

Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), mobile homes, and small farms. Residential demand is sensitive to the effects of weather, with demand historically highest during the winter heating season; although, increased use of air conditioning in PGE’s service territory has caused the summer peaks to increase in recent years. Economic conditions can also affect residential demand; historical data suggests that high unemployment rates contribute to a decrease in residential deliveries. Residential demand is also impacted by energy efficiency measures; however, the Company’s decoupling mechanism is intended to mitigate the financial effects of such measures.

During 2014, as a result of warmer weather during the 2014 heating season, total residential deliveries decreased 3.1% compared to 2013. Total residential deliveries for 2013 increased 2.6% compared to 2012 as a result of more extreme weather conditions during 2013 and an increase in the average number of customers. On a weather adjusted basis, energy deliveries to residential customers decreased by 1.9% in 2014 when compared to 2013.

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

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

In 2014, the 0.7% increase in commercial deliveries compared with 2013 was driven by increased demand from across the majority of commercial sectors, most notably office buildings, government and education, food stores and the warehousing sectors combined with an increase in the average number of commercial customers. Deliveries

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to commercial customers increased 0.5% in 2013 compared with 2012, which was primarily due to more extreme weather in 2013 relative to 2012, and an increase in the average number of commercial customers.

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

The Company’s industrial energy deliveries increased 0.8% in 2014 from 2013 which was due to increased demand in the high tech industry, partially offset by a decline in demand from a paper production customer. The 0.2% decrease in 2013 from 2012 was driven by decreased demand from certain paper production and high tech manufacturing customers.

Other accrued (deferred) revenues, net include items that are not currently in customer prices, but are expected to be in prices in a future period. Such amounts include deferrals recorded under the RAC, the PCAM, and the decoupling mechanism. For further information on these items, see “State of Oregon Regulation” in the Regulation section of this Item 1.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro conditions, and daily and seasonal retail demand. Wholesale revenues represented 5% of total revenues in 2014, compared with 4% in 2013, and 3% in 2012.

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

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of excess natural gas, as well as revenues from transmission services, excess transmission capacity resales, excess fuel oil sales, pole contact rentals, and other electric services provided to customers. Other operating revenues represented 2% of total revenues in 2014, 2013, and 2012.

Seasonality

Demand for electricity by PGE’s residential and, to a lesser extent, commercial customers, is affected by seasonal weather conditions. The Company uses heating and cooling degree-days to determine the effect of weather on the demand for electricity. Heating and cooling degree-days provide cumulative variances in the average daily temperature from a baseline of 65 degrees, over a period of time, to indicate the extent to which customers are likely to use, or have used, electricity for heating or air conditioning. The higher the number of degree-days, the greater the expected demand for heating or cooling.

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

	Heating Degree-Days	Cooling Degree-Days
2014	3,794	653
2013	4,386	539
2012	4,169	436
15-year average for 2014	4,264	453

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

	Winter Loads			Summer Loads
	Average	Peak	Month	Average	Peak	Month
2014	2,574	3,866	February	2,358	3,646	August
2013	2,656	3,869	December	2,278	3,527	July
2012	2,529	3,426	January	2,249	3,597	August

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

Power Supply

PGE relies upon its generating resources, as well as wholesale power purchases from third parties to meet its customers’ energy requirements. As part of its power supply operations, the Company enters into short- and long-term power and fuel purchase agreements. PGE executes economic dispatch decisions concerning its own generation, and participates in the wholesale market in an effort to obtain reasonably-priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. The Company also promotes energy efficiency measures to meet its energy requirements.

PGE’s generating resources consist of six thermal plants (natural gas- and coal-fired turbines), two wind farms, and seven hydroelectric plants. The volume of electricity the Company generates is dependent upon, among other factors, the capacity and availability of its generating resources and the price and availability of wholesale power and natural gas. Capacity of the thermal plants represents the MW the plant is capable of generating under normal operating conditions, net of electricity used in the operation of the plant. The capacity of the Company’s thermal generating resources is also affected by ambient temperatures. Capacity of both hydro and wind generating resources represent the nameplate MW, which varies from actual energy expected to be received as these types of generating resources are highly dependent upon river flows and wind conditions, respectively. Availability represents the percentage of the year the plant was available for operations, which reflects the impact of planned and forced outages. For a complete listing of these facilities, see “Generating Facilities” in Item 2.—“Properties.”

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

	As of December 31,
	2014			2013			2012
	Capacity	%		Capacity	%		Capacity	%
Generation:
Thermal:
Natural gas	1,389	28	%	1,163	27	%	1,172	28	%
Coal	814	17		756	17		670	16
Total thermal	2,203	45		1,919	44		1,842	44
Wind (1)	717	15		450	10		450	11
Hydro (2)	494	10		494	11		489	12
Total generation	3,414	70		2,863	65		2,781	67
Purchased power:
Long-term contracts:
Capacity/exchange	250	5		160	3		160	4
Hydro	595	12		592	14		588	14
Wind	39	1		39	1		39	1
Solar	13	—		13	—		13	—
Other	118	2		117	3		117	3
Total long-term contracts	1,015	20		921	21		917	22
Short-term contracts	481	10		596	14		475	11
Total purchased power	1,496	30		1,517	35		1,392	33
Total resource capacity	4,910	100	%	4,380	100	%	4,173	100	%

(1) Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 215 MWa to 290 MWa, dependent upon wind conditions.

(2) Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 200 MWa to 250 MWa, dependent upon river flows.

For information regarding actual generating output and purchases for the years ended December 31, 2014, 2013 and 2012, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Generation

The portion of PGE’s retail load requirements generated by its plants varies from year to year and is determined by various factors, including planned and unplanned outages, availability and price of coal and natural gas, precipitation and snow-pack levels, the market price of electricity, and wind variability. In December 2014, PGE completed construction of PW2, a new capacity resource, and Tucannon River, a new renewable resource, both discussed below. In addition, as of December 31, 2014, the Company has Carty, a new energy resource, under construction, which is expected to be placed in service in the second quarter of 2016. Such resources were selected pursuant to the competitive bidding process completed in 2013 in accordance with the Company’s 2009 IRP. For additional information on these new energy and capacity resources, 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.”

Thermal PGE has a 90% ownership interest in the Boardman coal-fired generating plant (Boardman), which it operates, and has a 20% ownership interest in Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is operated by a third party. These two coal-fired generating facilities provided approximately 24% of the Company’s total retail load requirement in 2014, compared with 22% in 2013 and 19% in 2012.

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The Company has four natural gas-fired generating facilities: PW1, PW2, Beaver, and Coyote Springs Unit 1 (Coyote Springs). On December 30, 2014, construction of PW2, a 220 MW natural gas-fired capacity resource located adjacent to PW1 and Beaver near Clatskanie, Oregon, was completed and the facility was placed in service. These natural gas-fired generating plants provided approximately 18% of PGE’s total retail load requirement in 2014 and in 2013, and 15% in 2012.

The thermal plants provide reliable power for the Company’s customers, as well as capacity reserves. These resources have a combined capacity of 2,203 MW, representing approximately 65% of the net capacity of PGE’s generating facilities. Thermal plant availability, excluding Colstrip, was 89% in 2014, compared with 84% in 2013 and 92% in 2012, while Colstrip plant availability was 83% in 2014, compared with 66% in 2013 and 93% in 2012. Thermal plant availability percentages for 2013 were lower than 2014 and 2012 due to unplanned outages at three plants. For additional information on the unplanned plant outages, see “Power Operations” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

On December 31, 2014, PGE acquired an additional 10% ownership interest in Boardman from a co-owner, increasing the Company’s ownership share to 90% from 80%. For additional information, see Note 17, Jointly-owned Plant, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Wind PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River. Biglow Canyon, located in Sherman County, Oregon, is PGE’s largest renewable energy resource consisting of 217 wind turbines with a total nameplate capacity of approximately 450 MW. Tucannon River, which was placed in service on December 15, 2014, is located in southeastern Washington and consists of 116 wind turbines with a total nameplate capacity of 267 MW.

The energy from wind resources provided 6% of the Company’s total retail load requirement in 2014, 2013 and 2012. Availability for these resources was 94% in 2014, compared with 98% in 2013 and in 2012. 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 and from 80 MWa to 110 MWa for Tucannon River, dependent upon wind conditions.

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 494 MW, actual energy received is dependent upon river flows. Energy from these resources provided 9% of the Company’s total retail load requirement in 2014 and in 2013, and 10% in 2012, with availability of 100% in 2014 and in 2013, and 99% in 2012. Northwest hydro conditions have a significant impact on the region’s power supply, with water conditions significantly impacting PGE’s cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases.

PGE has a 66.67% ownership interest in the 465 MW Pelton/Round Butte hydroelectric project on the Deschutes River, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The Tribes have an option to purchase an additional undivided 16.66% interest in Pelton/Round Butte at its discretion on or after December 31, 2021. The Tribes have a second option to purchase an undivided 0.02% interest in Pelton/Round Butte at its discretion on or after April 1, 2041. If both options are exercised by the Tribes, the Tribes’ ownership percentage would exceed 50%.

Dispatchable Standby Generation(DSG)—PGE has a DSG program under which the Company can start, operate, and monitor customer-owned diesel-fueled standby generators when needed to support specific capacity needs. The program also helps provide NERC-required operating reserves. As of December 31, 2014, there were 52 sites with a

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total capacity of 94 MW. Additional DSG projects are being pursued with a goal of a total of 108 MW online by the end of 2015.

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

Natural Gas Physical supplies of natural gas are generally purchased up to 12 months in advance of delivery and based on anticipated operation of the plants. PGE attempts to manage the price risk of natural gas supply through the use of financial contracts up to 60 months in advance of expected need of energy.

PGE owns 79.5%, and is the operator of record, of the Kelso-Beaver Pipeline, which directly connects PW1, PW2 and Beaver 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 three plants.

PGE also has contractual access to natural gas storage in Mist, Oregon, from which it can draw in the event that gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company and may be utilized to provide fuel to PW1, PW2 and Beaver. PGE is in discussions with this company concerning a new long-term gas storage arrangement. PGE believes that sufficient market supplies of gas are available to meet anticipated operations of these plants for the foreseeable future.

Beaver has the capability to operate on No. 2 diesel fuel oil when it is economical or if the plant’s natural gas supply is interrupted. PGE had an approximate 6-day supply of ultra-low sulfur diesel fuel oil at the plant site as of December 31, 2014. The current operating permit for Beaver limits the number of gallons of fuel oil that can be burned daily, which effectively limits the daily hours of operation of Beaver on fuel oil.

Coyote Springs utilizes 41,000 Dth per day of natural gas when operating at full capacity, with firm transportation capacity on three pipeline systems accessing gas fields in Alberta, Canada. PGE believes that sufficient market supplies of gas are available for Coyote Springs for the foreseeable future, based on anticipated operation of the plant. Although Coyote Springs was designed to also operate on fuel oil, such capability has been deactivated in order to optimize natural gas operations.

Coal PGE has fixed-price purchase agreements that will provide coal for Boardman for the majority of 2015. The coal is obtained from surface mining operations in Wyoming and Montana and is delivered by rail under two separate transportation contracts which extend through 2020.

PGE expects to begin seeking requests for proposal in 2015 for the purchase of coal to start layering open positions for 2016 and beyond. The terms of contracts and the quality of coal are expected to be staged in alignment with required emissions limits. PGE believes that sufficient market supplies of coal are available to meet anticipated operations of Boardman through 2020.

Purchased Power

PGE supplements its own generation with power purchased in the wholesale market to meet its retail load requirements. The Company utilizes short- and long-term wholesale power purchase contracts in an effort to provide the most favorable economic mix on a variable cost basis. Such contracts have original terms ranging from one month to 53 years and expire at varying dates through 2055.

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

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

Capacity/exchange—PGE has three contracts that provide PGE with firm capacity to help meet the Company’s peak loads. One contract represents 150 MW of capacity and expires in December 2016. The other two contracts represent two power purchase agreements for up to 100 MW of seasonal peaking capacity, one agreement covers winter from December 2014 to February 2019 and the second agreement covers summer from July 2014 to September 2018.

Hydro—The Company has four contracts that provide for the purchase of power generated from hydroelectric projects with an aggregate capacity of 117 MW and which expire between 2015 and 2018. In addition, PGE has the following:

• 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 150 MW of capacity expires in 2018 and the contract representing 163 MW of capacity expires in 2052. Although the projects currently provide a total of 313 MW of capacity, actual energy received is dependent upon river flows.

• Confederated Tribes—PGE has a long-term agreement under which the Company purchases, at market prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides 165 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. During the third quarter of 2014, PGE entered into an agreement with the Tribes, whereby the Tribes have agreed to relinquish their right to sell their share of the energy generated from the Pelton/Round Butte hydroelectric project to a third party, and sell the energy exclusively to the Company for the period of January 1, 2015 through December 31, 2024.

Wind—PGE has three contracts that provide for the purchase of renewable wind-generated electricity and which extend to various dates between 2028 and 2035. Although these contracts provide a total of 39 MW of capacity, actual energy received is dependent upon wind conditions.

Solar—PGE has three agreements to purchase power generated from photovoltaic solar projects, which expire between 2036 and 2037. These projects have a combined generating capacity of 7 MW. In addition, the Company operates, and purchases power from three solar projects with an aggregate of approximately 6 MW of capacity.

Other—These primarily consist of long-term contracts to purchase power from various counterparties, including other Pacific Northwest utilities, over terms extending into 2031.

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

PGE also utilizes spot purchases of power in the open market to secure the energy required to serve its retail customers. Such purchases are made under contracts that range in duration from 15 minutes to less than one month. For additional information regarding PGE’s power purchase contracts, see Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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Future Energy Resource Strategy

In March 2014, PGE filed with the OPUC the 2013 IRP, which outlines the Company’s expectations for resource needs and resource portfolio performance over the next 20 years and includes an “Action Plan,” which covers the Company’s proposed actions over the next two to four years (through 2017). Over this time period, PGE projects energy requirements and the energy available through its generation resources and long-term power purchase agreements to be in approximate balance. In December 2014, the OPUC acknowledged PGE’s 2013 IRP with minor modifications, and the preparation and submittal of additional studies.

The Action Plan includes the following, among other components, between 2014 and 2017:

• Seek renewal, or partial renewal, of expiring power purchase agreements for energy generated from hydroelectric projects, if available and cost-effective for customers;

• Acquire a total of 114 MWa of energy efficiency through continuation of Energy Trust of Oregon programs, with a target increase of 124 MWa if legislation and regulation allow;

• Acquire an additional 25 MW of demand response and 23 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies; and

• Perform various research and studies related to load forecast and energy efficiency projections, distributed generation resources within PGE’s service territory, the viability of large-scale biomass operations, fuel supply, operational flexibility requirements and analytical tools, cost-benefit analysis of Energy Imbalance Market participation, RPS compliance strategies and potential impacts of compliance with United States Environmental Protection Agency’s (EPA’s) proposed Clean Power Plan rules concerning reductions in carbon dioxide emissions from existing fossil fuel-fired power plants in preparation for the next IRP.

The 2013 IRP also incorporates three new energy and capacity resources, Tucannon River, PW2, and Carty, which were selected in the competitive bidding process in 2013 pursuant to the Company’s 2009 IRP, the previous IRP acknowledged by the OPUC. Tucannon River and PW2 were placed in service in December 2014, with Carty expected to be placed in service in the second quarter of 2016. For additional information on these new resources, 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.”

Beyond 2018, PGE may need additional resources in order to meet the 2020 and 2025 RPS requirements and to replace energy from Boardman, which is scheduled to cease coal-fired operations in 2020. Additional post-2018 actions may also be needed to offset expiring power purchase agreements and to back-up variable energy resources, such as wind generation facilities. These actions are expected to be identified in a future IRP. PGE expects to file its next IRP with the OPUC in 2016.

Transmission and Distribution

Transmission systems deliver energy from generating facilities to distribution systems for final delivery to customers. PGE schedules energy deliveries over its transmission system in accordance with FERC requirements and operates one balancing authority area (an electric system bounded by interchange metering) in its service territory. In 2014, PGE delivered approximately 22 million megawatt hours (MWh) in its balancing authority area through 1,162 circuit miles of transmission lines operating at or above 115 kV.

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

Company’s transmission and distribution systems are located as follows:

• On property owned or leased by PGE;

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

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

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

The Company’s wholesale transmission activities are regulated by the FERC and are offered on a non-discriminatory basis in accordance with the FERC Standards of Conduct, with all potential customers provided equal access to PGE’s transmission system through PGE’s OATT. In accordance with its OATT, PGE offers several transmission services to wholesale customers:

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

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

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

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

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

Environmental Matters

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

Air Quality

Clean Air Act—PGE’s operations, primarily its thermal generating plants, are subject to regulation under the federal Clean Air Act (CAA), which addresses, among other things, particulate matter, hazardous air pollutants, and greenhouse gas emissions (GHGs). Oregon and Montana, the states in which PGE’s thermal facilities are located,

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also implement and administer certain portions of the CAA and have set standards that are at least equal to federal standards.

The EPA issued a rule in 2011 aimed at the reduction of toxic air emissions from power plants. Specifically, these mercury and air toxics standards (MATS), which became effective on April 16, 2012, for power plants are intended to reduce emissions from new and existing coal- and oil-fired electric utility steam generating units. With the installation of emissions controls, which included a Dry Sorbent Injection system, at Boardman completed in 2013, the Company believes the Boardman plant meets the MATS requirements without additional capital investment. Oregon Department of Environmental Quality (DEQ) rules provide for coal-fired operation at Boardman to cease no later than December 31, 2020. Emissions controls in place at Colstrip allow operation within the standards necessary to meet the MATS requirements. The Company does not anticipate further capital investment to meet the requirements currently in place.

Although regulation of mercury emissions is contemplated under MATS, the states of Oregon and Montana have previously adopted regulations concerning mercury emissions, with which the Company complies.

PGE manages its air emissions by the use of low sulfur fuel, emissions and combustion controls and monitoring, and sulfur dioxide (SO₂) allowances awarded under the CAA. The current and expected future SO₂ allowances, along with the recent installation of emissions controls, are anticipated to be sufficient to permit the Company to meet these compliance requirements.

Climate Change—No comprehensive GHG emissions legislation has been considered and voted on by the United States Congress in recent years. However, state, regional, and federal legislative efforts continue with respect to establishing regulation of GHG emissions and their potential impacts on climate change. The EPA has taken the lead role on climate change policy utilizing existing authority under the CAA to develop regulations.

In December 2010, the EPA announced it had entered into a proposed settlement agreement with various 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 standards for new natural gas- and coal-fired electric generating units were proposed in April 2012 under the CAA, and re-proposed in September 2013, but have yet to be finalized, as the EPA is in the process of issuing a revised proposal.

On June 2, 2014, the EPA released a proposed rule, which it calls the “Clean Power Plan.” Under the proposed rule, each state would have to reduce the carbon intensity of its power sector on a state-wide basis by an amount specified by the EPA. The proposed rule would establish state-specific goals in terms of pounds of carbon dioxide emitted per MWh. The proposed rule is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 30% below 2005 levels by 2030. The target amount was determined by the EPA’s view of each state’s options, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants; iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy); and iv) implementing customer energy efficiency programs. The final goal would need to be met in 2030 and an interim goal for each state would need to be met on average over the 10-year period from 2020 to 2029. Under the proposed rule, states would have flexibility in designing programs to meet their emission reduction targets, including the four approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

The EPA has indicated that it expects to issue the final rules by mid-summer 2015. If finalized by such date, states would have until June 30, 2016 to submit plans to implement the rule (subject to extension). The Company cannot predict whether the proposed rule will be adopted or, if adopted, i) how the states in which the Company’s generation facilities are located will implement the rule or ii) the impact of the rule on the Company’s operations. However, the rule, if adopted as proposed, could result in increased costs for the Company. The Company continues to monitor the developments around the federal proposals.

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The State of Oregon established a non-binding policy guideline that sets a goal to reduce GHG emissions to 10% below 1990 levels by 2020 and at least 75% below 1990 levels by 2050. 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.

Any laws that would impose emissions taxes or mandatory reductions in GHG emissions may have a material impact on PGE’s operations, as the Company utilizes fossil fuels in its own power generation and other companies use such fuels to generate power that PGE purchases in the wholesale market. PGE’s natural gas-fired facilities, Beaver, Coyote Springs, PW1, and PW2, and the Company’s ownership interest in coal-fired facilities, Boardman and Colstrip, provided approximately 64% of the Company’s net generating capacity during 2014. If PGE were to incur incremental costs as a result of changes in the regulations regarding GHGs, the Company would seek recovery in customer prices.

Water Quality

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

Threatened and Endangered Species and Wildlife

Fish Protection—The federal Endangered Species Act (ESA) has granted protection to many populations of migratory fish species in the Pacific Northwest that have declined significantly over the last several decades. Long-term recovery plans for these species have caused major operational changes to many of the region’s hydroelectric projects. PGE purchases power in the wholesale market to serve its retail load requirements and has contracts to purchase power generated at some of the affected facilities on the mid-Columbia River in central Washington.

PGE continues to implement fish protection measures at its hydroelectric projects on the Clackamas, Deschutes, and Willamette rivers that were prescribed by the U.S. Fish and Wildlife Service and the National Marine Fisheries Service under their authority granted in the ESA and the Federal Power Act. As a result of measures contained in their operating licenses, the Deschutes River and Willamette River projects have been certified as low impact hydro, with 50 MWa of their output included as part of the Company’s renewable energy portfolio used to meet the requirements of the Oregon RPS. Conditions required with the operating licenses are expected to result in a minor reduction in power production and increase capital spending to modify the facilities to enhance fish passage and survival.

Avian Protection—Various statutes, including the Migratory Bird Treaty Act, have established civil, criminal, and administrative penalties for the unauthorized take of migratory birds. Because PGE operates electric transmission lines and wind generation facilities that can pose risks to a variety of such birds, the Company is required to have an avian protection plan to reduce risks to bird species that can result from Company operations. PGE has developed and implemented such a plan for its transmission and distribution facilities and continues to develop similar plans for its wind generation facilities. In 2014, such a plan, referred to as a Bird Bat Conservation Strategy, was drafted for Biglow Canyon. Data collection will occur at Tucannon River, for which such a plan is anticipated in 2017.

Hazardous Waste

PGE has a comprehensive program to comply with requirements of both federal and state regulations related to hazardous waste storage, handling, and disposal. The handling and disposal of hazardous waste from Company

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facilities is subject to regulation under the federal Resource Conservation and Recovery Act (RCRA). In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, are regulated under the federal Toxic Substances Control Act.

Boardman and Colstrip produce a byproduct known as coal combustion residuals (CCR), which have historically not been considered hazardous waste under the RCRA. On December 19, 2014, the EPA signed a final rule, which becomes effective six months after publication in the Federal Register, that regulates CCR as non-hazardous waste under the RCRA. As this rule has yet to be published, PGE is unable to determine with any certainty the impact the rule will have on the Company’s operations. Based on a preliminary evaluation, the Company believes the rules will not have a material effect on operations at Boardman. However, the Company believes that this rule will have some effect on Colstrip, although it is not clear to what extent as the operator of Colstrip has indicated that it cannot yet predict the financial and operational impact. If PGE were to incur incremental costs as a result of the new rules, the Company would seek recovery in customer prices.

PGE is also subject to regulation under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA), commonly referred to as Superfund. The CERCLA provides authority to the EPA to assert joint and several liability for investigation and remediation costs for designated Superfund sites.

A 1997 investigation by the EPA of a segment of the Willamette River in Oregon known as Portland Harbor revealed significant contamination of river sediments and prompted the EPA to subsequently include Portland Harbor on the federal National Priority List as a Superfund site pursuant to CERCLA. The EPA initially listed sixty-nine Potentially Responsible Parties (PRPs), including PGE as it has historically owned or operated property near the river. In 2008, the EPA requested further information from various parties, including PGE, concerning property several miles beyond the original river segment and, as a result, the PRPs now number over one hundred.

The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017.

The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision. It is unclear for what portion, if any, PGE may be held responsible.

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

Under the Nuclear Waste Policy Act of 1982, the USDOE is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel from Trojan that is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel at the former plant site. The spent nuclear fuel is expected to remain in the ISFSI until permanent off-site storage is available. Shipment of the spent nuclear fuel from the ISFSI to off-site storage is not expected to be completed prior to 2033. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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ITEM 1A.     RISK FACTORS.

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

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

The prices that PGE charges for its retail services, as authorized by the OPUC, are a major factor in determining the Company’s operating income, financial position, liquidity, and credit ratings. As a general matter, PGE seeks to recover in customer prices most of the costs incurred in connection with the operation of its business, including, among other things, costs related to capital projects (such as the construction of new facilities or the modification of existing facilities), the costs of compliance with legislative and regulatory requirements and the costs of damage from storms and other natural disasters. However, there can be no assurance that such recovery will be granted. The OPUC has the authority to disallow the recovery of any costs that it considers imprudently incurred. Although the OPUC is required to establish customer prices that are fair, just and reasonable, it has significant discretion in the interpretation of this standard.

In February 2015, PGE filed with the OPUC a 2016 General Rate Case (2016 GRC) with a 2016 test year. For additional information regarding the 2016 GRC, see the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In PGE’s three most recent general rate cases (2015, 2014 and 2011), overall price increases approved by the OPUC were less than the Company’s initial proposals. Under such circumstances, PGE attempts to manage its costs at levels consistent with the reduced price increases. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the Company’s financial and operating results could be adversely affected.

Economic conditions that result in reduced demand for electricity and impair the financial stability of some of PGE’s customers, could affect the Company’s results of operations.

Unfavorable economic conditions in Oregon may result in reduced demand for electricity. Such reductions in demand could adversely affect PGE’s results of operations and cash flows. Economic conditions could also result in an increased level of uncollectible customer accounts and cause the Company’s vendors and service providers to experience cash flow problems and be unable to perform under existing or future contracts.

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

As part of its normal business operations, PGE purchases power and natural gas in the open market under short- and long-term contracts, which may specify variable prices or volumes. Market prices for power and natural gas are influenced primarily by factors related to supply and demand. These factors generally include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric and wind generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, and changes in technology.

Volatility in these markets can affect the availability, price and demand for power and natural gas. Disruption in power and natural gas markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect regulatory and legislative processes in unpredictable ways, affect wholesale power prices, and impair PGE’s ability to manage its energy portfolio. Changes in power and natural gas prices can also affect the fair value of derivative instruments and cash requirements to purchase power and natural gas. If power and natural gas prices decrease from those contained in the Company’s existing purchased power and natural gas agreements, PGE may

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be required to provide increased collateral, which could adversely affect the Company’s liquidity. Conversely, if power and natural gas prices rise, especially during periods when the Company requires greater-than-expected volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated.

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

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

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

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

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

Forced outages at the Company’s generating plants could result in power costs greater than those included in customer prices. In 2013, the Company experienced forced outages at three of its generating plants, and as a result, incurred incremental replacement power costs of $17 million. As indicated above, application of the Company’s PCAM could help mitigate adverse financial impacts of such outages; however, the cost sharing features of the mechanism do not provide full recovery in customer prices. Inability to recover such costs in future prices could have a negative impact on the Company’s results of operations.

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

PGE’s current position as a “short” utility requires that the Company supplement its own generation with wholesale power purchases to meet its retail load requirement. In addition, long-term increases in both the number of customers and demand for energy will require continued expansion and upgrade of PGE’s generation, transmission, and distribution systems. Construction of new facilities and modifications to existing facilities could be affected by various factors, including unanticipated delays and cost increases and the failure to obtain, or delay in obtaining, necessary permits from state or federal agencies or tribal entities, which could result in failure to complete the projects and the disallowance of certain costs in the rate determination process. In addition, failure to complete construction projects according to specifications could result in reduced plant efficiency, equipment failure, and plant performance that falls below expected levels, which could increase operating costs.

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

Access to capital markets is important to PGE’s ability to operate its business and complete its capital projects. Credit rating agencies evaluate the Company’s credit ratings on a periodic basis and when certain events occur. A ratings downgrade could increase the interest rates and fees on PGE’s revolving credit facilities and letter of credit facilities, increasing the cost of funding day-to-day working capital requirements, and could also result in higher interest rates on future long-term debt. A ratings downgrade could also restrict the Company’s access to the commercial paper market, a principal source of short-term financing, or result in higher interest costs.

In addition, if Moody’s Investors Service (Moody’s) and/or Standard & Poor’s Ratings Services (S&P) reduce their rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, which could have an adverse effect on the Company’s liquidity.

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

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

There are certain pending legal and regulatory proceedings, such as the proceedings related to refunds on wholesale market transactions in the Pacific Northwest and the investigation and any resulting remediation efforts related to the Portland Harbor site, that may have an adverse effect on results of operations and cash flows for future reporting periods. For additional information, see Item 3.—“Legal Proceedings” and Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Reduced river flows and unfavorable wind conditions can adversely affect generation from hydroelectric and wind generating resources. The Company could be required to replace energy expected from these sources with higher cost power from other facilities or with wholesale market purchases, which could have an adverse effect on results of operations.

PGE derives a significant portion of its power supply from its own hydroelectric facilities and through long-term purchase contracts with certain public utility districts in the state of Washington. Regional rainfall and snow pack levels affect river flows and the resulting amount of energy generated by these facilities. Shortfalls in energy expected from lower cost hydroelectric generating resources would require increased energy from the Company’s other generating resources and/or power purchases in the wholesale market, which could have an adverse effect on results of operations.

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

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Although the application of the PCAM could help mitigate adverse financial effects from any decrease in power provided by hydroelectric and wind generating resources, full recovery of any increase in power costs is not assured. Inability to fully recover such costs in future prices could have a negative impact on the Company’s results of operations, as well as a reduction in renewable energy credits and loss of production tax credits related to wind generating resources.

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

Access to capital and credit markets is important to PGE’s ability to operate. The Company expects to issue debt and equity securities, as necessary, to fund its future capital requirements. In addition, contractual commitments and regulatory requirements may limit the Company’s ability to delay or terminate certain projects. For additional information concerning PGE’s capital requirements, see “Capital Requirements” in the Liquidity and Capital Resources section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

If the capital and credit market conditions in the United States and other parts of the world deteriorate, the Company’s future cost of debt and equity capital, as well as access to capital markets, could be adversely affected. In addition, restrictions on PGE’s ability to access capital markets could affect its ability to execute its strategic plan.

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

Future legislation or regulations could result in limitations on greenhouse gas emissions from the Company’s fossil fuel-fired generation facilities. Compliance with any greenhouse gas emissions reduction requirements could require PGE to incur significant expenditures, including those related to carbon capture and sequestration technology, purchase of emission allowances and offsets, fuel switching, and the replacement of high-emitting generation facilities with lower-emitting facilities.

The cost to comply with potential greenhouse gas emissions reduction requirements is subject to significant uncertainties, including those related to: i) the timing of the implementation of emissions reduction rules; ii) required levels of emissions reductions; iii) requirements with respect to the allocation of emissions allowances; iv) the maturation, regulation and commercialization of carbon capture and sequestration technology; and v) PGE’s compliance alternatives. Although the Company cannot currently estimate the effect of future legislation or regulations on its results of operations, financial condition or cash flows, the costs of compliance with such legislation or regulations could be material.

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

PGE currently has unsecured revolving credit facilities with several banks for an aggregate amount of $700 million. These revolving credit facilities provide a primary source of liquidity and may be used to supplement operating cash flow and as backup for commercial paper borrowings.

The revolving credit facilities represent commitments by the participating banks to make loans and, in certain cases, to issue letters of credit. The Company is required to make certain representations to the banks each time it requests an advance under one of the credit facilities. However, in the event certain circumstances occur that could result in a material adverse change in the business, financial condition or results of operations of PGE, the Company may not be able to make such representations, in which case the banks would not be required to lend. PGE is also subject to the risk that one or more of the participating banks may default on their obligation to make loans under the credit facilities.

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

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

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

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

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

Performance of the capital markets also affects the fair value of assets that are held in trust to satisfy future obligations under the Company’s non-qualified employee benefit plans, which include deferred compensation plans. As changes in the fair value of these assets are recorded in current earnings, decreases can adversely affect the Company’s operating results. In addition, such decreases can require that PGE make additional payments to satisfy its obligations under these plans.

For additional information regarding PGE’s contribution obligations under its pension and non-qualified benefit plans, see “Contractual Obligations and Commercial Commitments” in the Liquidity and Capital Resources section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Pension and Other Postretirement Plans” in Note 10, Employee Benefits, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data.”

Changes in technology may negatively impact the revenues derived from PGE’s generation facilities.

A basic premise of PGE’s business is that generating electricity at central generation facilities achieves economies of scale and produces electricity at a relatively low price. Many companies and organizations conduct research and development activities to seek improvements in alternative technologies, such as fuel cells, photovoltaic (solar) cells, micro-turbines and other forms of distributed generation. It is possible that advances in such technologies will reduce the cost of alternative methods of electricity production to a level that is equal to or below that of central thermal and wind generation facilities. Such a development could limit the Company’s future growth opportunities and limit growth in demand for PGE’s electric service.

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

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

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

A portion of PGE’s total energy requirement is supplied with power generated from hydroelectric and wind generating resources. Operation of these facilities is subject to regulation related to the protection of fish and wildlife. The listing of various plants and species of fish, birds, and other wildlife as threatened or endangered has resulted in significant operational changes to these projects. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, laws relating to the protection of migratory birds and other wildlife could impact the development and operation of transmission lines and wind projects. Also, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the availability of hydroelectric or wind generating resources to meet the Company’s energy requirements.

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

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

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

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

The OPUC has authorized the Company to collect $2 million annually, beginning in 2011, from retail customers for such damages and to defer any amount not utilized in the current year. During 2014, PGE utilized $5 million of the established reserve as a result of restoration costs associated with storm damage occurring between October and

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December 2014. The remaining reserve balance of $3 million as of December 31, 2014 is available to offset potential storm damage costs in future years.

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

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

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

PGE has a workforce with a significant number of employees approaching retirement, which could make it more difficult to maintain the workforce necessary to provide safe and reliable service to customers and meet regulatory requirements.

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

ITEM 1B.     UNRESOLVED STAFF COMMENTS.

None.

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ITEM 2.     PROPERTIES.

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

Generating Facilities

The following are generating facilities owned by PGE as of December 31, 2014:

Facility	Location	Net Capacity (1)
Wholly-owned:
Natural Gas/Oil:
Beaver	Clatskanie, Oregon	516	MW
Port Westward Unit 1	Clatskanie, Oregon	401
Coyote Springs	Boardman, Oregon	248
Port Westward Unit 2 (2)	Clatskanie, Oregon	224
Wind:
Biglow Canyon	Sherman County, Oregon	450
Tucannon River (3)	Columbia County, Washington	267
Hydro:
North Fork	Clackamas River	58
Faraday	Clackamas River	46
Oak Grove	Clackamas River	44
River Mill	Clackamas River	25
T.W. Sullivan	Willamette River	18
Jointly-owned (4):
Coal:
Boardman (5)	Boardman, Oregon	518
Colstrip (6)	Colstrip, Montana	296
Hydro:
Round Butte (7)	Deschutes River	230
Pelton (7)	Deschutes River	73
Net capacity		3,414	MW

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

(2) Placed in service on December 30, 2014.

(3) Placed in service on December 15, 2014.

(4) Reflects PGE’s ownership share.

(5) PGE operates Boardman and has a 90% ownership interest, which, on December 31, 2014, increased from 80%. For information concerning the Company’s acquisition of the additional 10% ownership interest in Boardman on December 31, 2014, see Note 17, Jointly-owned Plant, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

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

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PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the Federal Power Act. The licenses for the hydroelectric projects on the three different rivers expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055.

Transmission and Distribution

PGE owns and/or has contractual rights associated with transmission lines that deliver electricity from its generation facilities to its distribution system in its service territory and also to the Western Interconnection. As of December 31, 2014, PGE owned an electric transmission system consisting of 1,162 circuit miles as follows: 212 circuit miles of 500 kV line; 402 circuit miles of 230 kV line; and 548 miles of 115 kV line. The Company also has 26,880 circuit miles of primary and secondary distribution lines that deliver electricity to its customers.

The Company also has an ownership interest in the following:

• Approximately 15% of the capacity on the Colstrip Project Transmission facilities from the Colstrip plant in Montana to BPA’s transmission system; and

• Approximately 20% of the capacity on the Pacific Northwest Intertie, a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border. The Pacific Northwest Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

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

• Approximately 3,240 MW of firm BPA transmission on BPA’s system to PGE’s service territory in Oregon; and

• 195 MW of firm BPA transmission from mid-Columbia projects in Washington to the northern end of the Pacific Northwest Intertie, near John Day, Oregon, 100 MW to the northern end of the Pacific DC Intertie, near Celilo, Oregon, and 5 MW to Biglow Canyon.

ITEM 3.     LEGAL PROCEEDINGS.

Citizens’ Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O’Neill v. Public Utility Commission of Oregon, Public Utility Commission of Oregon, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, and the Oregon Supreme Court.

PGE, in its 1993 general rate filing, sought OPUC approval to recover through rates future decommissioning costs and full recovery of, and a rate of return on, its Trojan investment. PGE’s request was challenged, but in August 1993, the OPUC issued a Declaratory Ruling in PGE’s favor. The Citizens’ Utility Board (CUB) appealed the decision to the Oregon Court of Appeals.

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

In April 1996, the Marion County Circuit Court issued a decision that found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan. The 1996 decision was appealed to the Oregon Court of Appeals.

In June 1998, the Oregon Court of Appeals ruled that the OPUC did not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan. The court remanded the matter to the OPUC for reconsideration of its 1995 Order in light of the court’s decision.

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

In March 2002, the OPUC issued an order (Settlement Order) denying all of the URP’s challenges and approving PGE’s application for the accounting and ratemaking elements of the Settlement. The URP appealed the Settlement Order to the Marion County Circuit Court. Following various appeals and proceedings, the Oregon Court of Appeals issued an opinion in October 2007 that reversed the Settlement Order and remanded the Settlement Order to the OPUC for reconsideration.

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

In October 2008, the URP and the Class Action Plaintiffs (described in the Dreyer proceeding below) separately appealed the September 2008 OPUC order to the Oregon Court of Appeals. On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the September 2008 OPUC order.

On October 18, 2013, the Oregon Supreme Court accepted plaintiffs’ petition seeking review of the February 6, 2013 Oregon Court of Appeals decision.

On October 2, 2014, the Oregon Supreme Court, in a unanimous decision, affirmed the February 6, 2013 Oregon Court of Appeals decision that upheld the OPUC order dated September 30, 2008. On January 15, 2015, the Oregon Supreme Court denied the plaintiffs petition seeking reconsideration of the October 2, 2014 decision.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court; and Morgan v. Portland General Electric Company, Marion County Circuit Court.

In January 2003, two class action suits were filed in Marion County Circuit Court against PGE. The Dreyer case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the Morgan case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million plus interest for the Current Class and $70 million plus interest for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charged its customers.

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

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

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

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

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Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission and Ninth Circuit Court of Appeals (collectively, Pacific Northwest Refund proceeding).

In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. Although FERC’s original decision terminated the proceeding and denied the claims for refunds, upon appeal of this decision to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit), the Ninth Circuit remanded the case to the FERC to, among other things, address market manipulation evidence and account for the evidence in any future orders regarding the award or denial of refunds in the proceedings.

In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. The orders held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also expanded the scope of the hearing to allow parties to pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule or of a statutory requirement. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund claimants have filed petitions for appeal of these procedural orders with the Ninth Circuit.

Pursuant to a FERC-ordered settlement process, the Company received notice of two claims for refunds in the first phase of the remand proceeding and reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012.

Additionally, the settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The above-referenced settlements resulted in a release of the Company as a named respondent in the first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.

During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of the California Energy Resource Scheduling division of the California Department of Water Resources (CERS), presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of the two CERS’ respondents, but that CERS had produced evidence that the remaining CERS respondent had engaged in unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts. The Administrative Law Judge scheduled a second phase

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of the hearing to commence after a final FERC decision on the Initial Decision. The Administrative Law Judge determined that in the second phase the remaining respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. The findings in the Initial Decision are subject to further FERC action. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.

Sierra Club and Montana Environmental Information Center v. PPL Montana LLC, Avista Corporation, Puget Sound Energy, Portland General Electric Company, Northwestern Corporation, and PacifiCorp, U.S. District Court for the District of Montana.

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the CAA at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC - the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleges certain violations of the CAA, and stated that the Sierra Club and MEIC would: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees.

The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality. The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.

On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes civil penalties and an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.

On May 3, 2013, the defendants filed a motion to dismiss 36 of the 39 claims in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emissions increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects.

In July 2014, the court denied defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment. On August 27, 2014, the plaintiffs filed a second amended complaint. The defendants’ response to the second amended complaint was filed on September 26, 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is ongoing with trial now scheduled for November 2015.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

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PART II

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

PGE’s common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol “POR”. As of February 10, 2015, there were 868holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $37.74per share. The following table sets forth, for the periods indicated, the highest and lowest sales prices of PGE’s common stock as reported on the NYSE.

	High		Low		Dividends Declared Per Share
2014
Fourth Quarter	$	40.31	$	32.07	$	0.280
Third Quarter	34.74		31.41		0.280
Second Quarter	34.69		32.01		0.280
First Quarter	32.75		28.98		0.275
2013
Fourth Quarter	$	30.57	$	27.82	$	0.275
Third Quarter	33.26		27.57		0.275
Second Quarter	32.91		29.14		0.275
First Quarter	30.53		27.42		0.270

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

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ITEM 6.     SELECTED FINANCIAL DATA.

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

	Years Ended December 31,
	2014			2013			2012			2011			2010
	(In millions, except per share amounts)
Statement of Income Data:
Revenues, net	$	1,900		$	1,810		$	1,805		$	1,813		$	1,783
Gross margin	62		%	58		%	60		%	58		%	54		%
Income from operations (1)	$	293		$	206		$	302		$	309		$	267
Net income (1)	174			104			140			147			121
Net income attributable to Portland General Electric Company (1)	175			105			141			147			125
Earnings per share—basic (1)	2.24			1.36			1.87			1.95			1.66
Earnings per share—diluted (1)	2.18			1.35			1.87			1.95			1.66
Dividends declared per common share	1.115			1.095			1.075			1.055			1.035
Statement of Cash Flows Data:
Capital expenditures	1,007			656			303			300			450

(1) The year ended December 31, 2013 includes $52 million of costs expensed related to the Company’s Cascade Crossing Transmission Project. For information regarding this matter, see “Electric Utility Plant” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

	As of December 31,
	2014			2013			2012			2011			2010
	(Dollars in millions)
Balance Sheet Data:
Total assets	$	7,042		$	6,101		$	5,670		$	5,733		$	5,491
Total long-term debt	2,501			1,916			1,636			1,735			1,808
Total Portland General Electric Company shareholders’ equity	1,911			1,819			1,728			1,663			1,592
Common equity ratio	43.3		%	48.7		%	51.1		%	48.6		%	46.7		%

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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

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

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

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

• 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 customers’ 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 generating 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 PGE 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 of capital projects, 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 generating 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;

• 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;

• declines in the fair value of 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, transmission, and distribution 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.

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

Overview

Capital Requirements and Financing—During 2014, the following three new generation resources were under construction:

Port Westward Unit 2—In May 2013, PGE commenced construction of PW2, a 220 MW natural gas-fired flexible capacity resource located adjacent to PW1 and Beaver near Clatskanie, Oregon. In December 2014, this capacity resource was placed in service. As of December 31, 2014, $295 million is included in Electric utility plant related to PW2, including $20 million of AFDC. The Company estimates that final completion of the plant will require approximately$20 million of capital expenditures in 2015.

Tucannon River Wind Farm—In September 2013, PGE commenced construction of Tucannon River in southeastern Washington consisting of 116 turbines for a total nameplate capacity of 267

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MW. In December 2014, this renewable resource was placed in service. As of December 31, 2014, $501 million is included in Electric utility plant related to Tucannon River, including $24 million of AFDC and net of a state sales tax refund of $23 million from the state of Washington. The Company estimates that final completion of the wind farm will require approximately $29 million of capital expenditures in 2015.

Carty Generating Station—In January 2014, the Company commenced construction of Carty, a 440 MW natural gas-fired baseload resource in Eastern Oregon, located adjacent to Boardman. The total cost of Carty is estimated at $450 million, excluding AFDC, and the facility is expected to be online in the second quarter of 2016. As of December 31, 2014, $260 million, including $16 million of AFDC, is included in CWIP for Carty.

PGE’s capital requirements amounted to $948 million for 2014, with $606 million related to the construction of these new generation resources. The remainder of the 2014 capital requirements related to ongoing capital expenditures for the upgrade, replacement, and expansion of transmission, distribution and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing. During 2014, the combination of cash from operations in the amount of $518 million, and proceeds from unsecured term loans and issuances of FMBs in the amount of $585 million funded the Company’s capital requirements.

Capital requirements in 2015 are expected to approximate $629 million, which includes an estimated $172 million related to the construction of Carty. PGE expects to fund 2015 estimated capital requirements and contractual maturities of long-term debt of $375 million with a combination of cash from operations, which is expected to range from $460 million to $500 million, and issuances of shares pursuant to an equity forward sale agreement (EFSA) and long-term debt securities. For information concerning the EFSA, see Note 12, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” and for additional related information, see the Liquidity and the Debt and Equity Financings sections of this Item 7.

General Rate Cases—On February 12, 2015,PGE filed with the OPUC a 2016 GRC, which is based on a 2016 test year and includes costs related to Carty. The Company’s request, when combined with other supplemental tariff changes, would result in an increase in annual revenues of $66 million. Such change would result in an approximate 3.7% overall increase relative to currently approved prices.

The net increase in annual revenue requirement consists of the following (in millions):

Carty	$	83
Base business cost	39
Supplemental tariff updates*	(56		)
Annual revenue requirement, net	$	66

* Includes $26 million related to capital project deferrals expected to be fully recovered in 2015, $17 million of accelerated customer credits related to the settlement of a legal matter concerning costs associated with the operation of the ISFSI, a $15 million increase in customer credits related to the Residential Exchange Program, and other tariff updates.

PGE is proposing a capital structure of 50% debt and 50% equity, a return on equity of 9.9%, a cost of capital of 7.67%, and a rate base of approximately $4.5 billion.

Regulatory review of the 2016 GRC will continue throughout 2015, with a final order expected to be issued by the OPUC by mid-December 2015. New customer prices are expected to become effective in 2016, with an initial price decrease January 1 and a price increase effective as Carty becomes operational, which is expected in the second quarter of 2016.

In December 2014, the OPUC issued an order on PGE’s 2015 GRC, which was based on a 2015 test year. When combined with customer credits, the OPUC order authorized a $15 million increase in annual revenues,

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representing an approximate 1% overall increase in customer prices, which became effective January 1, 2015. The order reflects a capital structure of 50% debt and 50% equity, a return on equity of 9.68%, a cost of capital of 7.56%, and a rate base of approximately $3.8 billion.

Pursuant to the 2015 GRC order, a forecast of capital expenditures for PW2 of $323 million and Tucannon River of $525 million was used to set customers prices. However, to the extent that total actual capital expenditures are less than that used to set customer prices, the 2015 revenue requirement impact of any shortfall will be deferred for future refund to customers. In the event that total actual capital expenditures exceed those used to set customer prices, there is no deferral of such incremental capital costs. For further information regarding actual costs recorded as of December 31, 2014, see “Capital Requirements and Financing” in this Overview, above.

In December 2013, the OPUC issued an order on PGE’s 2014 GRC, which was based on a 2014 test year. The OPUC authorized a $61 million increase in annual revenues, representing an approximate 4% overall increase in customer prices, which became effective January 1, 2014. The order reflects a capital structure of 50% debt and 50% equity, a return on equity of 9.75%, a cost of capital of 7.65%, and a rate base of approximately $3.1 billion.

The general rate case filings, as well as copies of the orders, direct testimony, exhibits, and stipulations are available on the OPUC website at www.oregon.gov/puc.

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

The Company’s revenues and income from operations can fluctuate during the year due to, among other variables, the impacts of seasonal weather conditions on the demand for electricity and changes in retail prices for electricity and in customer usage patterns. In addition, the availability and price of power and fuel can affect income from operations. PGE is a winter-peaking utility that typically experiences its highest retail energy demand during the winter heating season, with a slightly lower peak in the summer that generally results from air conditioning demand.

Customers and Demand—In 2014, retail energy deliveries decreased 0.8% from 2013, which was driven by the decrease in residential energy deliveries and partially offset by increases in commercial and industrial energy deliveries. The decline in demand from residential customers is largely attributable to warmer weather conditions during the 2014 heating season relative to 2013. Total heating degree-days in 2014 (an indication of the extent to which customers are likely to use, or have used, electricity for heating) was 11% lower than the 15-year average, and 13% lower than total heating degree days in 2013.

The increases in commercial and industrial energy deliveries were driven by increased demand from the high tech industry, office buildings, and the government and education sectors, which was partially offset by decreased demand from a paper production customer. Energy efficiency and conservation efforts by retail customers influence demand, although the financial effects of such efforts are intended to be mitigated by the decoupling mechanism.

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For 2014 and 2013, the average number of retail customers and deliveries, by customer class, were as follows:

	2014		2013		Increase/ (Decrease) in Energy Deliveries
	Average Number of Customers	Energy Deliveries *	Average Number of Customers	Energy Deliveries *
Residential	735,502	7,462	728,481	7,702	(3.1	)%
Commercial	105,231	7,494	104,385	7,441	0.7
Industrial	260	4,310	263	4,276	0.8
Total	840,993	19,266	833,129	19,419	(0.8	)%

 * In thousands of MWh.

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

Plant availability is impacted by planned maintenance and forced, or unplanned, outages, during which the respective plant is unavailable to provide power. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year. Availability of the plants PGE operates approximated 92%, 89%, and 94% for the years ended December 31, 2014, 2013, and 2012, respectively, with the availability of Colstrip, which PGE does not operate, approximating 83%, 66%, and 93%, respectively.

Beginning in July 2013, the Company experienced three unplanned plant outages with Boardman off-line for July 2013, Coyote Springs off-line for September through November 2013, and Colstrip Unit 4 off-line for July 2013 through January 2014. As a result of these unplanned outages, the Company incurred incremental replacement power costs of approximately $2 million in 2014 and $17 million in 2013.

During the year ended December 31, 2014, the Company’s generating plants provided approximately 58% of its retail load requirement, compared to 54% in 2013 and 50% in 2012. The lower relative volume of power generated to meet the Company’s retail load requirement during 2012 was primarily due to the economic displacement of thermal generation by energy received from hydro resources and lower-cost purchased power.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increased 1% in 2014 compared to 2013, primarily due to more favorable hydro conditions in 2014. These resources provided approximately 18% of the Company’s retail load requirement for 2014, compared with 17% for 2013 and 19% for 2012. Energy received from these sources exceeded projections (or “normal”) included in the Company’s AUT by approximately 2% in 2014, 1% in 2013, and 11% in 2012. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year. “Normal” represents the level of energy forecasted to be received from hydroelectric resources for the year and is based on average regional hydro conditions. Any excess in hydro generation from that

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projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Based on recent forecasts of regional hydro conditions, energy from hydro resources is expected to be below normal for 2015.

Energy expected to be received from wind generating resources is projected annually in the AUT and through 2013, was based on wind studies completed in connection with the permitting process of the wind farm. For 2014 and beyond, the projection included in the AUT is based on a five-year historical rolling average of the wind farm. To the extent historical information is not available for a given year, the projections are based on wind studies. Any excess in wind generation from that projected in the AUT generally displaces power from higher-cost sources, while any shortfall is generally replaced with power from higher-cost sources. Energy received from wind generating resources fell short of that projected in PGE’s AUT by 9% in 2014, 15% in 2013 and 20% in 2012.

Pursuant to the Company’s PCAM, customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, to the extent such difference is outside of a pre-determined “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC is above or below the deadband, the PCAM provides for 90% of the variance to be collected from or refunded to customers, respectively, subject to a regulated earnings test. The following is a summary of the impacts of the PCAM for 2014, 2013 and 2012:

• For 2014, actual NVPC was below baseline NVPC by $7 million, which is within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2014. A final determination regarding the 2014 PCAM results will be made by the OPUC through a public filing and review in 2015.

• For 2013, actual NVPC was above baseline NVPC by $11 million, which is within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2013. A final determination regarding the 2013 PCAM results was made by the OPUC through a public filing and review in 2014, which confirmed no collection from customers pursuant to the PCAM for 2013.

• For 2012, actual NVPC was below baseline NVPC by $17 million, and exceeded the lower deadband threshold of $15 million. However, based on results of the regulated earnings test, no estimated refund to customers was recorded as of December 31, 2012. A final determination regarding the 2012 PCAM results was made by the OPUC through a public filing and review in 2013, which confirmed no refund to customers pursuant to the PCAM for 2012.

For further information concerning the PCAM, see Power Costs under “State of Oregon Regulation” in the Regulation section of Item 1.—“Business.”

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

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

• An investigation of environmental matters at Portland Harbor.

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

On June 2, 2014, the EPA released a proposed rule, which it calls the “Clean Power Plan,” intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 30% below 2005 levels by 2030. For additional information regarding this proposed rule, see “Environmental Matters” in Item 1.—Business.

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On December 19, 2014, the EPA signed a final rule that regulates CCR as non-hazardous waste. For additional information regarding this new rule, see “Environmental Matters” in Item 1.—Business.

The following discussion highlights certain regulatory items, which have impacted the Company’s revenues, results of operations, or cash flows for 2014, or have affected customer prices, as authorized by the OPUC. In some cases, the Company deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Power Costs—Pursuant to the AUT process, PGE files annually an estimate of power costs for 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.

The 2014 AUT was approved by the OPUC and became effective January 1, 2014, with an expected reduction in annual revenues of approximately $17 million based on lower forecasted power costs. This amount was included in the overall $61 million revenue increase authorized by the OPUC in the Company’s 2014 GRC.

The 2015 AUT was approved by the OPUC and became effective January 1, 2015, with an expected reduction in annual revenues of approximately $60 million based on lower forecasted power costs. This amount was included in the overall $15 million revenue increase authorized by the OPUC in the Company’s 2015 GRC.

In June 2014, the Company submitted the 2013 results of the PCAM to the OPUC for final regulatory review and determination of any customer refund or collection. Based on a regulated earnings test, no refund or collection resulted, and in October 2014, the OPUC issued an order to such effect. For further information, see “Power Operations” in the Operating Activities section of this Overview, above.

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 Company may submit a filing to the OPUC by April 1st each year, with prices expected 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.

PGE submitted a RAC filing to the OPUC in 2014 anticipating that the Tucannon River wind farm would be placed into service before the end of the year. The Company utilized the RAC to record the revenue requirement, which was estimated to be approximately $1 million, for the period from December 15, 2014 when the facility was placed into service, until December 31, 2014. Because Tucannon River was included in the 2015 GRC, PGE proposed to provide the final actual deferred revenue requirement to the OPUC in the first quarter of 2015, with the tariff collection under the RAC to begin no earlier than July 1, 2015.

Decoupling Mechanism—The decoupling mechanism, which the OPUC has authorized through 2016, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The mechanism provides for collection from (or refund to) customers if weather adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

As part of the Company’s 2014 GRC, the OPUC approved a change in the refund or collection period to begin January 1. The Company recorded an estimated refund of $5 million during the year ended December 31, 2014, which resulted from variances between actual weather adjusted use per customer and that projected in the 2014 GRC. Any refund is expected to occur over a one-year period, which will begin January 1, 2016.

Capital deferral—In the 2011 General Rate Case (2011 GRC), the OPUC authorized the Company to defer the costs associated with four capital projects that were not completed at the time the 2011 GRC was approved. In 2012, PGE deferred such costs and recorded a regulatory asset of $16 million for potential future recovery in customer prices with an offsetting credit to Depreciation and amortization expense. The OPUC authorized recovery of the deferred costs over a one-year period beginning January 1, 2014. For 2013, the Company has recorded a

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dditional deferred costs and interest associated with these projects totaling $19 million, with recovery of such amounts included in customer prices over a one year period beginning January 1, 2015. Beginning January 1, 2014, the costs of these projects were reflected in the Company’s rate base.

Boardman Operating Life Adjustment—In PGE’s 2011 GRC, the OPUC approved a tariff that provided a mechanism for future consideration of customer price changes related to the recovery of the Company’s remaining investment in Boardman over a shortened operating life. Pursuant to the tariff, the OPUC approved recovery of increased depreciation expense reflecting a change in the retirement date of Boardman from 2040 to 2020 and estimated decommissioning costs, with new prices effective July 1, 2011. As part of the 2014 GRC, the incremental depreciation expense that resulted from the shortened Boardman life was rolled into base customer prices, while recovery of the decommissioning costs continue under this separate tariff. The tariff also provides for annual updates to decommissioning revenue requirements with revised prices to take effect each January 1.

During the second quarter of 2014, the OPUC approved the Company’s request for recovery of additional decommissioning costs that resulted from the acquisition of an additional 15% interest in Boardman on December 31, 2013, which was expected to result in approximately $3 million of incremental revenue in 2014.

On December 31, 2014, PGE acquired an additional 10% ownership share in Boardman previously held by one of the former co-owners. On September 18, 2014, the Company submitted to the OPUC a request for approval of the annual update of the decommissioning revenue requirements for 2015, which included the additional decommissioning costs related to this incremental 10% ownership. PGE received authorization from the FERC in November 2014 to consummate the acquisition. The OPUC authorized the acquisition of the 10% interest in the 2015 GRC order, with recovery of the incremental share of decommissioning costs authorized in the tariff effective January 1, 2015.

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Results of Operations

The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations.

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

	Years Ended December 31,
	2014					2013					2012
	Amount			As % of Rev		Amount			As % of Rev		Amount			As % of Rev
Revenues, net	$	1,900		100	%	$	1,810		100	%	$	1,805		100	%
Purchased power and fuel	713			38		757			42		726			40
Gross margin	1,187			62		1,053			58		1,079			60
Other operating expenses:
Generation, transmission and distribution	257			13		225			12		211			12
Cascade Crossing transmission project	—			—		52			3		—			—
Administrative and other	227			12		219			12		216			12
Depreciation and amortization	301			16		248			14		248			14
Taxes other than income taxes	109			6		103			6		102			5
Total other operating expenses	894			47		847			47		777			43
Income from operations	293			15		206			11		302			17
Interest expense, net *	96			5		101			5		108			6
Other income:
Allowance for equity funds used during construction	37			2		13			1		6			—
Miscellaneous income, net	1			—		7			—		4			—
Other income, net	38			2		20			1		10			—
Income before income taxes	235			12		125			7		204			11
Income tax expense	61			3		21			1		64			3
Net income	174			9		104			6		140			8
Less: net loss attributable to noncontrolling interests	(1		)	—		(1		)	—		(1		)	—
Net income attributable to Portland General Electric Company	$	175		9	%	$	105		6	%	$	141		8	%

* Includes an allowance for borrowed funds used during construction of $22 million in 2014, $7 million in 2013, and $4 million in 2012.

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

	Years Ended December 31,
	2014					2013					2012
Revenues(1) (dollars in millions):
Retail:
Residential	$	893		47	%	$	861		48	%	$	860	48	%
Commercial	657			34		619			34		633		34
Industrial	221			12		217			12		226		13
Subtotal	1,771			93		1,697			94		1,719		95
Other accrued (deferred) revenues, net	(8		)	—		(5		)	—		4		—
Total retail revenues	1,763			93		1,692			94		1,723		95
Wholesale revenues	95			5		80			4		49		3
Other operating revenues	42			2		38			2		33		2
Total revenues	$	1,900		100	%	$	1,810		100	%	$	1,805	100	%
Energy deliveries(2) (MWh in thousands):
Retail:
Residential	7,462			34	%	7,702			35	%	7,505		35	%
Commercial	7,494			34		7,441			34		7,402		35
Industrial	4,310			20		4,276			20		4,283		20
Total retail energy deliveries	19,266			88		19,419			89		19,190		90
Wholesale energy deliveries	2,520			12		2,353			11		2,249		10
Total energy deliveries	21,786			100	%	21,772			100	%	21,439		100	%
Average number of retail customers:
Residential	735,502			87	%	728,481			87	%	723,440		87	%
Commercial	105,231			13		104,385			13		103,766		13
Industrial	260			—		263			—		261		—
Total	840,993			100	%	833,129			100	%	827,467		100	%

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

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

follows:

	Years Ended December 31,
	2014				2013				2012
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	4,466		21	%	4,070		19	%	3,610		17	%
Natural gas	3,429		16		3,375		16		2,882		14
Total thermal	7,895		37		7,445		35		6,492		31
Hydro	1,750		8		1,646		8		1,943		9
Wind	1,172		6		1,200		5		1,125		5
Total generation	10,817		51		10,291		48		9,560		45
Purchased power:
Term	5,926		28		6,472		31		7,382		35
Hydro	1,568		7		1,629		8		1,728		8
Wind	317		2		311		1		319		1
Spot	2,626		12		2,547		12		2,285		11
Total purchased power	10,437		49		10,959		52		11,714		55
Total system load	21,254		100	%	21,250		100	%	21,274		100	%
Less: wholesale sales	(2,520	)			(2,353	)			(2,249	)
Retail load requirement	18,734				18,897				19,025

Net income attributable to Portland General Electric Company for the year ended December 31, 2014 was $175 million, or $2.18 per diluted share, compared to $105 million, or $1.35 per diluted share, for the year ended December 31, 2013. The $70 million, or 67%, increase in net income was primarily driven by higher average retail prices resulting from the January 1, 2014 price increase authorized by the OPUC in the Company’s 2014 GRC, lower net variable power costs, an increase in AFDC resulting from a higher average CWIP balance, and the charge to expense of $52 million of capitalized costs related to Cascade Crossing Transmission Project in the second quarter of 2013. A0.8% decrease in retail energy deliveries driven by a decline in residential energy deliveries, higher operating and maintenance expenses, combined with an increase in the Company’s effectivetax rate to 26.0% for 2014 from 16.8% for 2013 partially offset the increases to net income.

Net income attributable to Portland General Electric Company for the year ended December 31, 2013 was $105 million, or $1.35 per diluted share, compared to $141 million, or $1.87 per diluted share, for the year ended December 31, 2012. The $36 million, or 26%, decrease in net income was primarily driven by the charge to expense in 2013 of $52 million of previously capitalized costs related to Cascade Crossing, $17 million of incremental replacement power costs related to three unplanned plant outages, and an industrial customer refund of $9 million related to cumulative over-billings over a period of several years. These three items are the primary drivers for the reduction in the Company’s income tax expense for 2013, which had a favorable impact to net income when compared to 2012. In addition, higher repair costs at the Company’s generating plants, higher operating and maintenance costs related to PGE’s transmission and distribution system, a 4% increase in average variable power cost per MWh, and higher pension costs all contributed to the decrease in net income. A 3% increase in retail energy deliveries to residential customers primarily resulting from more extreme weather in 2013, an increase in the allowance for debt and equity funds used for construction, as well as lower interest expense partially offset the decreases to net income.

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2014 Compared to 2013

Revenues increased $90 million, or 5%, in 2014 compared with 2013 as a result of the items discussed below.

Total retail revenues increased $71 million, or 4%, in 2014 compared with 2013, primarily due to the net effect of the following:

• A $60 million increase related to higher average retail prices resulting from the January 1, 2014 price increase authorized by the OPUC in the Company’s 2014 GRC;

• A $20 million increase related to an increase in the average retail price for the collection of deferred costs related to four capital projects beginning January 1, 2014 (offset in Depreciation and amortization expense);

• A $9 million increase as a result of an industrial customer refund recorded in the second quarter of 2013 (reflected in Other retail revenues, net in the preceding table) related to cumulative over-billings that occurred over a period of several years as a result of a meter configuration error; and

• A $5 million increase related to various items, including other supplemental tariff changes; partially offset by

• A $13 million decrease related to an 0.8% decline in retail energy deliveries, consisting of a decrease of 3.1% in residential, partially offset by increases of 0.7% and 0.8% in commercial and industrial, respectively; and

• A $10 million decrease related to the decoupling mechanism, with an overall estimated refund of $5 million recorded in 2014 compared with an overall estimated collection of $5 million recorded in 2013.

Total heating degree-days in 2014 were lower than the 15-year average (as provided by the National Weather Service, as measured at Portland International Airport), and total heating degree days in 2013. While 2014 total cooling degree days exceeded the 15-year average and 2013 total cooling degree-days. The following table presents the number of heating and cooling degree-days for 2014 and 2013, along with the 15-year averages:

	Heating Degree-Days						Cooling Degree-Days
	2014		2013		Increase/(decrease)		2014		2013		Increase/(decrease)
1st quarter	1,891		1,902		(1	)%	—		—		—	%
2nd quarter	530		593		(11	)	57		82		(30	)
3rd quarter	18		90		(80	)	579		457		27
4th quarter	1,355		1,801		(25	)	17		—		—
	3,794		4,386		(13	)	653		539		21
15-year annual average	4,264		4,239		1		453		454		—
Increase (decrease) from the 15-year annual average	(11	)%	3	%			44	%	19	%

On a weather adjusted basis, retail energy deliveries in 2014 were 0.3% below 2013, with energy deliveries to residential customers decreasing by 1.9%, and energy deliveries to commercial and industrial customers each increasing 0.8%. PGE projects that retail energy deliveries for 2015 will be approximately 1.0% higher than 2014 weather adjusted levels, after allowing for energy efficiency and conservation efforts.

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

In 2014, the $15 million, or 19%, increase in wholesale revenues from 2013 consisted of $9 million related to a 11% increase in average wholesale price and $6 million related to a 7% increase in wholesale sales volume.

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Other operating revenues increased $4 million, or 11%, in 2014 from 2013, primarily due to higher sales of excess transmission capacity and services, as well as an increase in pole contact rentals. The increase was partially offset by a $6 million decrease in gains on the sale of excess natural gas not needed for operations.

Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. In 2014, Purchased power and fuel expense decreased $44 million, or 6%, from 2013, which was driven by a 6% decline in the average variable power cost per MWh to $33.54 in 2014 from $35.61 in 2013. The decrease was driven by a decline in the Company’s cost of natural gas to fuel natural gas-fired plants in 2014 compared with 2013, combined with higher-cost replacement power in 2013 related to thermal plant outages.

Energy received from PGE-owned hydroelectric projects and from mid-Columbia projects combined for 2014 was comparable with 2013, and represented 18% of the Company’s retail load requirement for 2014 and 17% for 2013. Total hydroelectric energy received exceeded that projected in PGE’s AUT by approximately 2% for 2014 and 1% for 2013. Based on recent forecasts of regional hydro conditions in 2015, energy from hydro resources is expected to be below normal levels.

The following table presents the forecast of the April-to-September 2015 runoff (issued February 10, 2015) compared to the actual runoffs for 2014 and 2013 (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):

	Runoff as a Percent of Normal *
Location	2015 Forecast		2014 Actual		2013 Actual
Columbia River at The Dalles, Oregon	92	%	108	%	100	%
Mid-Columbia River at Grand Coulee, Washington	96		110		108
Clackamas River at Estacada, Oregon	74		97		102
Deschutes River at Moody, Oregon	93		98		98

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

Energy received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) in 2014 decreased 2% from 2013, and represented 6% of the Company’s retail load requirement in each of those years. Energy received from wind generating resources fell short of projections included in the Company’s AUT by approximately 9% in 2014 compared with 15% in 2013.

Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, decreased $59 million for 2014 compared with 2013. The decrease was largely due to a 6% decline in the average variable power cost per MWh, combined with an 11% increase in the average price per MWh of wholesale power sales and a 7% increase in the volume of wholesale power sales. For 2014, actual NVPC was $7 million below baseline NVPC, compared with $11 million above for 2013.

Generation, transmission and distribution expense increased $32 million, or 14%, in 2014 compared with 2013. Storm related and service restoration costs were collectively $10 million higher primarily related to the Company’s service territory experiencing three major wind storms during the fourth quarter of 2014 ($5 million of which was offset by increased revenues utilizing the storm recovery mechanism); operating costs increased $7 million as a result of the Company’s ownership interest in Boardman increasing to 80% from 65% on December 31, 2013; and maintenance and overhaul expenses at PGE’s generation facilities were $6 million greater than in 2013. In addition, other distribution expenses were up $7 million, including $4 million of substation related expense; other generation expenses increased $3 million; and other transmission expenses increased $1 million. Partially offsetting these increases was a $3 million net decrease in 2014 due to expense taken in 2013 related to the Company’s benchmark bid for renewable resources pursuant to the 2009 IRP.

Cascade Crossing transmission project reflects $52 million of costs expensed in the second quarter of 2013, which were previously recorded as construction work-in-progress (CWIP). For additional information, see “Electric Utility Plant” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Administrative and other expense increased $8 million, or 4%, in 2014 compared with 2013. The increase was due in large part to $5 million more incentive compensation expense recorded in 2014 than in 2013 due to the higher net income in 2014. Additionally, customer service expenses, reflecting higher information technology costs, were $4 million higher in 2014, while medical premiums, rent and other items combined to increase expense $5 million. Partially offsetting these increases were a $3 million reduction in injuries and damages expense resulting from insurance recoveries related to prior year claims and a $3 million reduction in pension expense due to higher discount rates.

Depreciation and amortization expense in 2014 increased $53 million, or 21%, compared with 2013. In 2013, PGE deferred, for future recovery, $17 million of costs related to four capital projects as authorized in the Company’s 2011 GRC and in 2014 recorded $16 million of amortization expense related to the actual recovery of these costs (offset in Retail revenues). The addition of capital assets also contributed to an increase of $16 million in Depreciation and amortization expense year over year.

Taxes other than income taxes expense increased $6 million, or 6%, in 2014 compared with 2013, primarily due to higher property taxes, resulting from increases in appraised property values, along with an increase in payroll taxes.

Interest expense decreased $5 million, or 5%, in 2014 compared with 2013 as a $16 million reduction resulted from the higher allowance for borrowed funds used during construction due to the higher average CWIP balance, partially offset by an increase in interest expense from the higher average balance of debt outstanding in 2014, resulting from the construction of PW2, Carty, and Tucannon River.

Other income, net was $38 million in 2014 compared with $20 million in 2013. The increase was primarily due to a $24 million increase in the allowance for equity funds used during construction from the higher average CWIP balance, partially offset by a decrease in earnings from the Non-qualified benefit plan trust assets.

Income tax expense increased $40 million, or 190%, in 2014 compared to 2013, primarily due to the increase in pre-tax income in 2014 compared to 2013, which was driven in part by the charges to expense in 2013 related to Cascade Crossing and an industrial customer refund. The effective tax rate increased to 26.0% for 2014 from 16.8% for 2013 due primarily to the increase in pre-tax income and the smaller relative percentage thereof represented by federal and state tax credits, partially offset by the effect of increased AFDC equity.

2013 Compared to 2012

Revenues increased $5 million in 2013 compared with 2012 as a result of the items discussed below.

Total retail revenues decreased $31 million, or 2%, in 2013 compared with 2012, primarily due to the net effect of the following:

• A $38 million decrease resulting from lower average prices due primarily to lower expected power costs as established in the Company’s 2013 AUT and a larger portion of energy deliveries going to customers who purchase their energy from ESSs;

• A $9 million decrease related to an industrial customer refund for cumulative over-billings that occurred over a period of several years as a result of a meter configuration error. Management believes the customer billing error is not material to any past reporting period. The Company corrected this matter in the second quarter of 2013 through an out of period adjustment; and

• A $4 million decrease related to the Company’s PCAM, as the estimated refund to customers related to the 2011 PCAM was reduced in 2012, with no estimated refund to or collection from customers recorded in 2013; partially offset by

• A $20 million increase related to higher volumes of energy deliveries driven by more extreme weather in 2013 compared to 2012. Residential energy deliveries were up 2.6% in 2013, while commercial and industrial deliveries combined were comparable to 2012.

Both heating and cooling degree-days in 2013 exceeded the 15-year averages (as provided by the National Weather Service, as measured at Portland International Airport), while in 2012, both heating and cooling degree-days fell below the 15-year averages. The following table presents the number of heating and cooling degree-days for 2013 and 2012, along with the 15-year averages:

	Heating Degree-Days						Cooling Degree-Days
	2013		2012		Increase/(decrease)		2013		2012		Increase/(decrease)
1st quarter	1,902		1,967		(3	)%	—		—		—	%
2nd quarter	593		709		(16	)	82		40		105
3rd quarter	90		58		55		457		395		16
4th quarter	1,801		1,435		26		—		1		(100	)
	4,386		4,169		5		539		436		24
15-year annual average	4,239		4,235		—		454		456		—
Increase (decrease) from the 15-year annual average	3	%	(2	)%			19	%	(4	)%

On a weather adjusted basis, retail energy deliveries in 2013 were comparable to 2012, with energy deliveries to residential customers increasing by 1%, and energy deliveries to commercial and industrial customers combined were comparable to prior year.

Wholesale revenues in 2013 increased $31 million, or 63%, from 2012, which consisted of $29 million related to a 55% increase in the average wholesale price and $2 million related to a 5% increase in wholesale sales volume.

Other operating revenues increased $5 million, or 15%, in 2013 from 2012, primarily due to an increase in gains on the sale of excess natural gas, and an increase in the sale of oil, not needed for operations.

Purchased power and fuel expense increased $31 million, or 4%, in 2013 from 2012, largely due to a 4% increase in average variable power cost per MWh. Such increase was driven by a 16% increase in the cost of purchased power and a decrease in energy received from hydroelectric projects. In addition, during the second half of 2013, the Company experienced unplanned plant outages at three of its generating facilities and incurred $17 million of incremental replacement power costs. A 10% decrease in the average variable power cost per MWh of per generated partially offset the increases. The average variable power cost increased to $35.61 per MWh in 2013 from $34.25 per MWh in 2012.

Hydroelectric energy, from PGE-owned hydroelectric projects and from mid-Columbia projects combined, decreased 11% during 2013 from 2012 due to less favorable hydro conditions in 2013. Total hydroelectric energy received exceeded that projected in the Company’s AUT by approximately 1% for 2013 and 11% for 2012.

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The following table presents the actual of the April-to-September runoff for 2013 and 2012 (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):

	Runoff as a Percent of Normal *
Location	2013 Actual		2012 Actual
Columbia River at The Dalles, Oregon	100	%	126	%
Mid-Columbia River at Grand Coulee, Washington	108		129
Clackamas River at Estacada, Oregon	102		133
Deschutes River at Moody, Oregon	98		118

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

Energy received from PGE-owned wind generating resources (Biglow Canyon) increased 7% from 2012 due to unfavorable wind conditions in 2012, and represented 6% of the Company’s retail load requirement in 2013 and in 2012. Energy received from Biglow Canyon fell short of projections included in the Company’s AUT by approximately 15% in 2013 compared with 20% in 2012.

Actual NVPC for 2013 was comparable with 2012. A decrease driven by a 55% increase in the average variable power cost per MWh of wholesale power sales, was largely offset by a 4% increase in the average variable power cost per MWh. For 2013, actual NVPC was $11 million above baseline NVPC, compared with $17 million below baseline NVPC for 2012.

Generation, transmission and distribution expense increased $14 million, or 7%, in 2013 compared to 2012. The increase is largely due to $5 million related to planned overhaul and repair costs at Colstrip and Coyote Springs, $3 million related to increased delivery system repair and restoration work, $3 million for the warranty extension related to the third phase of Biglow Canyon, and $2 million of expense associated with the Company’s benchmark proposals that were not selected in the RFP process for new generation.

Cascade Crossing transmission project reflects $52 million of costs expensed in the second quarter of 2013, which were previously recorded as CWIP. For additional information, see “Electric Utility Plant” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Administrative and other expense increased $3 million, or 1%, in 2013 compared to 2012, as a $6 million increase in employee pension expense, driven by a lower discount rate, was partially offset by amortization of $3 million in 2012 of deferred costs related to the Trojan refund matter.

Depreciation and amortization expense in 2013 was comparable to 2012, as a $7 million increase resulting from capital additions was largely offset by an increase in costs deferred related to four capital projects as authorized in the Company’s 2011 GRC, a decrease in the asset retirement obligation (ARO) resulting from the decommissioning of the Bull Run hydro facility in 2012, and the amortization in 2012 of tax credits related to the ISFSI located at the former Trojan site.

Interest expense decreased $7 million, or 6%, in 2013 compared to 2012, and consisted of $4 million related to the timing of the 2013 maturities and issuances of long-term debt and $3 million related to an increase in the allowance for borrowed funds used for construction, which was driven by a higher average CWIP balance resulting from the commencement of the construction of PW2, Carty, and Tucannon River in 2013.

Other income, net was $20 million in 2013 compared to $10 million in 2012. The increase was primarily due to a $7 million increase in the allowance for equity funds used for construction from the higher average CWIP balance, as well as an increase in earnings from the non-qualified benefit plan trust assets.

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Income tax expense decreased $43 million, or 67%, in 2013 compared with 2012, with the effective tax rate decreasing to 16.8% for 2013 from 31.4% for 2012. These decreases are primarily due to a decrease in the pre-tax income for 2013 compared with 2012, which was driven by the $52 million charge to expense in 2013 related to Cascade Crossing, combined with other unfavorable impacts to 2013 pre-tax income. Also contributing to the decreases was an increase to deferred tax balances in 2012 for a change in the Company’s composite state tax rate and an increase in production tax credits in 2013.

Liquidity and Capital Resources

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

Capital Requirements

The following table presents actual capital expenditures and debt maturities for 2014 and projected capital expenditures and future debt maturities for 2015 through 2019 (in millions, excluding allowance for funds used during construction, or AFDC):

	Years Ending December 31,
	2014			2015		2016		2017		2018		2019
Ongoing capital expenditures	$	310		$	386	$	353	$	339	$	300	$	300
Port Westward Unit 2	118			20		—		—		—		—
Tucannon River Wind Farm	380			29		—		—		—		—
Carty Generating Station	108			172		35		—		—		—
Hydro licensing and construction	32			22		10		2		1		2
Total capital expenditures	$	948	*	$	629	$	398	$	341	$	301	$	302
Long-term debt maturities	$	—		$	375	$	67	$	58	$	75	$	300

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

For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in this Item 7.

Ongoing capital expenditures—Consists of upgrades to and replacement of transmission, distribution, and generation infrastructure as well as new customer connections. For the years 2015 through 2017, approximately $100 million relates to the implementation of the Company’s new customer information and meter data management systems.

Port Westward Unit 2—PW2 is a 220 MW natural gas-fired capacity resource located adjacent to PW1 and Beaver near Clatskanie, Oregon that was placed in service in December 2014. As of December 31, 2014, $295 million is included in Electric utility plant for PW2, including $20 million of AFDC. The Company estimates that final completion of the plant will require approximately$20 million of capital expenditures in 2015.

Tucannon River Wind Farm—Tucannon River is a 267 MW nameplate capacity wind farm, consisting of 116 turbines each with a generating capacity of 2.3 MWs, located in southeastern Washington. This renewable resource was placed in service in December 2014. As of December 31, 2014, $501 million is included in Electric utility plant for Tucannon River, including $24 million of AFDC and net of a state sales tax refund of $23 million from the state

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of Washington. The Company estimates that final completion of the wind farm will require approximately $29 million of capital expenditures in 2015.

Carty Generating Station—Carty is a 440 MW natural gas-fired baseload resource in Eastern Oregon, located adjacent to Boardman. The total cost of Carty is estimated at $450 million, excluding AFDC, and the facility is expected to be online in the second quarter of 2016. As of December 31, 2014, $260 million, including $16 million of AFDC, is included in CWIP for Carty.

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

Liquidity

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

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

	Years Ended December 31,
	2014			2013			2012
Cash and cash equivalents, beginning of year	$	107		$	12		$	6
Net cash provided by (used in):
Operating activities	518			544			494
Investing activities	(994		)	(692		)	(294		)
Financing activities	496			243			(194		)
Net change in cash and cash equivalents	20			95			6
Cash and cash equivalents, end of year	$	127		$	107		$	12

2014 Compared to 2013

Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The $26 million decrease in cash flows from operating activities in 2014 compared to 2013 was largely due to a decrease in the net change in working capital items, and a decrease in the amount received related to the settlement of a legal matter concerning costs associated with the operation of the ISFSI. These decreases were partially offset by an increase to Net income, net of non-cash items, and an increase in cash received from the Bonneville Power Administration to be returned to customers pursuant to the Residential Exchange Program.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 2015 will range from $300 million to $310 million. Combined with all other sources, cash provided by operations in 2015 is estimated to range from $460 million to $500 million. This estimate anticipates no change in margin deposits held by brokers as of December 31, 2014, which is based on both the timing of contract settlements and projected energy prices. The remaining estimated cash flows from operations in 2015 is expected from normal operating activities.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. The $302 million increase in net cash used in investing activities in 2014 compared to 2013 was primarily due to a $351 million increase in capital expenditures, largely due to the construction of three new generation projects (PW2, Carty and Tucannon River), partially offset by a decrease in contributions to the Nuclear decommissioning trust. For additional information regarding the contributions to the Nuclear decommissioning trust, see Note 3, Balance Sheet Components, and Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

The Company plans approximately $629 million of capital expenditures in 2015 related to upgrades to and replacement of generation, transmission, and distribution infrastructure, including $172 million related to the

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construction of Carty. PGE plans to fund the 2015 capital expenditures with the cash expected to be generated from operations during 2015, as discussed above, as well as with the issuance of debt and equity securities. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2014, cash provided by such activities consisted of net proceeds received from the issuances of term bank loans of $305 million and FMBs of $280 million, partially offset by the payment of dividends of $87 million. During 2013, net cash provided by financing activities consisted of net proceeds received from the issuances of common stock in the amount of $67 million and FMBs in the aggregate amount of $377 million, partially offset by the repayment of FMBs of $100 million and commercial paper of $17 million, and payment of dividends of $84 million.

2013 Compared to 2012

Cash Flows from Operating Activities—The $50 million increase in cash flows from operating activities in 2013 compared to 2012 was largely due to the receipt of $44 million in the third quarter of 2013 related to the settlement of a legal matter concerning costs associated with the operation of the ISFSI. Such amount was transferred into the Nuclear decommissioning trust, and consequently is also reflected as an outflow of cash for investing activities. The net change in working capital items, partially offset by a decrease in Net income after the consideration of non-cash items, also contributed to the increase in cash flows from operating activities.

Cash Flows from Investing Activities—The $398 million increase in net cash used in investing activities in 2013 compared to 2012 was primarily due to a $353 million increase in capital expenditures, largely due to the construction of three new generation projects (PW2, Carty and Tucannon River), and a $44 million contribution to the Nuclear decommissioning trust in the third quarter of 2013.

Cash Flows from Financing Activities—During 2013, cash provided by financing activities consisted of net proceeds received from the issuances of common stock in the aggregate amount of $67 million and FMBs in the aggregate amount of $377 million, partially offset by the repayment of FMBs of $100 million and commercial paper of $17 million, and payment of dividends of $84 million. During 2012, net cash used in financing activities consisted of the repayment of FMBs of $100 million, payment of dividends of $81 million and net maturities of commercial paper of $13 million.

Dividends on Common Stock

The following table presents common stock dividends declared in 2014:

Declaration Date	Record Date	Payment Date	Declared Per Common Share
February 19, 2014	March 25, 2014	April 15, 2014	$	0.275
May 7, 2014	June 25, 2014	July 15, 2014	0.280
July 24, 2014	September 25, 2014	October 15, 2014	0.280
October 23, 2014	December 26, 2014	January 15, 2015	0.280

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

Credit Ratings and Debt Covenants

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

	Moody’s	S&P
First Mortgage Bonds	A1	A-
Senior unsecured debt	A3	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

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

As of December 31, 2014, PGE had posted approximately $41 million of collateral with these counterparties, consisting of $11 million in cash and $30 million in bank letters of credit, $11 million of which is related to master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2014, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $112 million and decreases to approximately $57 million by December 31, 2015. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $247 million and decreases to approximately $119 million by December 31, 2015.

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

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The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2014, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $685 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65% of total capitalization (debt to total capital ratio). As of December 31, 2014, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 56.7%.

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors. Management believes that the availability of revolving credit facilities, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. For 2015, PGE expects to fund estimated capital requirements and maturities of long-term debt with cash from operations, issuances of debt securities of up to $300 million and issuances of equity securities under the EFSA of approximately $270 million. The actual timing and amount of such issuances of debt and equity securities will be dependent upon the timing and amount of capital expenditures.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $900 million through February 6, 2016 and had the following unsecured revolving credit facilities as of December 31, 2014:

• A $400 million revolving credit facility, which is scheduled to terminate in November 2018; and

• A $300 million revolving credit facility, which is scheduled to terminate in December 2017.

These revolving credit facilities supplement operating cash flows and provide a primary source of liquidity. Pursuant to the terms of the agreements, the revolving credit facilities may be used for general corporate purposes, backup for commercial paper borrowings, and the issuance of standby letters of credit.

As of December 31, 2014, PGE had no borrowings outstanding under the revolving credit facilities, no commercial paper outstanding, and $20 million of letters of credit issued. As of December 31, 2014, the aggregate unused available credit under the revolving credit facilities was $680 million.

The Company also has two letter of credit facilities under which it may obtain letters of credit in an aggregate amount not to exceed $60 million. Under these facilities, an additional $56 million of letters of credit was outstanding as of December 31, 2014.

Long-term Debt. During 2014, PGE issued a total of $280 million of FMBs, consisting of the following:

• In November, issued $80 million of 3.51% Series FMBs due 2024;

• In October, issued $100 million of 4.44% Series FMBs due 2046; and

• In August, issued $100 million of 4.39% Series FMBs due 2045.

In January 2015, the Company repaid $70 million of 3.46% Series FMBs and issued $75 million of 3.55% Series FMBs due 2030.

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In addition to the issuances of FMBs, PGE obtained four term loans in an aggregate principal amount of $305 million during 2014 pursuant to a credit agreement. The term loan interest rates are set at the beginning of the interest period for periods ranging from one- to six-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 70 basis points, with no other fees. The credit agreement expires October 30, 2015, at which time any amounts outstanding under the term loans become due and payable.

As of December 31, 2014, total long-term debt outstanding was $2,501 million, with scheduled maturities of $375 million in 2015. In addition, PGE has the option to remarket through 2033 the $21 million of Pollution Control Revenue Bonds held by the Company.

Equity. In connection with PGE’s public offering of 11,100,000 shares of its common stock in 2013, the Company entered into an EFSA. Pursuant to the EFSA, a forward counterparty borrowed 11,100,000 shares of PGE’s common stock from third parties and such borrowed shares were sold in a registered public offering. PGE receives proceeds from the sale of the common stock when the EFSA is physically settled. As of December 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares of PGE common stock to the forward counterparty in exchange for cash of $275 million. The Company anticipates physical settlement of the EFSA by delivery of newly issued shares on or before the EFSA’s expiration date of June 11, 2015. For additional information on the EFSA, see Note 12, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective helps the Company maintain investment grade debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratios were 43.3% and 48.7% as of December 31, 2014 and 2013, respectively.

Contractual Obligations and Commercial Commitments

The following table presents PGE’s contractual obligations as of December 31, 2014 (in millions):

	2015		2016		2017		2018		2019		There- after		Total
Long-term debt	$	375	$	67	$	58	$	75	$	300	$	1,626	$	2,501
Interest on long-term debt *	118		112		110		106		92		1,557		2,095
Capital and other purchase commitments	242		21		2		2		2		74		343
Purchased power and fuel:
Electricity purchases	179		167		140		143		143		833		1,605
Capacity contracts	27		26		6		6		5		20		90
Public Utility Districts	8		7		5		4		2		23		49
Natural gas	56		37		40		40		36		244		453
Coal and transportation	23		14		11		5		5		—		58
Operating leases	10		11		12		11		8		192		244
Total	$	1,038	$	462	$	384	$	392	$	593	$	4,569	$	7,438

* 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, 2014.

As of December 31, 2014, no contributions to PGE’s pension plan are expected for 2015 through 2019. Contributions beyond 2019 are not estimated due to significant uncertainty in financial market and demographic outcomes.

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Other Financial Obligations

PGE has entered into long-term power purchase agreements with certain public utility districts in the state of Washington under which it has acquired a percentage of the output of three hydroelectric projects (the Priest Rapids, Wanapum and Wells hydroelectric projects). The Company is required to pay its proportionate share of the operating and debt service costs of the projects whether or not they are operable. The agreements further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of both the output and the operating and debt service costs of the defaulting purchaser. For the Wells project, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage of the output. For the Priest Rapids and Wanapum projects, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt. For additional information on these long-term power purchase agreements, see “Public Utility Districts” in Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Off-Balance Sheet Arrangements

PGE entered into an EFSA in connection with a registered public offering of its common stock in 2013. The Company may settle the EFSA with issuance of PGE common stock, for cash or net share settlement from time-to-time, in whole or part, through June 11, 2015. For additional information on the EFSA, see Note 12, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

Critical Accounting Policies

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

Regulatory Accounting

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

If future recovery of regulatory assets is not probable, PGE would expense such items in the period such determination is made. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting.

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Discontinued application of regulatory accounting would have a material impact on the Company’s results of operations and financial position.

Asset Retirement Obligations

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

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

Revenue Recognition

Retail customers are billed monthly for electricity use based on meter readings taken throughout the month. At the end of each month, PGE estimates the revenue earned from the last meter read date through the last day of the month, which has not yet been billed to customers. Such amount, which is classified as Unbilled revenues in the Company’s consolidated balance sheets, is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current customer prices.

Contingencies

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

Price Risk Management

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

Fair value adjustments consist of reevaluating the fair value of derivative contracts at the end of each reporting period for the remaining term of the contract and recording any change in fair value in Net income for the period. Fair value is the present value of the difference between the contracted price and the forward market price

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multiplied by the total quantity of the contract. For option contracts, a theoretical value is calculated using Black-Scholes models that utilize price volatility, price correlation, time to expiration, interest rate and forward commodity price curves. The fair value of these options is the difference between the premium paid or received and the theoretical value at the fair value measurement date.

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

Pension Plan

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

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

Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets, or reduction in the discount rate, would have the effect of increasing the 2014 net periodic pension expense by approximately $2 million.

Fair Value Measurements

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

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

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

Risk Management Committee

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

Commodity Price Risk

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

The following table presents energy commodity derivative fair values as a net liability as of December 31, 2014 that are expected to settle in each respective year (in millions):

	2015		2016		2017		2018		2019		Thereafter		Total
Commodity contracts:
Electricity	$	50	$	19	$	6	$	5	$	5	$	22	$	107
Natural gas	49		44		18		3		—		—		114
	$	99	$	63	$	24	$	8	$	5	$	22	$	221

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

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

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Foreign Currency Exchange Rate Risk

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

As of December 31, 2014, a 10% change in the value of the Canadian dollar would result in an immaterial change in exposure for transactions that will settle over the next twelve months.

Interest Rate Risk

To meet short-term cash requirements, PGE has the ability to issue commercial paper for terms of up to 270 days and has revolving credit facilities that permit same day borrowings. Although any borrowings under the commercial paper program or the revolving credit facilities carry a fixed rate during their respective terms, the short-term nature of such borrowings subjects the Company to fluctuations in interest rates that result from changes in market conditions. As of December 31, 2014, PGE had no borrowings outstanding under its revolving credit facilities and no commercial paper outstanding.

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

As of December 31, 2014, the total fair value and carrying amounts by maturity date of PGE’s long-term debt are as follows (in millions): 

	Total Fair Value		Carrying Amounts by Maturity Date
			Total		2015		2016		2017		2018		There- after
First Mortgage Bonds	$	2,460	$	2,075	$	70	$	67	$	58	$	75	$	1,805
Unsecured term bank loans	305		305		305		—		—		—		—
Pollution Control Revenue Bonds	136		121		—		—		—		—		121
Total	$	2,901	$	2,501	$	375	$	67	$	58	$	75	$	1,926

As of December 31, 2014, PGE’s unsecured term bank loans in the amount of $305 million were the only long-term debt instruments subject to interest rate risk exposures. As of December 31, 2014, a 10% change in the interest rate of these unsecured term bank loans would result in an immaterial change in interest rate risk exposure over the next twelve months.

Credit Risk

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

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

60

As of December 31, 2014, PGE’s credit risk exposure is $4 million for commodity activities with externally-rated investment grade counterparties and matures in 2016. The credit risk is included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

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

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

61

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

Report of Independent Registered Public Accounting Firm	63
Consolidated Statements of Income for the years ended December 31, 2014, 2013, and 2012	65
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013, and 2012	66
Consolidated Balance Sheets as of December 31, 2014 and 2013	67
Consolidated Statements of Equity for the years ended December 31, 2014, 2013, and 2012	69
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013, and 2012	70
Notes to Consolidated Financial Statements	72

62

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Portland General Electric Company

Portland, Oregon

We have audited the accompanying consolidated balance sheets of Portland General Electric Company and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. We also have audited the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

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

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

63

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 12, 2015

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

	Years Ended December 31,
	2014			2013			2012
Revenues, net	$	1,900		$	1,810		$	1,805
Operating expenses:
Purchased power and fuel	713			757			726
Generation, transmission and distribution	257			225			211
Cascade Crossing transmission project	—			52			—
Administrative and other	227			219			216
Depreciation and amortization	301			248			248
Taxes other than income taxes	109			103			102
Total operating expenses	1,607			1,604			1,503
Income from operations	293			206			302
Interest expense, net	96			101			108
Other income:
Allowance for equity funds used during construction	37			13			6
Miscellaneous income, net	1			7			4
Other income, net	38			20			10
Income before income taxes	235			125			204
Income tax expense	61			21			64
Net income	174			104			140
Less: net loss attributable to noncontrolling interests	(1		)	(1		)	(1		)
Net income attributable to Portland General Electric Company	$	175		$	105		$	141
Weighted-average shares outstanding (in thousands):
Basic	78,180			76,821			75,498
Diluted	80,494			77,388			75,647
Earnings per share:
Basic	$	2.24		$	1.36		$	1.87
Diluted	$	2.18		$	1.35		$	1.87

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Years Ended December 31,
	2014			2013			2012
Net income	$	174		$	104		$	140
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of $2 in 2014 and ($1) in 2013	(2		)	1			—
Comprehensive income	172			105			140
Less: comprehensive loss attributable to the noncontrolling interests	(1		)	(1		)	(1		)
Comprehensive income attributable to Portland General Electric Company	$	173		$	106		$	141

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	As of December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	127		$	107
Accounts receivable, net	149			146
Unbilled revenues	93			104
Inventories, at average cost:
Materials and supplies	42			41
Fuel	40			24
Regulatory assets—current	133			66
Other current assets	115			103
Total current assets	699			591
Electric utility plant:
Generation	3,742			2,968
Transmission	440			417
Distribution	3,075			2,943
General	426			381
Intangible	478			386
Construction work-in-progress	417			508
Total electric utility plant	8,578			7,603
Accumulated depreciation and amortization	(2,899		)	(2,723		)
Electric utility plant, net	5,679			4,880
Regulatory assets—noncurrent	494			464
Nuclear decommissioning trust	90			82
Non-qualified benefit plan trust	32			35
Other noncurrent assets	48			49
Total assets	$	7,042		$	6,101

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(In millions, except share amounts)

	As of December 31,
	2014			2013
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	156		$	173
Liabilities from price risk management activities—current	106			49
Current portion of long-term debt	375			—
Accrued expenses and other current liabilities	236			171
Total current liabilities	873			393
Long-term debt, net of current portion	2,126			1,916
Regulatory liabilities—noncurrent	906			865
Deferred income taxes	625			586
Unfunded status of pension and postretirement plans	237			154
Liabilities from price risk management activities—noncurrent	122			141
Asset retirement obligations	116			100
Non-qualified benefit plan liabilities	105			101
Other noncurrent liabilities	21			25
Total liabilities	5,131			4,281
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	—			—
Common stock, no par value, 160,000,000 shares authorized; 78,228,339 and 78,085,559 shares issued and outstanding as of December 31, 2014 and 2013, respectively	918			911
Accumulated other comprehensive loss	(7		)	(5		)
Retained earnings	1,000			913
Total Portland General Electric Company shareholders’ equity	1,911			1,819
Noncontrolling interests’ equity	—			1
Total equity	1,911			1,820
Total liabilities and equity	$	7,042		$	6,101

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions, except share and per share amounts)

	Portland General Electric Company Shareholders’ Equity
	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Shares	Amount
Balance as of December 31, 2011	75,362,956	$	836	$	(6	)	$	833		$	3
Shares issued pursuant to equity-based plans	193,316	1		—			—			—
Stock-based compensation	—	4		—			—			—
Dividends declared ($1.075 per share)	—	—		—			(81		)	—
Net income (loss)	—	—		—			141			(1		)
Balance as of December 31, 2012	75,556,272	841		(6		)	893			2
Issuances of common stock, net of issuance costs of $3	2,365,000	67		—			—			—
Shares issued pursuant to equity-based plans	164,287	1		—			—			—
Stock-based compensation	—	2		—			—			—
Dividends declared ($1.095 per share)	—	—		—			(85		)	—
Net income (loss)	—	—		—			105			(1		)
Other comprehensive income	—	—		1			—			—
Balance as of December 31, 2013	78,085,559	911		(5		)	913			1
Shares issued pursuant to equity-based plans	142,780	1		—			—			—
Stock-based compensation	—	6		—			—			—
Dividends declared ($1.115 per share)	—	—		—			(88		)	—
Net income (loss)	—	—		—			175			(1		)
Other comprehensive loss	—	—		(2		)	—			—
Balance as of December 31, 2014	78,228,339	$	918	$	(7	)	$	1,000		$	—

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2014			2013			2012
Cash flows from operating activities:
Net income	$	174		$	104		$	140
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	301			248			248
Increase (decrease) in net liabilities from price risk management activities	45			(18		)	(175		)
Regulatory deferrals—price risk management activities	(45		)	18			172
Cascade Crossing transmission project	—			52			—
Deferred income taxes	39			11			47
Allowance for equity funds used during construction	(37		)	(13		)	(6		)
Pension and other postretirement benefits	33			37			27
Regulatory deferral of settled derivative instruments	10			7			(9		)
Unrealized losses on non-qualified benefit plan trust assets	7			3			3
Decoupling mechanism deferrals, net of amortization	6			(6		)	2
Power cost deferrals, net of amortization	—			(6		)	(4		)
Other non-cash income and expenses, net	12			18			17
Changes in working capital, net of effects from purchase of 10% interest in Boardman:
Decrease (increase) in receivables and unbilled revenues	8			—			(4		)
(Increase) decrease in margin deposits	(2		)	37			34
Income tax refund received	—			—			8
(Decrease) increase in payables and accrued liabilities	(13		)	14			1
Other working capital items, net	(12		)	17			1
Cash received to be returned to customers pursuant to the Residential Exchange Program	13			1			—
Proceeds received from Trojan spent fuel legal settlement	6			44			—
Contribution to non-qualified employee benefit trust	(8		)	(6		)	—
Contribution to voluntary employees’ benefit association trust	(3		)	(3		)	(2		)
Other, net	(16		)	(15		)	(6		)
Net cash provided by operating activities	518			544			494
Cash flows from investing activities:
Capital expenditures	(1,007		)	(656		)	(303		)
Purchases of nuclear decommissioning trust securities	(19		)	(26		)	(26		)
Sales of nuclear decommissioning trust securities	17			25			23
Contribution to nuclear decommissioning trust	(6		)	(44		)	—
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid	8			—			—
Proceeds received from insurance recoveries	3			6			—
Proceeds from sale of properties	5			—			10
Other, net	5			3			2
Net cash used in investing activities	(994		)	(692		)	(294		)
See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

	Years Ended December 31,
	2014			2013			2012
Cash flows from financing activities:
Proceeds from issuance of long-term debt	$	585		$	380		$	—
Payments on long-term debt	—			(100		)	(100		)
Proceeds from issuances of common stock, net of issuance costs	—			67			—
Borrowings on short-term debt	—			35			—
Payments on short-term debt	—			(35		)	—
Maturities of commercial paper, net	—			(17		)	(13		)
Dividends paid	(87		)	(84		)	(81		)
Debt issuance costs	(2		)	(3		)	—
Net cash provided by (used in) financing activities	496			243			(194		)
Increase in cash and cash equivalents	20			95			6
Cash and cash equivalents, beginning of year	107			12			6
Cash and cash equivalents, end of year	$	127		$	107		$	12
Supplemental disclosures of cash flow information:
Cash paid for:
Interest, net of amounts capitalized	$	86		$	90		$	97
Income taxes	22			10			13
Non-cash investing and financing activities:
Accrued capital additions	70			84			19
Accrued dividends payable	23			22			21
Accrued sales tax refund related to Tucannon River Wind Farm	23			—			—
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	—			9			—

See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BASIS OF PRESENTATION

Nature of Operations

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power marketers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of December 31, 2014, PGE served 842,273 retail customers with a service area population of approximately 1.8 million, comprising approximately 46% of the state’s population.

As of December 31, 2014, PGE had 2,600 employees, with 780 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 743 and 37 employees and expire in February 2016 and August 2017, respectively.

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

Consolidation Principles

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

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

Use of Estimates

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

Customer Billing Matter

In May 2013, PGE discovered that it had over-billed an industrial customer during a period of several years as a result of a meter configuration error. An analysis of the data determined that the Company’s revenues were overstated by approximately $3 million in 2012 and in 2011, $2 million in 2010, and $1 million in 2009. PGE

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

believes the customer billing error is not material to any annual reporting period. The Company corrected this matter in the second quarter of 2013 as an out of period adjustment, and recorded, as a reduction to Revenues, net, a refund to the customer in the amount of $9 million.

Reclassifications

To conform with the 2014 presentation, PGE has reclassified Margin deposits of $9 million with Other current assets in the consolidated balance sheet as of December 31, 2013. In addition, the Company reclassified Renewable adjustment clause deferrals of $1 million to Other non-cash income and expenses, net in the operating activities section of the consolidated statement of cash flows for the year ended December 31, 2012 and separately presented Cash received to be returned to customers pursuant to the Residential Exchange Program of $1 million from Other non-cash income and expenses, net for the year ended December 31, 2013.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $120 million and $104 million as of December 31, 2014 and 2013, respectively.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice.

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

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2014, 2013 and 2012.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument.

Electricity sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets and were $11 million and $9 million as of December 31, 2014 and 2013, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $30 million and $29 million as of December 31, 2014 and 2013, respectively.

Inventories

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

Electric Utility Plant

Capitalization Policy

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

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted.

During the year ended December 31, 2013, PGE charged $52 million of costs previously included in CWIP related to the Cascade Crossing Transmission Project (Cascade Crossing), which was originally proposed as a 215-mile, 500 kV transmission project between Boardman, Oregon and Salem, Oregon. Based on an updated forecast of demand and future transmission capacity in the region, PGE determined in the second quarter of 2013 that the original projections of transmission capacity limitations contemplated in the Company’s 2009 Integrated Resource Plan, as acknowledged by the OPUC, were not likely to fully materialize. As a result, PGE and Bonneville Power Administration (BPA) worked toward refining the scope of the project and executed a non-binding memorandum of understanding (MOU) in May 2013. In connection with the MOU, the parties explored a new option under which BPA could provide PGE with ownership of approximately 1,500 MW of transmission capacity rights. As a result of the changed conditions reflected in the MOU, PGE also suspended permitting and development of Cascade

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

Crossing and charged the capitalized costs related to Cascade Crossing to expense in the second quarter of 2013. In October 2013, the parties determined that they would not be able to reach an agreement on the financial terms for the proposed ownership of transmission capacity rights and, therefore, agreed to discontinue discussions on this option. The Company has determined that, under current conditions, the best option for meeting its transmission needs is to continue to acquire transmission service offered under BPA’s Open Access Transmission Tariff. PGE has determined that it will not seek recovery of these costs.

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.4% in 2014, and 7.5% in 2013 and in 2012. AFDC from borrowed funds was $22 million in 2014, $7 million in 2013, and $4 million in 2012 and is reflected as a reduction to Interest expense. AFDC from equity funds was $37 million in 2014, $13 million in 2013, and $6 million in 2012 and is included in Other income, net.

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

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2014, 3.7% in 2013, and 3.8% in 2012. Estimated asset retirement removal costs included in depreciation expense were $57 million in 2014, and $55 million in 2013 and in 2012.

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recent depreciation study was completed for 2013, with an order received from the OPUC in September 2014 authorizing new depreciation rates effective January 1, 2015.

Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):

Generation, excluding thermal:
Hydro	87
Wind	27
Transmission	53
Distribution	40
General	13

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

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $191 million and $170 million as of December 31, 2014 and 2013, respectively, with amortization expense of $25 million in 2014, and $22 million in 2013 and in 2012. Future

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estimated amortization expense as of December 31, 2014 is as follows: $35 million in 2015; $33 million in 2016; $29 million in 2017; $28 million in 2018; and $22 million in 2019.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.

Regulatory Accounting

Regulatory Assets and Liabilities

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

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

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

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

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To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while 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. PGE’s authorized ROE was 9.75% for 2014, and 10% for 2013 and for 2012.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review.

For 2014, actual NVPC was below baseline NVPC by $7 million, which is within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2014. A final determination regarding the 2014 PCAM results will be made by the OPUC through a public filing and review in 2015.

For 2013, actual NVPC was above baseline NVPC by $11 million, which is within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2013. A final determination regarding the 2013 PCAM results was made by the OPUC through a public filing and review in 2014, which confirmed no collection from customers pursuant to the PCAM for 2013.

For 2012, actual NVPC was below baseline NVPC by $17 million, and exceeded the lower deadband threshold of $15 million. However, based on results of the regulated earnings test, no estimated refund to customers was recorded as of December 31, 2012. A final determination regarding the 2012 PCAM results was made by the OPUC through a public filing and review in 2013, which confirmed no refund to customers pursuant to the PCAM for 2012.

Asset Retirement Obligations

Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheet. An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is classified as Depreciation and amortization expense in the Company’s consolidated statements of income.

The difference between the timing of the recognition of the AROs’ depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. PGE had a regulatory liability related to AROs in the amount of $39 million as of December 31, 2014 and 2013. See Note 6, Regulatory Assets and Liabilities.

Contingencies

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been

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impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred.

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

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

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

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $42 million in 2014, $41 million in 2013, and $42 million in 2012.

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

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

Stock-Based Compensation

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

Income Taxes

Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected

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to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $86 million and $76 million as of December 31, 2014 and 2013, respectively, and will be included in prices when the temporary differences reverse.

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

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

Recent Accounting Pronouncement

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations in the contract; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which is January 1, 2017 for the Company, with early adoption prohibited. The impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows of the adoption of ASU 2014-09 is not known at this time.

NOTE 3: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of December 31, 2014 and 2013. The following is the activity in the allowance for uncollectible accounts (in millions):

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	6		$	5		$	6
Increase in provision	6			6			6
Amounts written off, less recoveries	(6		)	(5		)	(7		)
Balance as of end of year	$	6		$	6		$	5

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Trust Accounts

PGE maintains two trust accounts as follows:

Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust includes amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein. In 2014 and 2013, the Company received $6 million and $44 million, respectively, from the settlement of a legal matter concerning costs associated with the operation of the ISFSI. Those funds were deposited into the Nuclear decommissioning trust. For additional information concerning the legal matter, see Note 7, Asset Retirement Obligations.

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

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

	Nuclear     Decommissioning Trust				Non-Qualified Benefit     Plan Trust
	2014		2013		2014		2013
Cash equivalents	$	65	$	59	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		6		8
Debt securities	25		23		—		1
Insurance contracts, at cash surrender value	—		—		26		26
	$	90	$	82	$	32	$	35

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

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Other Current Assets and Accrued Expenses and Other Current Liabilities

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

	As of December 31,
	2014		2013
Other current assets:
Prepaid expenses	$	39	$	38
Current deferred income tax asset	33		42
Accrued sales tax refund related to Tucannon River Wind Farm	23		—
Margin deposits	11		9
Assets from price risk management activities	6		13
Other	3		1
	$	115	$	103
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	60	$	1
Accrued employee compensation and benefits	51		46
Accrued interest payable	26		23
Dividends payable	23		22
Accrued taxes payable	22		21
Other	54		58
	$	236	$	171

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2014 and 2013, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

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

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

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

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

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were

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no significant transfers between levels during the years ended December 31, 2014 and 2013, except those transfers from Level 3 to Level 2 presented in this note.

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

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	65	$	—	$	65
Debt securities:
Domestic government	7		7		—		14
Corporate credit	—		11		—		11
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		1		—		5
International	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		4		1		5
Natural gas	—		2		—		2
	$	12	$	90	$	1	$	103
Liabilities - Liabilities from price risk management activities(1) (3):
Electricity	$	—	$	32	$	80	$	112
Natural gas	—		95		21		116
	$	—	$	127	$	101	$	228

(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 $26 million, which are recorded at cash surrender value.

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

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	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	6		8		—		14
Corporate credit	—		9		—		9
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		3		—		7
International	1		—		—		1
Debt securities - domestic government	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		9		1		10
Natural gas	—		4		—		4
	$	12	$	92	$	1	$	105
Liabilities - Liabilities from price risk management activities (1) (3):
Electricity	$	—	$	10	$	117	$	127
Natural gas	—		40		23		63
	$	—	$	50	$	140	$	190

(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 $26 million, which are recorded at cash surrender value.

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

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

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

Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.

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

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Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace.

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

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

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures and swaps.

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Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:

						Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)
As of December 31, 2014:
Electricity physical forward	$	—	$	77	Discounted cash flow	Electricity forward price (per MWh)	$	11.97	$	122.72	$	37.43
Natural gas financial swaps	—		21		Discounted cash flow	Natural gas forward price (per Dth)	2.88		4.86		3.41
Electricity financial futures	1		3		Discounted cash flow	Electricity forward price (per MWh)	11.97		39.26		27.88
	$	1	$	101
As of December 31, 2013:
Electricity physical forward	$	—	$	103	Discounted cash flow	Electricity forward price (per MWh)	$	9.63	$	77.95	$	40.18
Natural gas financial swaps	—		23		Discounted cash flow	Natural gas forward price (per Dth)	3.16		4.49		3.71
Electricity financial futures	1		14		Discounted cash flow	Electricity forward price (per MWh)	9.63		46.07		33.01
	$	1	$	140

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, the Company uses internally-developed price curves that employ the mid-point of the market’s bid-ask spread derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These internally-developed price curves are validated against nonbinding broker quotes, market data from a regulated exchange and benchmark price assessments from a pricing vendor. For certain longer term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such circumstances, the Company uses internally-developed price curves, which utilize observable data and regression techniques to derive future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):

	Years Ended December 31,
	2014			2013
Net liabilities from price risk management activities as of beginning of year	$	139		$	16
Net realized and unrealized losses *	15			134
Settlements	(4		)	(1		)
Net transfers out of Level 3 to Level 2	(50		)	(10		)
Net liabilities from price risk management activities as of end of year	$	100		$	139
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	12		$	133

* Includes realized losses, net of $3 million in 2014 and $1 million in 2013.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans is classified as Level 3 fair value measurement and is estimated based on the terms of the loans and the Company’s creditworthiness. These significant unobservable inputs to the Level 3 fair value measurement include the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximates their carrying value.

As of December 31, 2014, the carrying amount of PGE’s long-term debt was $2,501 million and its estimated aggregate fair value was $2,901 million, consisting of $2,596 million and $305 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2013, the carrying amount of PGE’s long-term debt was $1,916 million and its estimated aggregate fair value was $2,074 million, all classified as Level 2 in the fair value hierarchy.

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

NOTE 5: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generating resources combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include fuel and power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing

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business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, where adverse changes in prices and/or rates may affect the Company’s financial position, performance, or cash flow.

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

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

	As of December 31,
	2014			2013
Current assets:
Commodity contracts:
Electricity	$	4		$	9
Natural gas	2			4
Total current derivative assets	6		(1)	13		(1)
Noncurrent assets:
Commodity contracts:
Electricity	1			1
Total noncurrent derivative assets	1		(2)	1		(2)
Total derivative assets not designated as hedging instruments	$	7		$	14
Total derivative assets	$	7		$	14
Current liabilities:
Commodity contracts:
Electricity	$	54		$	20
Natural gas	52			29
Total current derivative liabilities	106			49
Noncurrent liabilities:
Commodity contracts:
Electricity	58			107
Natural gas	64			34
Total noncurrent derivative liabilities	122			141
Total derivative liabilities not designated as hedging instruments	$	228		$	190
Total derivative liabilities	$	228		$	190

(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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PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): 

	As of December 31,
	2014			2013
Commodity contracts:
Electricity	16		MWh	14		MWh
Natural gas	127		Dth	106		Dth
Foreign currency exchange	$	7	Canadian	$	7	Canadian

PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table below.

Information related to price risk management liabilities subject to master netting agreements is as follows (in millions):

	Gross		Gross		Net		Gross Amounts Not Offset in
	Amounts		Amounts		Amounts		Consolidated Balance Sheets
	Recognized		Offset		Presented		Derivatives			Cash Collateral(1)		Net Amount
As of December 31, 2014:
Liabilities:
Commodity contracts:
Electricity(2)	$	55	$	—	$	55	$	(55	)	$	—	$	—
Natural gas(2)	17		—		17		(17		)	—		—
	$	72	$	—	$	72	$	(72	)	$	—	$	—
As of December 31, 2013:
Liabilities:
Commodity contracts:
Electricity(2)	$	91	$	—	$	91	$	(91	)	$	—	$	—
Natural gas(2)	1		—		1		(1		)	—		—
	$	92	$	—	$	92	$	(92	)	$	—	$	—

(1) As of December 31, 2014 and 2013, the Company had collateral posted of $11 million and $7 million, respectively, which consists entirely of letters of credit.

(2) Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.

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

	Years Ended December 31,
	2014		2013		2012
Commodity contracts:
Electricity	$	13	$	78	$	56
Natural Gas	72		28		19
Foreign currency exchange	—		1		—

Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2014, 2013, and 2012, $83 million, $120 million, and $42 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 2014 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):

	2015		2016		2017		2018		2019		Thereafter		Total
Commodity contracts:
Electricity	$	50	$	19	$	6	$	5	$	5	$	22	$	107
Natural gas	49		44		18		3		—		—		114
Net unrealized loss	$	99	$	63	$	24	$	8	$	5	$	22	$	221

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

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2014 was $216 million, for which the Company had posted $29 million in collateral, consisting primarily of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2014, the cash requirement to either post as collateral or settle the instruments immediately would have been $213 million. As of December 31, 2014, PGE had posted an additional $11 million in cash collateral for derivative instruments with no credit-risk-related contingent features, which is classified as Margin deposits on the Company’s consolidated balance sheet.

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

	As of December 31,
	2014		2013
Assets from price risk management activities:
Counterparty A	63	%	53	%
Counterparty B	14		6
	77	%	59	%
Liabilities from price risk management activities:
Counterparty C	22	%	43	%
Counterparty D	12		11
	34	%	54	%

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

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NOTE 6: REGULATORY ASSETS AND LIABILITIES

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

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

	Weighted Average Remaining Life (1)	As of December 31,
		2014					2013
		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management (2)	3 years	$	100		$	121	$	36		$	140
Pension and other postretirement plans (2)	(3)	—			247		—			194
Deferred income taxes (2)	(4)	—			86		—			76
Debt issuance costs (2)	8 years	—			15		—			17
Deferred capital projects	1 year	19			—		16			18
Other (5)	Various	14			25		14			19
Total regulatory assets		$	133		$	494	$	66		$	464
Regulatory liabilities:
Asset retirement removal costs (6)	(4)	$	—		$	804	$	—		$	747
Trojan decommissioning activities	2 years	23			34		—			49
Asset retirement obligations (6)	(4)	—			39		—			39
Other	Various	37			29		1			30
Total regulatory liabilities		$	60	(7)	$	906	$	1	(7)	$	865

(1) As of December 31, 2014.

(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 $33 million and $16 million as of December 31, 2014 and 2013, respectively.

(6) Included in rate base for ratemaking purposes.

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

As of December 31, 2014, PGE had regulatory assets of $63 million earning a return on investment at the following rates: i) $33 million earning a return by inclusion in rate base; ii) $19 million at PGE’s cost of debt of 5.54%; iii) $9 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 1.77%, depending on the year of approval; and iv) $2 million at PGE’s cost of capital of 7.65%.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management.

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

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

Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date.

Deferred capital projects represents costs related to four capital projects that were deferred for future accounting treatment pursuant to the Company’s 2011 GRC. The recovery of these project costs in customer prices began January 1, 2014.

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

Trojan decommissioning activities represents proceeds received for the settlement of a legal matter concerning the reimbursement from the United States Department of Energy of certain monitoring costs incurred related to spent nuclear fuel at Trojan. The proceeds will be returned to customers over a three-year period beginning January 1, 2015 and offset amounts previously collected from customers in relation to Trojan decommissioning activities. To conform with the 2014 presentation, PGE reclassified tax credits to be returned to customers related to the operation of the ISFSI in the amount of $8 million from Other to Trojan decommissioning activities in the noncurrent regulatory liabilities section as of December 31, 2013 in the preceding table.

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

NOTE 7: ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):

	As of December 31,
	2014		2013
Trojan decommissioning activities	$	41	$	41
Utility plant	64		49
Non-utility property	11		10
Asset retirement obligations	$	116	$	100

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

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation

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and have met all other conditions precedent. The Plaintiffs were seeking approximately $112 million in damages incurred through 2009.

A trial before the U.S. Court of Federal Claims concluded in 2012, with the U.S. Court of Federal Claims issuing a judgment awarding certain damages to the Plaintiffs. In 2013, the Plaintiffs received $70 million for the settlement of this matter. The settlement agreement also provided for a process to submit claims for allowable costs for the period 2010 through 2013, and was subsequently extended to cover 2014 through 2016. In 2014, the Plaintiffs received $9 million for costs related to 2010 through 2013. The Company will seek recovery of any costs for subsequent periods in future extensions of the agreement.

PGE has received proceeds of $50 million related to its share in this legal matter, with $44 million received in 2013 and $6 million received in 2014. Such funds were deposited into the Nuclear decommissioning trust and recorded as a regulatory liability to offset amounts previously collected in relation to Trojan decommissioning activities. In December 2014, the OPUC issued an order on the Company’s 2015 GRC, authorizing the return of the $50 million of proceeds received related to this legal matter to customers over a three-year period beginning January 1, 2015.

The ARO related to Trojan decommissioning activities is not impacted by the outcome of this legal matter because the proceeds received in connection with the settlement of this legal matter are for past Trojan decommissioning costs and this ARO reflects future Trojan decommissioning costs.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets where disposal is governed by environmental regulation. During 2014, the Company incurred AROs totaling $8 million related to the three new generating resources: Port Westward Unit 2 (PW2), Tucannon River Wind Farm (Tucannon River), and Carty Generating Station (Carty).

In December 2014 and 2013, PGE increased its ARO related to Boardman by $7 million and $4 million, respectively, in connection with the acquisition of additional interests in Boardman, with corresponding increases in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. For additional information regarding the Company’s acquisition of additional interests in Boardman, see Note 17, Jointly-owned Plant.

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

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

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	100		$	94		$	87
Liabilities incurred	15			4			—
Liabilities settled	(3		)	(4		)	(3		)
Accretion expense	6			6			6
Revisions in estimated cash flows	(2		)	—			4
Balance as of end of year	$	116		$	100		$	94

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

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

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

NOTE 8: CREDIT FACILITIES

PGE has credit facilities with an aggregate capacity of $700 million as follows:

• A $400 million revolving credit facility, which is scheduled to terminate in November 2018; and

• A $300 million revolving credit facility, which is scheduled to terminate in December 2017.

Pursuant to the terms of the agreements, both revolving credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both revolving credit facilities contain two, one-year extensions subject to approval by the banks, require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2014, PGE was in compliance with this covenant with a 56.7% debt to total capital ratio.

PGE classifies any borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt in the consolidated balance sheets. As of December 31, 2014, PGE had no borrowings or commercial paper outstanding, $20 million of letters of credit issued, and an aggregate available capacity of $680 million under the revolving credit facilities.

In addition, PGE has two one-year $30 million letter of credit facilities, under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit are subject to the approval of the issuing institution. As of December 31, 2014, $56 million of letters of credit had been issued under these facilities.

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

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt up to $900 million through February 6, 2016. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

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

	Years Ended December 31,
	2014			2013			2012
Average daily amount of short-term debt outstanding	$	—		$	9		$	4
Weighted daily average interest rate *	—		%	0.4		%	0.4		%
Maximum amount outstanding during the year	$	—		$	54		$	44

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

NOTE 9: LONG-TERM DEBT

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

	As of December 31,
	2014			2013
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048	$	2,075		$	1,795
Unsecured term bank loans, rates range from 0.86% to 0.93%, due October 2015	305			—
Pollution Control Revenue Bonds, 5% rate, due 2033	142			148
Pollution Control Revenue Bonds owned by PGE	(21		)	(27		)
Total long-term debt	2,501			1,916
Less: current portion of long-term debt	(375		)	—
Long-term debt, net of current portion	$	2,126		$	1,916

First Mortgage Bonds—During 2014, PGE issued a total of $280 million of FMBs, consisting of the following:

• In November, issued $80 million of 3.51% Series FMBs due 2024;

• In October, issued $100 million of 4.44% Series FMBs due 2046; and

• In August, issued $100 million of 4.39% Series FMBs due 2045.

The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs.

In January 2015, the Company issued $75 million of 3.55% Series FMBs due 2030.

Unsecured term bank loans—During 2014, PGE obtained four term loans pursuant to a credit agreement in an aggregate principal amount of $305 million. The term loan interest rates are set at the beginning of the interest period for periods ranging from one- to six-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 70 basis points, with no other fees. The credit agreement expires October 30, 2015, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults and other customary defaults. Interest is payable monthly on the unsecured term bank loans.

Pollution Control Revenue Bonds—In January 2014, PGE retired $6 million of Pollution Control Revenue Bonds (PCBs). The Company has the option to remarket through 2033 the $21 million of PCBs held by PGE as of December 31, 2014. At the time of any remarketing, the Company can choose a new interest rate period that could

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be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing. The PCBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on PCBs.

As of December 31, 2014, the future minimum principal payments on long-term debt are as follows (in millions):

Years ending December 31:
2015	$	375
2016	67
2017	58
2018	75
2019	300
Thereafter	1,626
	$	2,501

NOTE 10: EMPLOYEE BENEFITS

Pension and Other Postretirement Plans

Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan. The plan has been closed to most new employees since January 31, 2009 and to all new employees since January 1, 2012. No changes were made to the benefits provided to existing participants when the plan was closed to new employees.

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

PGE made no contributions to the pension plan in 2014, 2013, and 2012. No contributions to the pension plan are expected in 2015.

In 2014, the Company offered certain eligible participants of the pension plan the option to select a lump sum distribution. As a result of this offering, PGE made lump sum distributions totaling $16 million on July 1, 2014.

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

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

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

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

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

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

	2014						2013
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	15	$	17	$	32	$	16	$	19	$	35
Non-qualified benefit plan liabilities *	25		80		105		22		79		101

* For the NQBP, excludes the current portion of $2 million in 2014 and in 2013, which is classified in Other current liabilities in the consolidated balance sheets.

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

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

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

	As of December 31,
	2014				2013
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	66	%	67	%	67	%	67	%
Debt securities	34		33		33		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	66	%	67	%	58	%	58	%
Debt securities	34		33		42		42
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	19	%	13	%	24	%	16	%
Debt securities	1		7		1		9
Insurance contracts	80		80		75		75
Total	100	%	100	%	100	%	100	%

* The target for the Defined Benefit Pension 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.

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

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2014:
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	$	42	$	146	$	—	$	188
International	—		171		—		171
Debt securities:
Domestic government and corporate credit	—		197		—		197
Private equity funds	—		—		29		29
	$	42	$	520	$	29	$	591
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	10		1		—		11
International	10		—		—		10
Debt securities—Domestic government	5		—		—		5
	$	25	$	7	$	—	$	32
As of December 31, 2013:
Defined Benefit Pension Plan assets:
Equity securities:
Domestic	$	166	$	19	$	—	$	185
International	185		—		—		185
Debt securities:
Domestic government and corporate credit	—		181		—		181
Corporate credit	14		—		—		14
Private equity funds	—		—		31		31
	$	365	$	200	$	31	$	596
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	10	$	—	$	10
Equity securities:
Domestic	8		2		—		10
International	9		—		—		9
Debt securities—Domestic government	3		—		—		3
	$	20	$	12	$	—	$	32

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

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

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

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

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

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

Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy, which consists of Private equity funds, were as follows (in millions):

	Years Ended December 31,
	2014			2013
Level 3 balance as of beginning of year	$	31		$	32
Unrealized gains, net	2			4
Realized gains (losses), net	3			(2		)
Sales, net	(7		)	(3		)
Level 3 balance as of end of year	$	29		$	31

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2014 and 2013. Information related to the Other NQBP is not included in the following tables (dollars in millions):

	Defined Benefit Pension Plan						Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014			2013			2014			2013			2014			2013
Benefit obligation:
As of January 1	$	705		$	728		$	77		$	84		$	24		$	27
Service cost	15			17			2			2			—			—
Interest cost	34			30			4			3			1			1
Participants’ contributions	—			—			1			2			—			—
Actuarial (gain) loss	72			(38		)	4			(9		)	5			(2		)
Contractual termination benefits	—			—			1			1			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	777		$	705		$	83		$	77		$	27		$	24
Fair value of plan assets:
As of January 1	$	596		$	537		$	32		$	28		$	16		$	15
Actual return on plan assets	44			91			1			5			1			3
Company contributions	—			—			4			3			1			—
Participants’ contributions	—			—			1			2			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	591		$	596		$	32		$	32		$	15		$	16
Unfunded position as of December 31	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Accumulated benefit plan obligation as of December 31	$	691		$	631		N/A			N/A			$	27		$	24
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	15		$	16
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(186		)	(109		)	(51		)	(45		)	(25		)	(22		)
Net liability	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Amounts included in comprehensive income:
Net actuarial (gain) loss	$	67		$	(89	)	$	5		$	(11	)	$	5		$	(1	)
Amortization of net actuarial loss	(17		)	(24		)	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			(1		)	(1		)	—			—
	$	50		$	(113	)	$	3		$	(13	)	$	4		$	(2	)
Amounts included in AOCL*:
Net actuarial loss	$	236		$	186		$	10		$	6		$	13		$	9
Prior service cost	—			—			1			2			—			—
	$	236		$	186		$	11		$	8		$	13		$	9

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	Defined Benefit Pension Plan				Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014		2013		2014			2013			2014		2013
Assumptions used:
Discount rate for benefit obligation	4.02	%	4.84	%	3.07	%	-	3.46	%	-	4.02	%	4.84	%
					4.10	%		4.96	%
Discount rate for benefit cost	4.84	%	4.24	%	3.46	%	-	2.77	%	-	4.84	%	4.24	%
					4.96	%		4.13	%
Weighted average rate of compensation increase for benefit obligation	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Weighted average rate of compensation increase for benefit cost	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Long-term rate of return on plan assets for benefit obligation	7.50	%	7.50	%	6.37	%		6.46	%		N/A		N/A
Long-term rate of return on plan assets for benefit cost	7.50	%	8.25	%	6.46	%		5.89	%		N/A		N/A

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

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

	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2014			2013			2012			2014			2013			2012			2014		2013		2012
Service cost	$	15		$	17		$	14		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	34			30			31			4			3			3			1		1		1
Expected return on plan assets	(39		)	(40		)	(41		)	(2		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	—			—			—			1			1			1			—		—		—
Amortization of net actuarial loss	17			24			17			1			1			1			1		1		1
Net periodic benefit cost	$	27		$	31		$	21		$	6		$	6		$	6		$	2	$	2	$	2

PGE estimates that $23 million will be amortized from AOCL into net periodic benefit cost in 2015, consisting of a net actuarial loss of $20 million for pension benefits, $1 million for non-qualified benefits and $1 million for other postretirement benefits, and prior service cost of $1 million for other postretirement benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

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

	Payments Due
	2015		2016		2017		2018		2019		2020 - 2024
Defined benefit pension plan	$	35	$	37	$	38	$	40	$	41	$	221
Other postretirement benefits	5		5		5		5		5		26
Non-qualified benefit plans	2		2		2		2		3		9
Total	$	42	$	44	$	45	$	47	$	49	$	256

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

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

• For 2014, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019;

• For 2013, 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; and

• 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.

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

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes 5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay.

For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $16 million in 2014, 2013 and 2012.

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NOTE 11: INCOME TAXES

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

	Years Ended December 31,
	2014		2013		2012
Current:
Federal	$	20	$	10	$	16
State and local	2		—		1
	22		10		17
Deferred:
Federal	26		4		30
State and local	13		7		17
	39		11		47
Income tax expense	$	61	$	21	$	64

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

	Years Ended December 31,
	2014		2013		2012
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(11.4	)	(21.8	)	(11.8	)
State and local taxes, net of federal tax benefit	3.9		3.4		3.5
Flow through depreciation and cost basis differences	(2.3	)	2.8		2.4
Adjustment to deferred taxes for change in blended composite state tax rate	—		—		2.6
Other	0.8		(2.6	)	(0.6	)
Effective tax rate	26.0	%	16.8	%	31.1	%

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

	As of December 31,
	2014			2013
Deferred income tax assets:
Employee benefits	$	161		$	122
Price risk management	88			71
Regulatory liabilities	48			33
Tax credits	13			51
Other	1			—
Total deferred income tax assets	311			277
Deferred income tax liabilities:
Depreciation and amortization	693			646
Regulatory assets	210			175
Total deferred income tax liabilities	903			821
Deferred income tax liability, net	$	(592	)	$	(544	)
Classification of net deferred income taxes:
Current deferred income tax asset *	$	33		$	42
Noncurrent deferred income tax liability	(625		)	(586		)
	$	(592	)	$	(544	)

* Included in Other current assets in the consolidated balance sheets.

To conform with the 2014 presentation, the Company reclassified $17 million to Regulatory liabilities from Other in the 2013 deferred income tax assets section of the preceding table.

As of December 31, 2014, PGE has federal and state tax credit carryforwards of $10 million and $3 million, respectively, which will expire at various dates from 2021 through 2036.

PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2014 and 2013 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2014 and 2013, PGE had no unrecognized tax benefits.

PGE and its subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Oregon, California, Montana, and certain local jurisdictions. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2010 and all issues were resolved related to those years. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

Further guidance was issued during 2014 that clarified final regulations issued on September 13, 2013, regarding the deduction and capitalization of expenditures related to tangible property. The final regulations under Internal Revenue Code Sections 162, 167 and 263(a) apply to amounts paid to acquire, produce, or improve tangible property, as well as dispositions of such property and have been adopted by PGE as of the January 1, 2014 effective date. The adoption of these regulations, including the consideration of subsequent guidance, did not have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

House of Representatives Bill 5771—The Tax Increase Prevention Act of 2014 was signed into law on December 19, 2014. PGE has examined the new law and while the Company intends to take advantage of some of the provisions, no provision will materially impact its consolidated financial position.

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NOTE 12: EQUITY-BASED PLANS

Equity Forward Sale Agreement

PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 11,100,000 shares of its common stock in June 2013. In connection with such public offering, the underwriters exercised their over-allotment option in full and PGE issued 1,665,000 shares of its common stock for net proceeds of $47 million. Pursuant to the terms of the EFSA, a forward counterparty borrowed 11,100,000 shares of PGE’s common stock from third parties in the open market and sold the shares to a group of underwriters for $29.50 per share, less an underwriting discount equal to $0.96 per share. The underwriters then sold the shares in a public offering. PGE receives proceeds from the sale of common stock when the EFSA is physically settled (described below), and at that time PGE issues new shares of common stock and records the proceeds in equity. Through December 31, 2014, the Company has issued 700,000 shares of its common stock pursuant to the EFSA for net proceeds of $20 million.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of: i) physical; ii) cash; or iii) net share settlement, in whole or in part, at any time on or prior to June 11, 2015, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $29.50 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

The EFSA had no initial fair value since it was entered into at the then market price of the common stock. Accordingly, PGE concluded that the EFSA was an equity instrument which does not qualify as a derivative because the EFSA was indexed to the Company’s stock. PGE anticipates settling the EFSA through physical settlement on or before June 11, 2015.

As of December 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares to the forward counterparty in exchange for cash of $275 million. In addition, at December 31, 2014, the Company could have elected to make a cash settlement by paying approximately $119 million, or a net share settlement by delivering approximately 3,135,000 shares of common stock. To the extent that PGE makes a cash or net share settlement, the Company would receive no additional proceeds from the public offering.

Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common

stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

Employee Stock Purchase Plan

PGE has an employee stock purchase plan (ESPP), under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. There are two six-month offering periods each year, January 1 through June 30 and July 1 through December 31, during which eligible employees may purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2014, there were 427,021 shares available for future issuance pursuant to the ESPP.

Dividend Reinvestment and Direct Stock Purchase Plan

PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2014, there were 2,481,110 shares available for future issuance pursuant to the DRIP.

NOTE 13: STOCK-BASED COMPENSATION EXPENSE

Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs) to non-employee directors, officers and certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table:

	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2011	491,404		$	18.54
Granted	186,495		24.72
Forfeited	(22,947	)	18.95
Vested	(214,390	)	15.67
Outstanding as of December 31, 2012	440,562		22.54
Granted	183,071		29.25
Forfeited	(7,007	)	27.15
Vested	(185,536	)	20.20
Outstanding as of December 31, 2013	431,090		26.31
Granted	203,410		31.49
Forfeited	(12,278	)	29.90
Vested	(158,329	)	24.95
Outstanding as of December 31, 2014	463,893		28.96

A total of 4,687,500 shares of common stock were registered for future issuance under the Plan, of which 3,554,884 shares remain available for future issuance as of December 31, 2014.

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

Time-based RSUs vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was less than $1 million for the years ended December 31, 2014, 2013, and 2012.

Performance-based RSUs vest if performance goals are met at the end of a three-year performance period. For grants prior to March 5, 2013, such goals include return on equity relative to allowed return on equity, and regulated asset base growth. Grants on and after March 5, 2013 are based on three equally-weighted metrics: return on equity relative to allowed return on equity; regulated asset growth; and a relative total shareholder return (TSR) of PGE’s common stock as compared to the Edison Electric Institute Regulated Index (EEI Index) during the performance period. Vesting of performance-based RSUs is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

For the return on equity and regulated asset base growth portions of the performance-based RSUs, fair value is measured based on the closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions:

	2014				2013
Risk-free interest rate			0.6	%			0.3	%
Expected dividend yield			—	%			—	%
Expected term (in years)			3.0				3.0
Volatility	12.4%	-	23.0%		12.1%	-	25.1%

The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 134.2%, 117.5%, and 112.0% of awarded performance-based RSUs for 2014, 2013, and 2012, respectively, with an estimated 5% forfeiture rate.

The total value of performance-based RSUs vested was $3 million for the years ended December 31, 2014, 2013, and 2012.

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Stock-based compensation was $6 million for the year ended December 31, 2014, and $4 million in 2013 and in 2012, which is included in Administrative and other expense in the consolidated statements of income. Such amounts differ from those reported in the consolidated statements of equity for Stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. The net impact to equity from the income tax payments, partially offset by the issuance of DERs, resulted in a charge to equity of $1 million in 2014, $2 million in 2013, and $1 million in 2012, which is not included in Administrative and other expenses in the consolidated statements of income.

As of December 31, 2014, unrecognized stock-based compensation expense was $6 million, of which approximately $4 million and $2 million is expected to be expensed in 2015 and 2016, respectively. No stock-based compensation costs have been capitalized and the Plan had no material impact on cash flows for the years ended December 31, 2014, 2013, or 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

NOTE 14: EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) unvested time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the EFSA. See Note 12, Equity-based Plans, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria has been met.

Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computation. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Years Ended December 31,
	2014	2013	2012
Weighted average common shares outstanding—basic	78,180	76,821	75,498
Dilutive effect of potential common shares	2,314	567	149
Weighted average common shares outstanding—diluted	80,494	77,388	75,647

NOTE 15: COMMITMENTS AND GUARANTEES

Commitments

As of December 31, 2014, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):

	Payments Due
	2015		2016		2017		2018		2019		Thereafter		Total
Capital and other purchase commitments	$	242	$	21	$	2	$	2	$	2	$	74	$	343
Purchased power and fuel:
Electricity purchases	179		167		140		143		143		833		1,605
Capacity contracts	27		26		6		6		5		20		90
Public utility districts	8		7		5		4		2		23		49
Natural gas	56		37		40		40		36		244		453
Coal and transportation	23		14		11		5		5		—		58
Operating leases	10		11		12		11		8		192		244
Total	$	545	$	283	$	216	$	211	$	201	$	1,386	$	2,842

Capital and other purchase commitments—Certain commitments have been made for capital and other purchases for 2015 and beyond. Such commitments include those related to hydro licenses, upgrades to generating, distribution and transmission facilities, information systems, and system maintenance work. A large component of these commitments for 2015 are costs associated with the construction of Carty. Termination of these agreements could result in cancellation charges.

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Electricity purchases and Capacity contracts—PGE has power purchase contracts with counterparties, which expire at varying dates through 2049, and power capacity contracts through 2019. In addition to the power purchase contracts with counterparties presented in the table, PGE has power sale contracts with counterparties of approximately $43 million that settle as follows: $14 million in 2015; $11 million in 2016 and 2017; and $7 million in 2018.

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

	Revenue Bonds as of December 31, 2014		PGE’s Share as of December 31, 2014			Contract Expiration	PGE Cost, including Debt Service
			Output		Capacity		2014		2013		2012
					(in MW)
Priest Rapids and Wanapum	$	1,102	8.6	%	163	2052	$	14	$	14	$	14
Wells	215		19.4		150	2018	10		10		10
Portland Hydro	4		100.0		36	2017	4		4		4

The agreements for Priest Rapids and Wanapum and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.

Natural gas—PGE has agreements for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. The Company also has a natural gas storage agreement for the purpose of fueling the Company’s natural gas-fired generating plants (Port Westward Unit 1 (PW1), PW2 and Beaver).

Coal and transportation—PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman, which expire at various dates through 2020.

Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities. The majority of the future minimum operating lease payments presented in the table consist of i) the corporate headquarters lease, which expires in 2018, but includes renewal period options through 2043, and ii) the Port of St. Helens land lease, where PW1, PW2 and Beaver are located, which expires in 2096. Rent expense was $11 million in 2014, $9 million in 2013, and $10 million in 2012.

The future minimum operating lease payments presented is net of sublease income of: $3 million in 2015; $2 million in 2016; and $1 million in 2017, 2018 and 2019. Sublease income was $3 million in 2014, 2013 and 2012.

Guarantees

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification

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provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 2014, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.

NOTE 16: VARIABLE INTEREST ENTITIES

PGE has determined that as of December 31, 2014it is the primary beneficiary of two VIEs(three as of December 31, 2013), and, therefore, consolidates the VIEs within the Company’s consolidated financial statements. Such arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties, and selling the energy generated by the facilities. The Company is the Managing Member and a financial institution is the Investor Member in each of the Limited Liability Companies (LLCs), holding equity interests of less than 1% and more than 99%, respectively, in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

Determining whether PGE is the primary beneficiary of a VIE is complex, subjective and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining it is the primary beneficiary of these LLCs include the following: i) PGE has the experience to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and, therefore, PGE has control over the most significant activities of the LLCs; ii) PGE expects to own 100% of the LLCs shortly after five

years have elapsed from when the facility was placed in service, at which time the facilities will have approximately 75% of their estimated useful life remaining; and iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of any expected losses of the LLCs.

Included in PGE’s consolidated balance sheets as of December 31, 2014 and 2013 are LLC net assets of $4 million and $5 million, respectively, primarily comprised of Electric utility plant, and includes Cash and cash equivalents of $1 million as of December 31, 2013. These assets can only be used to settle the obligations of the consolidated VIEs and their creditors have no recourse to the general credit of PGE.

In January 2015, PGE acquired the equity interest held by the Investor Member of one of the LLCs pursuant to the terms of the operating agreement. The transaction did not have a significant impact to the Company’s consolidated financial position, consolidated results of operations or consolidated cash flows.

NOTE 17: JOINTLY-OWNED PLANT

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

In 1985, PGE sold a 15% undivided interest in Boardman and a 10.714% undivided interest in the Company’s share of the Pacific Northwest Intertie transmission line (jointly, the Facility Assets) to an unrelated third party (Purchaser). Under terms of the original 1985 agreements, on December 31, 2013, PGE acquired the Facility Assets from the Purchaser in exchange for $1 from the Purchaser. PGE assumed responsibility for the ARO related to that 15% interest in Boardman in the amount of $7 million. The acquisition of the 15% interest in Boardman increased the Company’s ownership share from 65% to 80% on December 31, 2013. Such transaction is non-cash and is excluded from investing activities in the consolidated statement of cash flows for the year ended December 31, 2013.

On December 31, 2014, PGE acquired an additional 10% interest in Boardman from another co-owner, whereby the Company received net cash of $8 million from the co-owner to assume the net liabilities associated with the ownership of this 10% interest. In connection with this transaction, PGE recorded Electric utility plant of $7 million, inventory of $4 million, an ARO of $7 million, a regulatory liability of $6 million to be returned to customers in 2015 and 2016, a regulatory liability of $4 million related to future additional decommissioning and environmental costs, and deferred revenue of $2 million. The acquisition of the 10% interest in Boardman increased the Company’s ownership share from 80% to 90%.

As of December 31, 2014, PGE had the following investments in jointly-owned plant (dollars in millions):

	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	90.00	%	1980			$	510	$	350	$	—
Colstrip	20.00		1986			520		334		2
Pelton/Round Butte	66.67		1958	/	1964	237		55		8
Total						$	1,267	$	739	$	10

* Excludes AROs and accumulated asset retirement removal costs.

NOTE 18: CONTINGENCIES

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PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

Trojan Investment Recovery

Regulatory Proceedings. In 1993, PGE closed Trojan and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

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

In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining investment in Trojan as of September 30, 2000, along with several largely offsetting regulatory liabilities. After offsetting the investment in Trojan with these liabilities, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan was no longer included in prices charged to customers, either through a return of or a return on that investment. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the

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settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

The OPUC then issued an order in 2008 (2008 Order) that required PGE to provide refunds, including interest from September 30, 2000, to customers who received service from the Company during the period from October 1, 2000 to September 30, 2001. The Company recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below separately appealed the 2008 Order to the Oregon Court of Appeals.

On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. On May 31, 2013, the Court of Appeals denied the appellants’ request for reconsideration of the decision. On October 18, 2013, the Oregon Supreme Court granted plaintiffs’ petition seeking review of the February 6, 2013 Oregon Court of Appeals decision.

On October 2, 2014, the Oregon Supreme Court, in a unanimous decision, affirmed the February 6, 2013 Oregon Court of Appeals decision that upheld the OPUC’s 2008 Order. On January 15, 2015, the Oregon Supreme Court denied the plaintiffs petition seeking reconsideration of the October 2, 2014 decision.

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

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

The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court.

The October 2, 2014 Oregon Supreme Court decision described above expressly noted that the plaintiffs in the class action must address any request to lift the abatement with the Marion County Circuit Court. PGE is evaluating how to proceed with respect to the class actions.

PGE believes that the October 2, 2014 Oregon Supreme Court decision has reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain pending, management believes that it is still reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss, or to estimate a range of potential loss.

Pacific Northwest Refund Proceeding

In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific

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Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. Upon appeal of the decision to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit), the Ninth Circuit remanded the case to the FERC to, among other things, address market manipulation evidence in detail and account for the evidence in any future orders regarding the award or denial of refunds in the proceedings.

In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. The orders held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also expanded the scope of the hearing to allow parties to pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule of a statutory requirement. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund claimants have filed petitions for appeal of these procedural orders with the Ninth Circuit.

Pursuant to a FERC-ordered settlement process, the Company received notice of two claims and reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012.

Additionally, the settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement, including the California Energy Resource Scheduling division of the California Department of Water Resources (CERS), as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The above-referenced settlements resulted in a release of the Company as a named respondent in the first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.

During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of CERS, presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of the two CERS’ respondents, but that CERS had produced evidence that the remaining CERS respondent had engaged in unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. The Administrative Law Judge determined that in the second phase the remaining respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. The findings in the Initial Decision are subject to further FERC action. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.

Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds from any of the current respondents, which

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contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, will pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss.

EPA Investigation of Portland Harbor

A 1997 investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In January 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017.

The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss.

DEQ Investigation of Downtown Reach

The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In January 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in December 2011 and entered into a consent order with the DEQ in July 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. The draft feasibility study report, which describes possible remediation alternatives that range in estimated cost from $3 million to $8 million, was submitted to the DEQ in February 2014. Following the DEQ’s evaluation of the draft feasibility study, PGE submitted a final feasibility study to the DEQ in September 2014. The estimated costs in the final feasibility study did not differ significantly from those in the draft feasibility study. Using the Company’s best estimate of the probable cost for the remediation effort from the set of alternatives provided in the feasibility study report, PGE has a $3 million reserve for this matter as of December 31, 2014.

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Based on the available evidence of previous rate recovery of incurred environmental remediation costs for PGE, as well as for other utilities operating within the same jurisdiction, the Company has concluded that the estimated cost of $3 million to remediate the Downtown Reach is probable of recovery. As a result, the Company also has a regulatory asset of $3 million for future recovery in prices as of December 31, 2014. The Company included recovery of the regulatory asset in its 2015 GRC filed with the OPUC. The final order issued by the OPUC in the 2015 GRC includes revenues to offset the amortization of the regulatory asset over a two year period beginning January 1, 2015.

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleges certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and states that the Sierra Club and MEIC will: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees.

The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.

On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.

On May 3, 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emissions increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment.

On August 27, 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed on September 26, 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is ongoing with trial now scheduled for November 2015.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.

Oregon Tax Court Ruling

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On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue (DOR) interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue is whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. The DOR has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld. Oral argument occurred in May 2014 and the parties now await a Court decision.

If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $7 million due to an increase in the tax rate at which deferred tax liabilities would be recognized in future years. During the third quarter of 2013, the Company entered into a closing agreement with the DOR, under which the DOR agreed to the tax apportionment methodology utilized on the tax returns relating to open tax years 2008 through 2012.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome.

Other Matters

PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

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QUARTERLY FINANCIAL DATA

(Unaudited)

	Quarter Ended
	March 31		June 30			September 30		December 31
	(In millions, except per share amounts)
2014
Revenues, net	$	493	$	423		$	484	$	500
Income from operations	98		58			65		72
Net income	58		35			38		43
Net income attributable to Portland General Electric Company	58		35			39		43
Earnings per share: (1)
Basic	0.74		0.44			0.48		0.57
Diluted	0.73		0.43			0.47		0.55
2013
Revenues, net	$	473	$	403		$	435	$	499
Income (loss) from operations (2)	87		(11		)	53		77
Net income (loss) (2)	48		(22		)	31		47
Net income (loss) attributable to Portland General Electric Company (2)	49		(22		)	31		47
Earnings (loss) per share—basic and diluted (1) (2)	0.65		(0.29		)	0.40		0.59

(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) The quarter ended June 30 includes $52 million of costs expensed related to the Company’s Cascade Crossing Transmission Project and a refund of revenues of $9 million related to the cumulative over-billing of an industrial customer since 2009. For information regarding these matters, see “Electric Utility Plant” in Note 2, Summary of Significant Accounting Policies, and “Customer Billing Matter” in Note 1, Basis of Presentation, respectively, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A.     CONTROLS AND PROCEDURES.

(a)     Disclosure Controls and Procedures

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are effective.

(b)     Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of the end of the period covered by this report pursuant to Rule 13a-15(c) under the Exchange Act. Management’s assessment was based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management has concluded that, as of December 31, 2014, the Company’s internal control over financial reporting is effective.

The Company’s internal control over financial reporting, as of December 31, 2014, has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audits the Company’s consolidated financial statements, as stated in their report included in Item 8.—“Financial Statements and Supplementary Data,” which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2014.

(c)     Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.     OTHER INFORMATION.

None.

119

PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required by Item 10 is incorporated herein by reference to the relevant information under the captions “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance,” “Proposal 1: Election of Directors,” and “Executive Officers” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 6, 2015.

ITEM 11.     EXECUTIVE COMPENSATION.

The information required by Item 11 is incorporated herein by reference to the relevant information under the captions “Corporate Governance—Non-Employee Director Compensation,” “Corporate Governance—Compensation Committee Interlocks and Insider Participation,” “Compensation and Human Resources Committee Report,” “Compensation Discussion and Analysis,” and “Executive Compensation Tables” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 6, 2015.

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

The information required by Item 12 is incorporated herein by reference to the relevant information under the captions “Security Ownership of Certain Beneficial Owners, Directors and Executive Officers” and “Equity Compensation Plans,” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 6, 2015.

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

The information required by Item 13 is incorporated herein by reference to the relevant information under the caption “Corporate Governance” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 6, 2015.

ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by Item 14 is incorporated herein by reference to the relevant information under the captions “Principal Accountant Fees and Services” and “Pre-Approval Policy for Independent Auditor Services” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on May 6, 2015.

120

PART IV

ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)    Financial Statements and Schedules

The financial statements are set forth under Item 8 of this Annual Report on Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.

(b)    Exhibit Listing

Exhibit Number	Description
(3)	Articles of Incorporation and Bylaws
3.1*	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 3.1).
3.2*	Tenth Amended and Restated Bylaws of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 3.2).
(4)	Instruments defining the rights of security holders, including indentures
4.1*	Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945 (Form 8, Amendment No. 1 dated June 14, 1965) (File No. 001-05532-99).
4.2*	Fortieth Supplemental Indenture dated October 1, 1990 (Form 10-K for the year ended December 31, 1990, Exhibit 4) (File No. 001-05532-99).
4.3*	Fifty-sixth Supplemental Indenture dated May 1, 2006 (Form 8-K filed May 25, 2006, Exhibit 4.1)(File No. 001-05532-99).
4.4*	Fifty-seventh Supplemental Indenture dated December 1, 2006 (Form 8-K filed December 22, 2006, Exhibit 4.1) (File No. 001-05532-99).
4.5*	Fifty-eighth Supplemental Indenture dated April 1, 2007 (Form 8-K filed April 12, 2007, Exhibit 4.1) (File No. 001-05532-99).
4.6*	Fifty-ninth Supplemental Indenture dated October 1, 2007 (Form 8-K filed October 5, 2007, Exhibit 4.1) (File No. 001-05532-99).
4.7*	Sixtieth Supplemental Indenture dated April 1, 2008 (Form 8-K filed April 17, 2008, Exhibit 4.1) (File No. 001-05532-99).
4.8*	Sixty-first Supplemental Indenture dated January 15, 2009 (Form 8-K filed January 16, 2009, Exhibit 4.1) (File No. 001-05532-99).
4.9*	Sixty-second Supplemental Indenture dated April 1, 2009 (Form 8-K filed April 16, 2009, Exhibit 4.1) (File No. 001-05532-99).
4.10*	Sixty-third Supplemental Indenture dated November 1, 2009 (Form 8-K filed November 4, 2009, Exhibit 4.1) (File No. 001-05532-99).
4.11*	Sixty-seventh Supplemental Indenture dated June 15, 2013 (Form 8-K filed June 27, 2013, Exhibit 4.1).
4.12*	Sixty-eighth Supplemental Indenture dated October 15, 2013 (Form S-3 filed November 12, 2013, Exhibit 4.13).
4.13*	Sixty-ninth Supplemental Indenture dated August 1, 2014 (Form 8-K filed October 17, 2014, Exhibit 4.1).
4.14	Seventieth Supplemental Indenture dated January 1, 2015.

121

Exhibit Number	Description
(10)	Material Contracts
10.1*	Credit Agreement dated May 7, 2014, between Portland General Electric Company, Wells Fargo Bank, National Association, as Administrative Agent, and JPMorgan Chase Bank, N.A., U.S. Bank National Association, and Bank of America, N.A. (Form 8-K filed May 9, 2014, Exhibit 10.1).
10.2*	Credit Agreement dated November 14, 2012, between Portland General Electric Company, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A. and U.S. Bank National Association, as Co-Syndication Agents, and a group of lenders (Form 10-K filed February 22, 2013, Exhibit 10.1).
10.3*	Credit Agreement dated December 8, 2011, between Portland General Electric Company, Bank of America, N.A., as Administrative Agent, Barclays Capital, as Syndication Agent, and a group of lenders (Form 10-K filed February 24, 2012, Exhibit 10.3).
10.4*	First Amendment dated April 10, 2012 to Credit Agreement dated December 8, 2011, between Portland General Electric Company, Bank of America, N.A., as Administrative Agent, and a group of lenders (Form 10-K filed February 22, 2013, Exhibit 10.3).
10.5*	Second Amendment dated October 31, 2012 to Credit Agreement dated December 8, 2011, between Portland General Electric Company, Bank of America, N.A., as Administrative Agent, and a group of lenders (Form 10-K filed February 22, 2013, Exhibit 10.4).
10.6*	Third Amendment dated January 7, 2013 to Credit Agreement dated December 8, 2011, between Portland General Electric Company, Bank of America, N.A., as Administrative Agent, and a group of lenders (Form 10-K filed February 22, 2013, Exhibit 10.5).
10.7*	Confirmation of Forward Sale Transaction dated June 11, 2013 between Portland General Electric Company and Barclays Bank PLC (Form 8-K filed June 17, 2013, Exhibit 10.1).
10.8*	First Amendment to Confirmation Agreement dated June 25, 2013 between Portland General Electric Company and Barclays Bank PLC (Form 10-Q filed August 2, 2013, Exhibit 10.2).
10.9*	Transfer Agreement between BA Leasing BSC, LLC, as Transferor, and Portland General Electric Company, as Transferee, dated December 18, 2013 (Form 10-K filed February 14, 2014, Exhibit 10.8).
10.10*	Portland General Electric Company Severance Pay Plan for Executive Employees dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.1) (File No. 001-05532-99). +
10.11*	Portland General Electric Company Outplacement Assistance Plan dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.2) (File No. 001-05532-99). +
10.12*	Portland General Electric Company 2005 Management Deferred Compensation Plan dated January 1, 2005 (Form 10-K filed March 11, 2005, Exhibit 10.18) (File No. 001-05532-99). +
10.13*	Portland General Electric Company Management Deferred Compensation Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.1) (File No. 001-05532-99). +
10.14*	Portland General Electric Company Supplemental Executive Retirement Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.2) (File No. 001-05532-99). +
10.15*	Portland General Electric Company Senior Officers’ Life Insurance Benefit Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.3) (File No. 001-05532-99). +
10.16*	Portland General Electric Company Umbrella Trust for Management dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.4) (File No. 001-05532-99). +
10.17*	Portland General Electric Company 2006 Stock Incentive Plan, as amended (Form 10-K filed February 27, 2008, Exhibit 10.23) (File No. 001-05532-99). +
10.18*	Portland General Electric Company 2006 Annual Cash Incentive Master Plan (Form 8-K filed March 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.19*	Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan (Form 8-K filed May 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.20*	Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (Form 8-K filed February 26, 2008, Exhibit 10.1) (File No. 001-05532-99). +
10.21*	Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters (Form 8-K filed December 24, 2009, Exhibit 10.1) (File No. 001-05532-99). +
10.22*	Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters for Officers and Key Employees (Form 8-K filed February 19, 2010, Exhibit 10.1). +
10.23*	Form of Directors’ Restricted Stock Unit Agreement (Form 8-K filed July 14, 2006, Exhibit 10.1) (File No. 001-05532-99). +

122

Exhibit Number	Description
10.24*	Form of Officers’ and Key Employees’ Performance Stock Unit Agreement (Form 10-Q filed May 3, 2012, Exhibit 10.1) (File No. 001-05532-99). +
10.25*	Employment Agreement dated and effective May 6, 2008 between Stephen M. Quennoz and Portland General Electric Company (Form 10-Q filed May 7, 2008, Exhibit 10.3). +
(12)	Statements Re Computation of Ratios
12.1	Computation of Ratio of Earnings to Fixed Charges.
(23)	Consents of Experts and Counsel
23.1	Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP.
(31)	Rule 13a-14(a)/15d-14(a) Certifications
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
(32)	Section 1350 Certifications
32.1	Certifications of Chief Executive Officer and Chief Financial Officer.
(101)	Interactive Data File
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

* Incorporated by reference as indicated.

+ Indicates a management contract or compensatory plan or arrangement.

Certain instruments defining the rights of holders of other long-term debt of PGE are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. PGE hereby agrees to furnish a copy of any such instrument to the SEC upon request.

Upon written request to Investor Relations, Portland General Electric Company, 121 S.W. Salmon Street, Portland, Oregon 97204, the Company will furnish shareholders with a copy of any Exhibit upon payment of reasonable fees for reproduction costs incurred in furnishing requested Exhibits.

123

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 12, 2015.

PORTLAND GENERAL ELECTRIC COMPANY
By:	/s/ JAMES J. PIRO
	James J. Piro
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 12, 2015.

Signature	Title
/s/ JAMES J. PIRO	President, Chief Executive Officer, and Director (principal executive officer)
James J. Piro
/s/ JAMES F. LOBDELL	Senior Vice President of Finance, Chief Financial Officer, and Treasurer (principal financial and accounting officer)
James F. Lobdell
/s/ JOHN W. BALLANTINE	Director
John W. Ballantine
/s/ RODNEY L. BROWN, JR.	Director
Rodney L. Brown, Jr.
/s/ JACK E. DAVIS	Director
Jack E. Davis
/s/ DAVID A. DIETZLER	Director
David A. Dietzler
/s/ KIRBY A. DYESS	Director
Kirby A. Dyess
/s/ MARK B. GANZ	Director
Mark B. Ganz
/s/ KATHRYN J. JACKSON	Director
Kathryn J. Jackson
/s/ NEIL J. NELSON	Director
Neil J. Nelson
/s/ M. LEE PELTON	Director
M. Lee Pelton
/s/ CHARLES W. SHIVERY	Director
Charles W. Shivery

124

EX-4.14

EXHIBIT 4.14

PORTLAND GENERAL ELECTRIC COMPANY

TO

WELLS FARGO BANK, NATIONAL ASSOCIATION

(AS SUCCESSOR TO HSBC BANK USA, NATIONAL ASSOCIATION)

Trustee.

Seventieth Supplemental Indenture

Dated: January 1, 2015

$75,000,000 First Mortgage Bonds,

3.55% Series, due 2030

Supplemental to Indenture of Mortgage and Deed of Trust,

dated July 1, 1945 of Portland General Electric Company.

THIS INSTRUMENT GRANTS A SECURITY INTEREST BY A TRANSMITTING UTILITY

THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS

This SEVENTIETH SUPPLEMENTAL INDENTURE (hereinafter this "Supplemental Indenture"), dated January 1, 2015, is made by and between Portland General Electric Company, an Oregon corporation (hereinafter called the "Company"), and Wells Fargo Bank, National Association (as successor to HSBC Bank USA, National Association), a national banking association, as Trustee (hereinafter called the "Trustee").

WHEREAS, the Company has heretofore executed and delivered its Indenture of Mortgage and Deed of Trust (herein sometimes referred to as the "Original Indenture"), dated July 1, 1945, to the Trustee to secure an issue of First Mortgage Bonds of the Company; and

WHEREAS, bonds in the aggregate principal amount of $34,000,000 have heretofore been issued under and in accordance with the terms of the Original Indenture as bonds of an initial series designated "First Mortgage Bonds, 3-1/8% Series due 1975" (herein sometimes referred to as the "Bonds of the 1975 Series"); and

WHEREAS, the Company has heretofore executed and delivered to the Trustee several supplemental indentures which provided, among other things, for amendment of the Original Indenture and for the creation or issuance of several new series of First Mortgage Bonds under the terms of the Original Indenture as follows:

SupplementalIndenture	Dated	Series Designation			Principal Amount
First	11-1-47	3-1/2	%	Series due 1977	$	6,000,000	(1)
Second	11-1-48	3-1/2	%	Series due 1977	4,000,000		(1)
Third	5-1-52	3-1/2	%	Second Series due 1977	4,000,000		(1)
Fourth	11-1-53	4-1/8	%	Series due 1983	8,000,000		(2)
Fifth	11-1-54	3-3/8	%	Series due 1984	12,000,000		(1)
Sixth	9-1-56	4-1/4	%	Series due 1986	16,000,000		(1)
Seventh	6-1-57	4-7/8	%	Series due 1987	10,000,000		(1)
Eighth	12-1-57	5-1/2	%	Series due 1987	15,000,000		(3)
Ninth	6-1-60	5-1/4	%	Series due 1990	15,000,000		(1)
Tenth	11-1-61	5-1/8	%	Series due 1991	12,000,000		(1)
Eleventh	2-1-63	4-5/8	%	Series due 1993	15,000,000		(1)
Twelfth	6-1-63	4-3/4	%	Series due 1993	18,000,000		(1)
Thirteenth	4-1-64	4-3/4	%	Series due 1994	18,000,000		(1)

1

SupplementalIndenture	Dated	Series Designation			Principal Amount
Fourteenth	3-1-65	4.70	%	Series due 1995	14,000,000	(1)
Fifteenth	6-1-66	5-7/8	%	Series due 1996	12,000,000	(1)
Sixteenth	10-1-67	6.60	%	Series due October 1, 1997	24,000,000	(1)
Seventeenth	4-1-70	8-3/4	%	Series due April 1, 1977	20,000,000	(1)
Eighteenth	11-1-70	9-7/8	%	Series due November 1, 2000	20,000,000	(4)
Nineteenth	11-1-71	8	%	Series due November 1, 2001	20,000,000	(4)
Twentieth	11-1-72	7-3/4	%	Series due November 1, 2002	20,000,000	(4)
Twenty-first	4-1-73	7.95	%	Series due April 1, 2003	35,000,000	(4)
Twenty-second	10-1-73	8-3/4	%	Series due October 1, 2003	17,000,000	(4)
Twenty-third	12-1-74	10-1/2	%	Series due December 1, 1980	40,000,000	(1)
Twenty-fourth	4-1-75	10	%	Series due April 1, 1982	40,000,000	(1)
Twenty-fifth	6-1-75	9-7/8	%	Series due June 1, 1985	27,000,000	(1)
Twenty-sixth	12-1-75	11-5/8	%	Series due December 1, 2005	50,000,000	(4)
Twenty-seventh	4-1-76	9-1/2	%	Series due April 1, 2006	50,000,000	(4)
Twenty-eighth	9-1-76	9-3/4	%	Series due September 1, 1996	62,500,000	(4)
Twenty-ninth	6-1-77	8-3/4	%	Series due June 1, 2007	50,000,000	(4)
Thirtieth	10-1-78	9.40	%	Series due January 1, 1999	25,000,000	(4)
Thirty-first	11-1-78	9.80	%	Series due November 1, 1998	50,000,000	(4)
Thirty-second	2-1-80	13-1/4	%	Series due February 1, 2000	55,000,000	(4)
Thirty-third	8-1-80	13-7/8	%	Series due August 1, 2010	75,000,000	(4)
Thirty-sixth	10-1-82	13-1/2	%	Series due October 1, 2012	75,000,000	(4)
Thirty-seventh	11-15-84	11-5/8	%	Extendable Series A due November 15, 1999	75,000,000	(4)
Thirty-eighth	6-1-85	10-3/4	%	Series due June 1, 1995	60,000,000	(4)

2

SupplementalIndenture		Dated		Series Designation					Principal Amount
Thirty-ninth		3-1-86		9-5/8		%		Series due March 1, 2016	100,000,000	(4)
Fortieth		10-1-90						Medium Term Note Series	200,000,000
Forty-first		12-1-91						Medium Term Note Series I	150,000,000	(1)
Forty-second		4-1-93		7-3/4		%		Series due April 15, 2023	150,000,000	(4)
Forty-third		7-1-93						Medium Term Notes Series II	75,000,000	(1)
Forty-fourth		8-1-94						Medium Term Notes Series III	75,000,000	(1)
Forty-fifth		5-1-95						Medium Term Notes Series IV	75,000,000	(1)
Forty-sixth		8-1-96						Medium Term Notes Series V	50,000,000	(1)
Forty-seventh		12-14-01						Second Series due 2002	150,000,000	(4)
Forty-eighth		6-1-02						Collateral Series due 2003	72,000,000	(1)
Forty-ninth		6-1-02						Second Collateral Series due 2003	150,000,000	(1)
Fiftieth	10-1-02		8-1/8		%		Series due 2010		150,000,000	(4)
Fifty-first	10-1-02		5.6675		%		Series due 2012		100,000,000	(1)
Fifty-second	4-1-03		5.279		%		Series due 2013		50,000,000	(4)
Fifty-third	5-1-03						Collateral Series A due 2033 Collateral Series B due 2033 Collateral Series C due 2033		142,400,000
Fifty-fourth	5-1-03						Collateral Series due 2004		150,000,000	(1)
Fifty-fifth	7-1-03						Medium Term Notes Series VI		200,000,000
Fifty-sixth	5-1-06		6.31 6.26		% %		Series due 2036 Series due 2031		175,000,000 100,000,000
Fifty-seventh	12-1-06		5.80		%		Series due 2039		170,000,000
Fifty-eighth	4-1-07		5.81		%		Series due 2037		130,000,000
Fifty-ninth	10-1-07		5.80		%		Series due 2018		75,000,000
Sixtieth	4-1-08		4.45		%		Second Series due 2013		50,000,000	(1)
Sixty-first	1-15-09		6.50 6.80		% %		Series due 2014 Series due 2016		63,000,000 67,000,000	(4)
Sixty-second	4-1-09		6.10		%		Series due 2019		300,000,000
Sixty-third	11-1-09		5.43		%		Series due 2040		150,000,000
Sixty-fourth	1-15-10		3.46		%		Series due 2015		70,000,000
Sixty-fifth	6-15-10		3.81		%		Series due 2017		58,000,000

3

SupplementalIndenture		Dated		Series Designation			Principal Amount
Sixty-sixth	5-29-13		N/A				N/A	(5)
Sixty-seventh	6-15-13		4.47 4.47		% %	Series due 2044 Series due 2043	150,000,000 75,000,000
Sixty-eighth	10-15-13		4.74 4.84		% %	Series due 2042 Series due 2048	105,000,000 50,000,000
Sixty-ninth	8-1-14		4.39 4.44 3.51		% % %	Series due 2045 Series due 2046 Series due 2024	100,000,000 100,000,000 80,000,000

(1)    Paid in full at maturity.

(2) This entire issue of Bonds was redeemed out of proceeds from the sale of First Mortgage Bonds, 3-3/8% Series due 1984.

(3) This entire issue of Bonds was redeemed out of proceeds from the sale of First Mortgage Bonds, 4-5/8% Series due 1993.

(4)    Redeemed in full prior to maturity.

(5)    Amended Section 14.01 of the Original Indenture.

which bonds are sometimes referred to herein as the "Bonds of the 1977 Series," "Bonds of the 1977 Second Series," "Bonds of the 1983 Series," "Bonds of the 1984 Series," "Bonds of the 1986 Series," "Bonds of the 4⅞% Series due 1987," "Bonds of the 5½% Series due 1987," "Bonds of the 1990 Series," "Bonds of the 1991 Series," "Bonds of the 4⅝% Series due 1993," "Bonds of the 4¾% Series due 1993," "Bonds of the 1994 Series," "Bonds of the 1995 Series," "Bonds of the 1996 Series," "Bonds of the 1997 Series," "Bonds of the 1977 Third Series," "Bonds of the 2000 Series," "Bonds of the 2001 Series," "Bonds of the 2002 Series," "Bonds of the 2003 Series," "Bonds of the 2003 Second Series," "Bonds of the 1980 Series," "Bonds of the 1982 Series," "Bonds of the 1985 Series," "Bonds of the 2005 Series," "Bonds of the 2006 Series," "Bonds of the 1996 Second Series," "Bonds of the 2007 Series," "Bonds of the 1999 Series," "Bonds of the 1998 Series," "Bonds of the 2000 Second Series," "Bonds of the 2010 Series," "Bonds of the 2012 Series," "Bonds of the Extendable Series A," "Bonds of the 1995 Second Series," "Bonds of the 2016 Series," "Bonds of the Medium Term Note Series," "Bonds of the Medium Term Note Series I," "Bonds of the 2023 Series," "Bonds of the Medium Term Note Series II," "Bonds of the Medium Term Note Series III," "Bonds of the Medium Term Note Series IV," "Bonds of the Medium Term Note Series V," "Bonds of the 2002 Second Series," "Bonds of the Collateral Series," "Bonds of the Second Collateral Series," "Bonds of the 2010 Second Series," "Bonds of the 2012 Second Series," "Bonds of the 2013 Series," "Bonds of the 2033 Series," "Bonds of the 2004 Collateral Series," "Bonds of the Medium Term Note Series VI," "Bonds of the 2036 Series," "Bonds of the 2031 Series," "Bonds of the 2039 Series," "Bonds of the 2037 Series," "Bonds of the 2018 Series," "Bonds of the 2013 Second Series," "Bonds of the 2014 Series," "Bonds of the 2016 Series," "Bonds of the 2019 Series," "Bonds of the 2040 Series," "Bonds of the 2015 Series," "Bonds of the 2017 Series," "Bonds of the 2044 Series," "Bonds of the 2043 Series," "Bonds of the 2042 Series," "Bonds of the 2048 Series," "Bonds of the 2045 Series," "Bonds of the 2046 Series," and "Bonds of the 2024 Series" respectively; and

4

WHEREAS, the Original Indenture provides that the Company and the Trustee, subject to the conditions and restrictions in the Original Indenture contained, may enter into an indenture or indentures supplemental thereto, which shall thereafter form a part of said Original Indenture, among other things, to mortgage, pledge, convey, transfer, or assign to the Trustee and to subject to the lien of the Original Indenture with the same force and effect as though included in the granting clauses thereof, additional properties acquired by the Company after the execution and delivery of the Original Indenture, and to provide for the creation of any series of bonds (other than the Bonds of the 1975 Series), designating the series to be created and specifying the form and provisions of the bonds of such series as therein provided or permitted, and to provide a sinking, amortization, replacement, or other analogous fund for the benefit of all or any of the bonds of any one or more series, of such character and of such amount, and upon such terms and conditions as shall be contained in such supplemental indenture; and

WHEREAS, the Company has heretofore executed and delivered to the Trustee sixty-nine supplemental indentures amending in certain respects the Original Indenture (such Original Indenture as so supplemented and amended is hereinafter referred to as the "Mortgage"); and

WHEREAS, the Company desires to further amend the Mortgage in certain respects pursuant to Section 17.01 of the Original Indenture, and the Trustee has agreed to such amendments; and

WHEREAS, the Company desires to provide for the creation of a new series of bonds to be known as "First Mortgage Bonds, 3.55% Series due 2030" (sometimes herein referred to as the "Bonds of the 2030 Series" or the "Bonds"), and to specify the form and provisions of the Bonds, and to mortgage, pledge, convey, transfer, or assign to the Trustee and to subject to the lien of the Mortgage certain additional properties acquired by the Company since the execution and delivery of the Original Indenture; and

WHEREAS, the Company intends at this time to provide for the issuance of $75,000,000 aggregate principal amount of Bonds of the 2030 Series under and in accordance with the terms of the Mortgage and this Supplemental Indenture (the Mortgage as so supplemented and amended by this Supplemental Indenture referred to as the "Indenture"); and

WHEREAS, the Bonds of the 2030 Series and the Trustee's authentication certificate to be executed on the Bonds of the 2030 Series are to be substantially in the following form, respectively:

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(Form of Bond of the 3.55% Series due 2030)

[Face of Bond]

THIS BOND HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE "SECURITIES ACT"). THE HOLDER HEREOF, BY PURCHASING THIS BOND, AGREES FOR THE BENEFIT OF THE COMPANY THAT (A) THIS BOND MAY NOT BE RESOLD, PLEDGED, OR OTHERWISE TRANSFERRED WITHOUT REGISTRATION UNDER THE SECURITIES ACT OR AN EXEMPTION THEREFROM (AND BASED UPON AN OPINION OF COUNSEL ACCEPTABLE TO THE COMPANY, PROVIDED THAT IN-HOUSE COUNSEL TO AN INSTITUTION THAT IS AN "ACCREDITED INVESTOR" AS DEFINED IN RULE 501(A)(1), (2), (3), OR (7) UNDER THE SECURITIES ACT SHALL BE DEEMED ACCEPTABLE) AND IN EACH CASE IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF EACH STATE OF THE UNITED STATES AND (B) IT WILL FURNISH TO THE COMPANY AND THE TRUSTEE SUCH CERTIFICATES AND OTHER INFORMATION AS THEY MAY REASONABLY REQUIRE TO CONFIRM THAT ANY TRANSFER BY IT OF THIS BOND COMPLIES WITH THE FOREGOING RESTRICTIONS, PROVIDED, HOWEVER, THAT SUCH CONFIRMATION BY THE COMPANY MUST BE MADE ON A TIMELY BASIS AND SHALL NOT BE UNREASONABLY WITHHELD. THE HOLDER HEREOF, BY PURCHASING THIS BOND, REPRESENTS AND AGREES FOR THE BENEFIT OF THE COMPANY THAT IT IS (1) A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A OR (2) AN INSTITUTION THAT IS AN "ACCREDITED INVESTOR" AS DEFINED IN RULE 501(A)(1), (2), (3), OR (7) UNDER THE SECURITIES ACT AND THAT IT IS HOLDING THIS BOND FOR INVESTMENT PURPOSES AND NOT FOR DISTRIBUTION OR (3) A NON-U.S. PERSON OUTSIDE THE UNITED STATES WITHIN THE MEANING OF REGULATION S UNDER THE SECURITIES ACT.

No. ______                                        $___________

CUSIP/PPN No. 736508 N@7

PORTLAND GENERAL ELECTRIC COMPANY

FIRST MORTGAGE BOND, 3.55% SERIES DUE 2030

ORIGINAL ISSUE DATE:    January 15, 2015

Portland General Electric Company, an Oregon corporation (hereinafter sometimes called the "Company"), for value received, hereby promises to pay to __________________________, or registered assigns, the principal sum of _____________________________ Dollars on January 15, 2030 (the "Maturity Date"), except to the extent redeemed or repaid prior to the Maturity Date, and to pay interest thereon at the rate of 3.55 percent per annum (calculated on the basis of a 360-day year of twelve 30-day months) until the principal hereof is paid or made available for payment. Interest will be paid semi-annually in arrears on July 15 and January 15 (each an "Interest Payment Date") each year from the Original Issue Date, which will be the date the first interest period commences. If the Maturity Date or an Interest Payment Date falls on a day which is not a Business Day, as defined below, principal or interest payable with respect to such Maturity Date or Interest Payment Date will be paid on the next succeeding Business Day with the same force and effect as if made on such Maturity Date or Interest Payment Date, as the case may be, and, in the case of an Interest Payment Date, but not the Maturity Date, no additional interest shall accrue. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, subject to certain exceptions, be paid to the person in whose name this bond (or one or more predecessor bonds) is registered at the close of business on the fifteenth day (whether or not a Business Day)

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next preceding such Interest Payment Date (the "Regular Record Date"); provided, however, that interest payable on the Maturity Date will be payable to the person to whom the principal hereof shall be payable. Should the Company default in the payment of interest ("Defaulted Interest"), the Defaulted Interest shall be paid to the person in whose name this bond (or one or more predecessor bonds) is registered on a subsequent record date fixed by the Company, which subsequent record date shall be fifteen days prior to the payment of such Defaulted Interest. As used herein, "Business Day" means any day, other than a Saturday or Sunday, on which banks in The City of New York are not required or authorized by law to close.

Payment of the principal of and interest on this bond will be made in immediately available funds at the office or agency of the Trustee located in Minneapolis, Minnesota or such other office of the Trustee that functions as its financial operations center, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. The Trustee, as paying agent of the Company, will make all payments of principal and interest by wire transfer of immediately available funds; provided, however, that appropriate written wire transfer instructions must have been received by the Trustee not less than sixteen days prior to the applicable Interest Payment Date, Maturity Date, or redemption date.

Reference is hereby made to the further provisions of this bond set forth on the reverse hereof, including terms of redemption, and such further provisions shall for all purposes have the same effect as though fully set forth at this place.

This bond shall not become or be valid or obligatory for any purpose until the authentication certificate hereon shall have been signed by the Trustee.

IN WITNESS WHEREOF, PORTLAND GENERAL ELECTRIC COMPANY has caused this instrument to be executed manually or in facsimile by its duly authorized officers and has caused a facsimile of its corporate seal to be imprinted hereon.

Dated: _____________________

PORTLAND GENERAL ELECTRIC COMPANY

By: ______________________________________

Title:

Attest: _____________________

Assistant Secretary

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(Form of Trustee's Authentication Certificate for

Bonds of the 3.55% Series due 2030)

This is one of the bonds, of the series designated herein, described in the within-mentioned Indenture.

WELLS FARGO BANK, NATIONAL     ASSOCIATION, AS TRUSTEE

By:    

Authorized Signatory

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[Reverse of Bond]

This bond is one of the bonds of a series designated as First Mortgage Bonds, 3.55% Series due 2030 (sometimes herein referred to as the "Bonds of the 2030 Series") limited to a maximum aggregate principal amount of $75,000,000. Bonds of the 2030 Series are bonds of an authorized issue of bonds of the Company known as First Mortgage Bonds, not limited as to maximum aggregate principal amount, all issued or issuable in one or more series under and equally secured (except insofar as any sinking fund, replacement fund, or other fund established in accordance with the provisions of the Indenture hereinafter mentioned may afford additional security for the bonds of any specific series) by an Indenture of Mortgage and Deed of Trust dated July 1, 1945, duly executed and delivered by the Company to Wells Fargo Bank, National Association (as successor to HSBC Bank USA, National Association), as Trustee, as supplemented, amended, and modified by sixty-nine supplemental indentures and by the Seventieth Supplemental Indenture (such Indenture of Mortgage and Deed of Trust as so supplemented, amended, and modified by such sixty-nine supplemental indentures and the Seventieth Supplemental Indenture being hereinafter called the "Indenture"), to which Indenture reference is hereby made for a description of the property mortgaged and pledged as security for said bonds, the nature and extent of the security, and the rights, duties, and immunities thereunder of the Trustee, the rights of the holders of said bonds and of the Trustee and of the Company in respect of such security, and the terms upon which said bonds may be issued thereunder. Capitalized terms used herein and not defined herein shall have the respective meanings in the Indenture, unless otherwise noted.

The Bonds of the 2030 Series are not subject to any sinking fund.

The Bonds of the 2030 Series may be redeemed by the Company prior to maturity as a whole, at any time, or in part, from time to time on notice given not more than ninety nor less than thirty days prior to the date of such redemption at the option of the Company at a price equal to the greater of (i) the principal amount of the portion of this bond to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest (not including any portion of such payments of interest accrued as of the date of redemption) due on this bond (or portion thereof) to be redeemed, discounted to the redemption date on a semi-annual basis (assuming a 360‑day year consisting of twelve 30-day months) at the Adjusted Treasury Rate, plus 50 basis points, together in each case with accrued and unpaid interest to the date of redemption.

If this bond or any portion thereof ($10,000 or an integral multiple thereof) is duly called for redemption and payment duly provided for as specified in the Indenture, this bond or such portion thereof shall cease to be entitled to the lien of the Indenture from and after the date payment is so provided for and shall cease to bear interest from and after the date fixed for such redemption.

In the event of the selection for redemption of a portion only of the principal of this bond, payment of the redemption price will be made only upon surrender of this bond in exchange for a bond or bonds (but only of authorized denominations of the same series) for the unredeemed balance of the principal amount of this bond.

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The Indenture contains provisions permitting the Company and the Trustee, with the consent of the holders of not less than seventy-five percent in principal amount of the bonds (exclusive of bonds disqualified by reason of the Company's interest therein) at the time outstanding, including, if more than one series of bonds shall be at the time outstanding, not less than sixty percent in principal amount of each series affected, to effect, by an indenture supplemental to the Indenture, modifications or alterations of the Indenture and of the rights and obligations of the Company and of the holders of the bonds and coupons if the modifications or alterations would adversely affect or diminish the rights of the holders of any bonds against the Company or its property; provided, however, that no such modification or alteration shall be made without the written approval or consent of all holders hereof which will (i) extend the maturity of this bond or reduce the rate or extend the time of payment of interest hereon or reduce the amount of the principal hereof, (ii) permit the creation of any lien, not otherwise permitted, prior to or on a parity with the lien of the Indenture, or (iii) reduce the percentage of the principal amount of the bonds upon the approval or consent of the holders of which modifications or alterations may be made as aforesaid.

The transfer of this bond is registrable by the registered owner hereof in person or by such owner's attorney duly authorized in writing, at the corporate trust office of the Trustee in Minneapolis, Minnesota, upon surrender of this bond for cancellation and upon payment of any taxes or other governmental charges payable upon such transfer, and thereupon a new registered bond or bonds of the same series and of a like aggregate principal amount will be issued to the transferee or transferees in exchange therefor.

The Company, the Trustee, and any paying agent may deem and treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payments of or on account of the principal hereof and interest due hereon, and for all other purposes, whether or not this bond shall be overdue, and neither the Company, the Trustee, nor any paying agent shall be affected by any notice to the contrary.

Bonds of this series are issuable only in fully registered form without coupons in denominations of $100,000 or any amount in excess thereof that is an integral multiple of $10,000. The registered owner of this bond at its option may surrender the same for cancellation at said office of the Trustee and receive in exchange therefor the same aggregate principal amount of registered bonds of the same series but of other authorized denominations upon payment of any taxes or other governmental charges payable upon such exchange and subject to the terms and conditions set forth in the Indenture. Bonds may be issued in a denomination of less than $100,000 (but in multiples of at least $10,000) if necessary to enable the registration of a transfer by a holder of its entire holding of Bonds, or if necessary for the redemption of Bonds.

If an event of default as defined in the Indenture shall occur, the principal of this bond may become or be declared due and payable before maturity in the manner and with the effect provided in the Indenture. The holders, however, of certain specified percentages of the bonds (exclusive of bonds disqualified by reason of the Company's interest therein) at the time outstanding, including in certain cases specified percentages of bonds of particular series, may in certain cases, to the extent and as provided in the Indenture, waive certain defaults thereunder and the consequences of such defaults.

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No recourse shall be had for the payment of the principal of or the interest on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, against any incorporator, shareholder, director, or officer, past, present, or future, as such, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, shareholders, directors, and officers, as such, being waived and released by the holder and owner hereof by the acceptance of this bond and as provided in the Indenture.

The Indenture provides that this bond shall be deemed to be a contract made under the laws of the State of New York, and for all purposes shall be construed in accordance with and governed by the laws of said State.

(End of Form of Bond of the 3.55% Series due 2030)

and

WHEREAS, all acts and proceedings required by law and by the charter or articles of incorporation and bylaws of the Company necessary to make the Bonds to be issued hereunder, when executed by the Company, authenticated and delivered by the Trustee, and duly issued, the valid, binding, and legal obligations of the Company, and to constitute this Supplemental Indenture a valid and binding instrument, have been done and taken; and the execution and delivery of this Supplemental Indenture have been in all respects duly authorized;

NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH, that, in order to secure the payment of the principal of, premium, if any, and interest on all First Mortgage Bonds at any time issued and outstanding under the Original Indenture as supplemented and modified by the sixty-nine supplemental indentures hereinbefore described and as supplemented and modified by this Supplemental Indenture, according to their tenor, purport, and effect, and to secure the performance and observance of all the covenants and conditions therein and herein contained, and for the purpose of confirming and perfecting the lien of the Indenture on the properties of the Company hereinafter described, or referred to, and for and in consideration of the premises and of the mutual covenants herein contained, and acceptance of the Bonds by the holders thereof, and for other valuable consideration, the receipt whereof is hereby acknowledged, the Company has executed and delivered this Supplemental Indenture and by these presents does grant, bargain, sell, warrant, alien, convey, assign, transfer, mortgage, pledge, hypothecate, set over, and confirm unto the Trustee the following property, rights, privileges, and franchises (in addition to all other property, rights, privileges, and franchises heretofore subjected to the lien of the Original Indenture as supplemented by the sixty-nine supplemental indentures hereinbefore described and not heretofore released from the lien thereof, all of which shall secure all bonds, including the Bonds), to wit:

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CLAUSE I

Without in any way limiting anything in the Mortgage or hereinafter described, all and singular the lands, real estate, chattels real, interests in land, leaseholds, ways, rights-of-way, easements, servitudes, permits and licenses, lands under water, riparian rights, franchises, privileges, electric generating plants, electric transmission and distribution systems, and all apparatus and equipment appertaining thereto, offices, buildings, warehouses, garages, and other structures, tracks, machine shops, materials and supplies, and all property of any nature appertaining to any of the plants, systems, business, or operations of the Company, whether or not affixed to the realty, used in the operation of any of the premises or plants or systems or otherwise, which have been acquired by the Company since the execution and delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company (other than excepted property as defined in the Mortgage).

CLAUSE II

All corporate, Federal, State, municipal, and other permits, consents, licenses, bridge licenses, bridge rights, river permits, franchises, grants, privileges, and immunities of every kind and description, owned, held, possessed, or enjoyed by the Company (other than excepted property as defined in the Mortgage) and all renewals, extensions, enlargements, and modifications of any of them, which have been acquired by the Company since the execution and the delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company.

CLAUSE III

Also all other property, real, personal, or mixed, tangible or intangible (other than excepted property as defined in the Mortgage) of every kind, character, and description and wheresoever situated, whether or not useful in the generation, manufacture, production, transportation, distribution, sale, or supplying of electricity, hot water, or steam, which has been acquired by the Company since the execution and delivery of the Original Indenture and not heretofore included in any indenture supplemental thereto, and now owned or which may hereafter be acquired by the Company (other than excepted property as defined in the Mortgage).

CLAUSE IV

Together with all and singular the plants, buildings, improvements, additions, tenements, hereditaments, easements, rights, privileges, licenses, and franchises and all other appurtenances whatsoever belonging or in any wise pertaining to any of the property hereby mortgaged or pledged, or intended so to be, or any part thereof, and the reversion and reversions, remainder and remainders, and the rents, revenues, issues, earnings, income, products, and profits thereof, and every part and parcel thereof, and all the estate, right, title, interest, property, claim, and demand of every nature whatsoever of the Company at law, in equity, or otherwise howsoever,

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in, of, and to such property and every part and parcel thereof (other than excepted property as defined in the Mortgage).

TO HAVE AND TO HOLD all of said property, real, personal, and mixed, and all and singular the lands, properties, estates, rights, franchises, privileges, and appurtenances hereby mortgaged, conveyed, pledged, or assigned, or intended so to be, together with all the appurtenances thereto appertaining and the rents, issues, and profits thereof, unto the Trustee and its successors and assigns, forever:

SUBJECT, HOWEVER, to the exceptions, reservations, restrictions, conditions, limitations, covenants, and matters contained in all deeds and other instruments whereunder the Company has acquired any of the property now owned by it, and to permitted encumbrances as defined in Subsection B of Section 1.11 of the Mortgage;

BUT IN TRUST NEVERTHELESS, for the equal and proportionate use, benefit, security, and protection of those who from time to time shall hold the bonds authenticated and delivered under the Original Indenture and the sixty-nine supplemental indentures hereinbefore described or this Supplemental Indenture, and duly issued by the Company, without any discrimination, preference, or priority of any one bond over any other by reason of priority in the time of issue, sale, or negotiation thereof or otherwise, except as provided in Section 11.28 of the Mortgage, so that, subject to said Section 11.28, each and all of said bonds shall have the same right, lien, and privilege under the Original Indenture and the sixty-nine supplemental indentures hereinbefore described, or this Supplemental Indenture, and shall be equally secured thereby and hereby and shall have the same proportionate interest and share in the trust estate, with the same effect as if all of the bonds had been issued, sold, and negotiated simultaneously on the date of delivery of the Original Indenture;

AND UPON THE TRUSTS, USES, AND PURPOSES and subject to the covenants, agreements, and conditions in the Original Indenture and the sixty-nine supplemental indentures hereinbefore described and herein set forth and declared.

ARTICLE ONE.BONDS OF THE 2030 SERIES AND
CERTAIN PROVISIONS RELATING THERETO.

SECTION 1.01.    Certain Terms of Bonds of the 2030 Series. There is hereby established a series of First Mortgage Bonds of the Company designated and entitled as "First Mortgage Bonds, 3.55% Series due 2030" (sometimes referred to as the "Bonds of the 2030 Series"). The aggregate principal amount of the Bonds of the 2030 Series shall be limited to $75,000,000, excluding, however, any Bonds of the 2030 Series which may be executed, authenticated, and delivered in exchange for or in lieu of or in substitution for other Bonds of such Series pursuant to the provisions of the Indenture.

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The definitive Bonds of the 2030 Series shall be issuable in substantially the form as hereinabove set forth in fully registered form without coupons in the denomination of $100,000, or any amount in excess thereof that is an integral multiple of $10,000.

Notwithstanding the provisions of Section 2.05 of the Mortgage, each Bond of the 2030 Series shall be dated as of the date sold by the Company (the "Original Issue Date") and shall mature on  January 15, 2030 (the "Maturity Date"), except to the extent redeemed or repaid prior to the Maturity Date. Each Bond of the 2030 Series shall bear interest from the Original Issue Date, which is the date the first interest period commences, at the rate of 3.55 per cent per annum (calculated on the basis of a 360‑day year of twelve 30‑day months), until payment of the principal thereof has been paid or made available for payment. Interest will be payable semi-annually in arrears on July 15 and January 15 (each an "Interest Payment Date") each year commencing with the first Interest Payment Date occurring after the Original Issue Date. If the Maturity Date or an Interest Payment Date falls on a day which is not a Business Day, as defined below, principal or interest payable with respect to such Maturity Date or Interest Payment Date will be paid on the next succeeding Business Day with the same force and effect as if made on such Maturity Date or Interest Payment Date, as the case may be, and, in the case of an Interest Payment Date, but not the Maturity Date, no additional interest shall accrue. The person in whose name any Bond of the 2030 Series is registered at the close of business on the applicable Record Date (as defined below) with respect to any Interest Payment Date shall be entitled to receive the interest payable thereon on such Interest Payment Date notwithstanding the cancellation of such Bond of the 2030 Series upon any registration of transfer or exchange thereof subsequent to such Record Date and prior to such Interest Payment Date, unless the Company shall default in the payment of the interest due on such Interest Payment Date, in which case such defaulted interest shall be paid to the person in whose name such Bond of the 2030 Series is registered on a subsequent record date fixed by the Company, which subsequent record date shall be fifteen days prior to the payment of such defaulted interest; provided, however, that interest payable on the Maturity Date will be payable to the person to whom the principal thereof shall be payable. As used herein the term "Business Day" means any day, other than a Saturday or Sunday, on which banks in The City of New York, New York are not required or authorized by law to close. As used herein, the term "Record Date" with respect to any Interest Payment Date shall mean the fifteenth day (whether or not such day is a Business Day) next preceding such Interest Payment Date. The principal of the Bonds of the 2030 Series shall be payable in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts at the office or agency of the Trustee located in Minneapolis, Minnesota or such other office of the Trustee that functions as its financial operations center, and interest on such Bonds of the 2030 Series shall be payable in like coin or currency at said office or agency.

The Company shall provide written notice to the Trustee of the Original Issue Date no later than five days before such date.

Upon compliance with the provisions of Section 2.06 of the Mortgage and as provided in this Supplemental Indenture, and upon payment of any taxes or other governmental charges payable upon such exchange, Bonds of the 2030 Series may be exchanged for a new Bond or

14

Bonds of the 2030 Series of different authorized denominations of like aggregate principal amount. The Trustee hereunder shall, by virtue of its office as such Trustee, be the registrar and transfer agent of the Company for the purpose of registering permitted transfers of Bonds of the 2030 Series.

Notwithstanding the provisions of Section 2.11 of the Mortgage, no service charge shall be made for any exchange or registration of transfer of Bonds of the 2030 Series, but the Company or the Trustee at either of their option may require payment of a sum sufficient to cover any tax or other governmental charge incident thereto.

SECTION 1.02.    Redemption Provisions for Bonds of the 2030 Series. The Bonds of the 2030 Series may be redeemed prior to maturity at any time, in whole or in part, upon prior notice given by mailing such notice to the respective registered owners of such Bonds of the 2030 Series not less than thirty nor more than ninety days prior to the redemption date and as otherwise required by the provisions of Article Nine of the Mortgage, at the option of the Company, at a redemption price equal to the greater of (i) 100 percent of the principal amount of the portion of the Bonds of the 2030 Series to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest (not including any portion of such payments of interest accrued as of the date of redemption) due on the Bonds of the 2030 Series (or portion thereof) to be redeemed, discounted to the redemption date on a semi-annual basis (assuming a 360‑day year consisting of twelve 30-day months) at the Adjusted Treasury Rate, plus 50 basis points, together in each case with accrued and unpaid interest to the date of redemption. The Company shall give the Trustee notice of such redemption price immediately after the calculation thereof, and the Trustee shall have no responsibility for such calculation.

Notwithstanding the provisions of Section 9.03 of the Mortgage, in the case of any partial redemption of the Bonds of the 2030 Series, the principal amount of the Bonds to be redeemed shall be allocated pro rata among all holders of such Bonds of the 2030 Series at the time outstanding and in accordance with the unpaid principal amount thereof.

The following definitions shall apply for purposes of this Section 1.02:

(a) "Adjusted Treasury Rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Adjusted Treasury Rate shall be calculated on the third Business Day preceding the redemption date.

(b) "Comparable Treasury Issue" means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Bonds of the 2030 Series to be redeemed that would be utilized, at the time of selection and in accordance withcustomary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Bonds of the 2030 Series.

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(c) "Comparable Treasury Price" means, with respect to any redemption date, (A) the average of four Reference Treasury Dealer Quotations for the redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations for the redemption date, or (B) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

(d) "Independent Investment Banker" means an independent investment and banking institution of national standing appointed by the Company.

(e) "Reference Treasury Dealer" means a primary U.S. Government securities dealer in New York City selected by the Independent Investment Banker.

(f) "Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the fourth Business Day preceding the redemption date.

SECTION 1.03.    Sections 4.04, 4.05, and 4.06 to Remain in Effect. Notwithstanding the provisions of Sections 4.04, 4.05, 4.06, and 4.07 of the Mortgage, the provisions of Sections 4.04, 4.05, and 4.06 of the Mortgage shall remain in full force and effect and shall be performed by the Company so long as any Bonds of the 2030 Series remain outstanding.

SECTION 1.04.    Certain Requirements of Mortgage to Remain Applicable. The requirements which are stated in the next to the last paragraph of Section 1.13 and in Clause (9) of Paragraph A of Section 3.01 of the Mortgage to be applicable so long as any of the Bonds of the 1975 Series are outstanding shall remain applicable so long as any of the Bonds of the 2030 Series are outstanding.

SECTION 1.05.    Certain Exceptions to Sections 2.06 and 2.10 of the Mortgage. Notwithstanding the provisions of Section 2.06 or Section 2.10 of the Mortgage, the Company shall not be required (a) to issue, register, discharge from registration, exchange, or register the transfer of any Bond of the 2030 Series for a period of fifteen days next preceding any selection by the Trustee of Bonds of the 2030 Series to be redeemed or (b) to register, discharge from registration, exchange, or register the permitted transfer of any Bond of the 2030 Series so selected for redemption in its entirety or (c) to exchange or register the permitted transfer of any portion of a Bond of the 2030 Series which portion has been so selected for redemption.

SECTION 1.06.    Reference to Minimum Provision for Depreciation in Certificate of Available Additions. So long as any Bonds of the 2030 Series remain outstanding, all references to the minimum provision for depreciation in the form of certificate of available additions set forth in Section 3.03 of the Mortgage shall be included in any certificate of available additions filed with the Trustee, but whenever Bonds of the 2030 Series shall no longer be outstanding, all

16

references to such minimum provisions for depreciation may be omitted from any such certificate.

SECTION 1.07.    Reporting Obligations. To the extent the Company is no longer required to file or does not voluntarily file the following documents with the Securities and Exchange Commission (the "SEC"), so long as any Bonds of the 2030 Series are outstanding, the Company shall furnish to the Trustee, within the time periods specified in the SEC's rules and regulations, the following:

(a) All quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10‑Q and 10‑K if the Company were required to file such forms, including a "Management's Discussion and Analysis of Financial Condition and Results of Operations" that describes the financial condition and results of operations of the Company and its consolidated subsidiaries and, with respect to the annual information only, a report thereon by the Company's certified independent accountants.

(b) All current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

The Trustee shall retain such documents in accordance with its customary procedures.

Delivery of such reports, information, and documents to the Trustee is for informational purposes only and the Trustee's receipt of such shall not constitute constructive notice of any information contained therein or determinable from information contained therein (as to which the Trustee may rely solely on Officers' Certificates).

SECTION 1.08.    CUSIP, ISIN, Private Placement, or Common Code Numbers. The Company in issuing the Bonds of the 2030 Series may use "CUSIP," "ISIN," "Private Placement, " or "Common Code" numbers (if then generally in use) and, if so, the Trustee shall use such numbers in notices of redemption or repurchase as a convenience to holders; provided, however, that any such notice may state that no representation is made as to the correctness of such numbers either as printed on the bonds or as contained in any notice of a redemption or repurchase and that reliance may be placed only on the other identification numbers printed on the bonds, and any such redemption or repurchase shall not be affected by any defect in or omission of such numbers. The Company shall promptly notify the Trustee in writing of any change in "CUSIP," "ISIN," "Private Placement," or "Common Code" numbers.

SECTION 1.09    Duration of Article One. This Article One shall be of force and effect only so long as any Bonds of the 2030 Series are outstanding.

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ARTICLE TWO.TRUSTEE.

SECTION 2.01.    Duties of Trustee. The Trustee hereby accepts the trust hereby created. The Trustee undertakes, prior to the occurrence of an event of default and after the curing of all events of default which may have occurred, to perform such duties and only such duties as are specifically set forth in the Original Indenture as heretofore and hereby supplemented and modified, on and subject to the terms and conditions set forth in the Original Indenture as so supplemented and modified, and in case of the occurrence of an event of default (which has not been cured) to exercise such of the rights and powers vested in it by the Original Indenture as so supplemented and modified, and to use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs.

The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the Bonds issued hereunder or the due execution thereof by the Company. The Trustee shall be under no obligation or duty with respect to the filing, registration, or recording of this Supplemental Indenture or the re-filing, re-registration, or re-recording thereof. The recitals of fact contained herein or in the Bonds (other than the Trustee's authentication certificate) shall be taken as the statements solely of the Company, and the Trustee assumes no responsibility for the correctness thereof.

ARTICLE THREE.
MISCELLANEOUS PROVISIONS.

SECTION 3.01.    Date of thisSupplemental Indenture. Although this Supplemental Indenture, for convenience and for the purpose of reference, is dated January 1, 2015, the actual date of execution by the Company and by the Trustee is as indicated by their respective acknowledgments hereto annexed.

SECTION 3.02.    Relation to Original Indenture. This Supplemental Indenture is executed and shall be construed as an indenture supplemental to the Original Indenture as heretofore supplemented and modified, and as supplemented and modified hereby, the Original Indenture as heretofore supplemented and modified is in all respects ratified and confirmed, and the Original Indenture as heretofore and hereby supplemented and modified shall be read, taken, and construed as one and the same instrument. All terms used in this Supplemental Indenture shall be taken to have the same meaning as in the Original Indenture except in cases where the context clearly indicates otherwise.

SECTION 3.03.    Invalid, Illegal, or Unenforceable Provisions. In case any one or more of the provisions contained in this Supplemental Indenture or in the Bonds shall for any reason be held to be invalid, illegal, or unenforceable in any respect, such invalidity, illegality, or unenforceability shall not affect any other provisions of this Supplemental Indenture, but this Supplemental Indenture shall be construed as if such invalid or illegal or unenforceable provision had never been contained herein.

18

SECTION 3.04.    Counterparts. This Supplemental Indenture may be executed in any number of counterparts, and each of such counterparts shall for all purposes be deemed to be an original, and all such counterparts, or as many of them as the Company and the Trustee shall preserve undestroyed, shall together constitute but one and the same instrument.

SECTION 3.05.    Conflicting Provision. If any provision of this Supplemental Indenture conflicts with another provision of the Mortgage required to be included in indentures qualified under the Trust Indenture Act of 1939 (as enacted prior to the date of this Supplemental Indenture) by any of the provisions of said Act, such required provision shall control.

SECTION 3.06.    Headings. Article and Section headings and the table of contents used herein are for convenience of reference only, are not part of this Supplemental Indenture, and are not to affect the construction of, or to be taken into consideration in interpreting, this Supplemental Indenture.

SECTION 3.07.    Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK DETERMINED WITHOUT REFERENCE TO PRINCIPLES OF CONFLICTS OF LAWS (OTHER THAN SECTION 5‑1401 OF THE GENERAL OBLIGATIONS LAW OF THE STATE OF NEW YORK), PROVIDED THAT THE FOREGOING SHALL NOT APPLY TO THE CREATION OR ENFORCEMENT OF ANY LIEN ON REAL PROPERTY CREATED BY THE INDENTURE, WHICH SHALL BE GOVERNED BY THE LAWS OF THE STATE IN WHICH SUCH REAL PROPERTY IS LOCATED.

SECTION 3.08.    Addresses for Notices to the Trustee. Any notice, direction, request or demand hereunder to or upon the Trustee shall be in writing (including facsimile and electronic mail in PDF format) and shall be deemed to have been sufficiently given or made, for all purposes, if given or served by overnight courier, facsimile, electronic mail in PDF format, or by being deposited postage prepaid by registered or certified mail in a post office letter box, addressed to the Trustee at: Wells Fargo Bank, National Association, Attn: Corporate, Municipal & Escrow Services, 333 S. Grand Avenue, 5th Floor Suite 5A, MAC E2604-05A, Los Angeles, CA 90071, Facsimile: 213.253.7598. The Trustee, by notice to the Company, may designate additional or different addresses for subsequent notices or communications.

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EX-12.1

EXHIBIT 12.1

PORTLAND GENERAL ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in thousands)
	Years Ended December 31,
	2014		2013		2012		2011		2010
Income from continuing operations before income taxes	$	236,679	$	125,758	$	205,406	$	204,714	$	178,158
Total fixed charges	128,515		118,189		122,851		126,766		131,486
Total earnings	$	365,194	$	243,947	$	328,257	$	331,480	$	309,644
Fixed charges:
Interest expense	$	96,068	$	100,818	$	107,992	$	110,413	$	110,240
Capitalized interest	22,441		6,892		3,699		3,059		9,097
Interest on certain long-term power contracts	5,137		5,996		6,643		8,764		8,068
Estimated interest factor in rental expense	4,869		4,483		4,517		4,530		4,081
Total fixed charges	$	128,515	$	118,189	$	122,851	$	126,766	$	131,486
Ratio of earnings to fixed charges	2.84		2.06		2.67		2.61		2.35

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-192274 on Form S-3 and Registration Statement Nos. 333-135726, 333-142694, and 333-158059on Form S-8 of our report dated February 12, 2015, relating to the consolidated financial statements of Portland General Electric Company and subsidiaries, and the effectiveness of Portland General Electric Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Portland General Electric Company for the year ended December 31, 2014.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 12, 2015

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, James J. Piro, certify that:

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.

Date: February 12, 2015	/s/ JAMES J. PIRO
	James J. Piro
	President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, James F. Lobdell, certify that:

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.

Date: February 12, 2015	/s/ JAMES F. LOBDELL
	James F. Lobdell
	Senior Vice President of Finance, Chief Financial Officer, and Treasurer

EX-32.1

EXHIBIT 32.1

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

We, James J. Piro, President and Chief Executive Officer, and James F. Lobdell, Senior Vice President of Finance, Chief Financial Officer and Treasurer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on February 13, 2015 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”), fully complies with the requirements of that section.

We further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ JAMES J. PIRO	/s/ JAMES F. LOBDELL
James J. Piro	James F. Lobdell
President and Chief Executive Officer	Senior Vice President of Finance, Chief Financial Officer and Treasurer
Date: February 12, 2015	Date: February 12, 2015

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Price Risk Management (Tables)

12 Months Ended

Dec. 31, 2014

Price Risk Management [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

	As of December 31,
	2014			2013
Current assets:
Commodity contracts:
Electricity	$	4		$	9
Natural gas	2			4
Total current derivative assets	6		(1)	13		(1)
Noncurrent assets:
Commodity contracts:
Electricity	1			1
Total noncurrent derivative assets	1		(2)	1		(2)
Total derivative assets not designated as hedging instruments	$	7		$	14
Total derivative assets	$	7		$	14
Current liabilities:
Commodity contracts:
Electricity	$	54		$	20
Natural gas	52			29
Total current derivative liabilities	106			49
Noncurrent liabilities:
Commodity contracts:
Electricity	58			107
Natural gas	64			34
Total noncurrent derivative liabilities	122			141
Total derivative liabilities not designated as hedging instruments	$	228		$	190
Total derivative liabilities	$	228		$	190

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

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

Schedule of Derivative Instruments [Table Text Block]

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): 

	As of December 31,
	2014			2013
Commodity contracts:
Electricity	16		MWh	14		MWh
Natural gas	127		Dth	106		Dth
Foreign currency exchange	$	7	Canadian	$	7	Canadian

Price risk management assets and liabilties subject to master netting agreements [Table Text Block]

price risk management liabilities subject to master netting agreements is as follows (in millions):

	Gross		Gross		Net		Gross Amounts Not Offset in
	Amounts		Amounts		Amounts		Consolidated Balance Sheets
	Recognized		Offset		Presented		Derivatives			Cash Collateral(1)		Net Amount
As of December 31, 2014:
Liabilities:
Commodity contracts:
Electricity(2)	$	55	$	—	$	55	$	(55	)	$	—	$	—
Natural gas(2)	17		—		17		(17		)	—		—
	$	72	$	—	$	72	$	(72	)	$	—	$	—
As of December 31, 2013:
Liabilities:
Commodity contracts:
Electricity(2)	$	91	$	—	$	91	$	(91	)	$	—	$	—
Natural gas(2)	1		—		1		(1		)	—		—
	$	92	$	—	$	92	$	(92	)	$	—	$	—

(1) As of December 31, 2014 and 2013, the Company had collateral posted of $11 million and $7 million, respectively, which consists entirely of letters of credit.

(2) Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

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

	Years Ended December 31,
	2014		2013		2012
Commodity contracts:
Electricity	$	13	$	78	$	56
Natural Gas	72		28		19
Foreign currency exchange	—		1		—

Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2014, 2013, and 2012, $83 million, $120 million, and $42 million, respectively, have been offset.

Schedule of Price Risk Derivatives [Table Text Block]

Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 2014 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):

	2015		2016		2017		2018		2019		Thereafter		Total
Commodity contracts:
Electricity	$	50	$	19	$	6	$	5	$	5	$	22	$	107
Natural gas	49		44		18		3		—		—		114
Net unrealized loss	$	99	$	63	$	24	$	8	$	5	$	22	$	221

Schedule of Concentration of Risk, by Counterparty [Table Text Block]

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

	As of December 31,
	2014		2013
Assets from price risk management activities:
Counterparty A	63	%	53	%
Counterparty B	14		6
	77	%	59	%
Liabilities from price risk management activities:
Counterparty C	22	%	43	%
Counterparty D	12		11
	34	%	54	%

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Balance Sheet Components Investments Held in Trust (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Marketable securities, at fair value:
Decommissioning Fund Investments, Fair Value	$ 90	$ 82
Non-qualified benefit plan trust	32	35
Nuclear Decommissioning [Member]
Cash equivalents	65	59
Marketable securities, at fair value:
Equity securities	0	0
Debt securities	25	23
Insurance contracts, at cash surrender value	0	0
Decommissioning Fund Investments, Fair Value	90	82
Non Qualified Benefit Plans [Member]
Cash equivalents	0	0
Marketable securities, at fair value:
Equity securities	6	8
Debt securities	0	1
Insurance contracts, at cash surrender value	26	26
Non-qualified benefit plan trust	$ 32	$ 35

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Commitments and Guarantees (Tables)

12 Months Ended

Dec. 31, 2014

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

As of December 31, 2014, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):

	Payments Due
	2015		2016		2017		2018		2019		Thereafter		Total
Capital and other purchase commitments	$	242	$	21	$	2	$	2	$	2	$	74	$	343
Purchased power and fuel:
Electricity purchases	179		167		140		143		143		833		1,605
Capacity contracts	27		26		6		6		5		20		90
Public utility districts	8		7		5		4		2		23		49
Natural gas	56		37		40		40		36		244		453
Coal and transportation	23		14		11		5		5		—		58
Operating leases	10		11		12		11		8		192		244
Total	$	545	$	283	$	216	$	211	$	201	$	1,386	$	2,842

Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block]

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

	Revenue Bonds as of December 31, 2014		PGE’s Share as of December 31, 2014			Contract Expiration	PGE Cost, including Debt Service
			Output		Capacity		2014		2013		2012
					(in MW)
Priest Rapids and Wanapum	$	1,102	8.6	%	163	2052	$	14	$	14	$	14
Wells	215		19.4		150	2018	10		10		10
Portland Hydro	4		100.0		36	2017	4		4		4

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Schedule of Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 41	$ 41
Utility plant	64	49
Non-utility property	11	10
Asset Retirement Obligation	$ 116	$ 100	$ 94	$ 87

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Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other current assets:
Prepaid Expense, Current	$ 39	$ 38
Current deferred income tax asset	33	42
accrued sales tax refund	23	0	0
Margin Deposit Assets	11	9
Assets from price risk management activities	6	13
Other	3	1
Other Assets, Current	115	103
Accrued expenses and other current liabilities:
Regulatory Liability, Current	60	1
Accrued employee compensation and benefits	51	46
Accrued interest payable	26	23
Dividends payable	23	22
Taxes Payable, Current	22	21
Other	54	58
Other Liabilities, Current	$ 236	$ 171

XML

Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	$ 32	$ 35
Non-qualified benefit plan liabilities	105	101
Other Postretirement Benefit Plans [Domain]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	0	0
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	17	19
Non-qualified benefit plan liabilities	80	79
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	15	16
Non-qualified benefit plan liabilities	25	22
Total Non-qualified benefit plan trust assets [Domain]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	32
Non-qualified benefit plan liabilities	$ 105	$ 101

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Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables)

12 Months Ended

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

RSU activity is summarized in the following table:

	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2011	491,404		$	18.54
Granted	186,495		24.72
Forfeited	(22,947	)	18.95
Vested	(214,390	)	15.67
Outstanding as of December 31, 2012	440,562		22.54
Granted	183,071		29.25
Forfeited	(7,007	)	27.15
Vested	(185,536	)	20.20
Outstanding as of December 31, 2013	431,090		26.31
Granted	203,410		31.49
Forfeited	(12,278	)	29.90
Vested	(158,329	)	24.95
Outstanding as of December 31, 2014	463,893		28.96

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions:

	2014				2013
Risk-free interest rate			0.6	%			0.3	%
Expected dividend yield			—	%			—	%
Expected term (in years)			3.0				3.0
Volatility	12.4%	-	23.0%		12.1%	-	25.1%

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Employee Benefits (Policies)

12 Months Ended

Dec. 31, 2014

Employee Benefits [Abstract]

pension and other postretirement benefits valuation methodology [Policy Text Block]

The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts.

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

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

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

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

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

Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

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

Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]

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

Non-qualified benefit [Policy Text Block]

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

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

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Employee Benefits Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Pension Plan [Member] | Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	67.00%	67.00%
Defined Benefit Plan, Actual Plan Asset Allocations	66.00%	67.00%
Defined Benefit Pension Plan [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	33.00%	33.00%
Defined Benefit Plan, Actual Plan Asset Allocations	34.00%	33.00%
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Other Postretirement Benefit Plans [Member] | Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	67.00%	58.00%
Defined Benefit Plan, Actual Plan Asset Allocations	66.00%	58.00%
Other Postretirement Benefit Plans [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	33.00%	42.00%
Defined Benefit Plan, Actual Plan Asset Allocations	34.00%	42.00%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Non Qualified Benefit Plans [Member] | Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	13.00%	16.00%
Defined Benefit Plan, Actual Plan Asset Allocations	19.00%	24.00%
Non Qualified Benefit Plans [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	7.00%	9.00%
Defined Benefit Plan, Actual Plan Asset Allocations	1.00%	1.00%
Non Qualified Benefit Plans [Member] | Other Contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	80.00%	75.00%
Defined Benefit Plan, Actual Plan Asset Allocations	80.00%	75.00%

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Revolving Credit Facilities Schedule of Short term debt (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Average daily amount of short-term debt outstanding	$ 0	$ 9	$ 4
Weighted daily average interest rate	0.00%	0.40%	0.40%
Maximum amount outstanding during the year	$ 0	$ 54	$ 44

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Income Taxes Income taxes (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Other		$ 17
Tax Credit Carryforward, Federal	10
Tax Credit Carryforward, State	3
Deferred Tax Assets, Valuation Allowance	0	0
Unrecognized Tax Benefits	$ 0	$ 0

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Fair Value of FInancial Instruments Schedule of Fair Value (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	$ 65	$ 59
Domestic government, Debt securities	14	14
Corporate debt securities held in decommissioning trust assets	11	9
Domestic Equity Securities	5	7
International Equity Securities	1	1
Debt securities - domestic government		1
Electricity	5	10
Natural gas	2	4
Financial Instruments, Owned, at Fair Value	103	105
Liabilities from price risk management activities: [Abstract]
Electricity	112	127
Natural gas	116	63
Liabilities, Fair Value Disclosure	228	190
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Domestic government, Debt securities	7	6
Corporate debt securities held in decommissioning trust assets	0	0
Domestic Equity Securities	4	4
International Equity Securities	1	1
Debt securities - domestic government		1
Electricity	0	0
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	12	12
Liabilities from price risk management activities: [Abstract]
Electricity	0	0
Natural gas	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	65	59
Domestic government, Debt securities	7	8
Corporate debt securities held in decommissioning trust assets	11	9
Domestic Equity Securities	1	3
International Equity Securities	0	0
Debt securities - domestic government		0
Electricity	4	9
Natural gas	2	4
Financial Instruments, Owned, at Fair Value	90	92
Liabilities from price risk management activities: [Abstract]
Electricity	32	10
Natural gas	95	40
Liabilities, Fair Value Disclosure	127	50
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Domestic government, Debt securities	0	0
Corporate debt securities held in decommissioning trust assets	0	0
Domestic Equity Securities	0	0
International Equity Securities	0	0
Debt securities - domestic government		0
Electricity	1	1
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	1	1
Liabilities from price risk management activities: [Abstract]
Electricity	80	117
Natural gas	21	23
Liabilities, Fair Value Disclosure	101	140
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 26	$ 26

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Long-term Debt Schedule of Maturities of Long term debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]
2015	$ 375
2016	67
2017	58
2018	75
2019	300
Thereafter	1,626
Total long-term debt	$ 2,501	$ 1,916

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Income Taxes Schedule of Components of Income Tax Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$ 20	$ 10	$ 16
State and local	2	0	1
Current Income Tax Expense (Benefit)	22	10	17
Deferred:
Federal	26	4	30
State and local	13	7	17
deferred income tax expense	39	11	47
Income tax expense	$ 61	$ 21	$ 64

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Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 591	$ 596
Unrealized gain on assets	2	4
Available-for-sale Securities, Gross Realized Gain (Loss)	3	(2)
Purchases and sales, net	$ (7)	$ (3)

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Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
Federal tax credits	(11.40%)	(21.80%)	(11.80%)
State and local taxes, net of federal tax benefit	3.90%	3.40%	3.50%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance	0.00%	0.00%	2.60%
Flow through depreciation and cost basis differences	(2.30%)	2.80%	2.40%
Other	0.80%	(2.60%)	(0.60%)
Effective tax rate	26.00%	16.80%	31.10%

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Long term debt (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended			12 Months Ended			1 Months Ended
	Nov. 30, 2014	Dec. 31, 2014	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond					$ 280
Long-term Pollution Control Bond		21			21
Pollution Control Bonds Retired				(6)
Debt Instrument, Interest Rate, Stated Percentage	3.51%	4.44%	4.39%		4.44%
Proceeds from Issuance of Long-term Debt	80	100	100		585	380	0
Unsecured Debt, Current		305			305	0
Debt Instrument, Description of Variable Rate Basis					70
First mortgage Bonds - minimum rate		3.46%			3.46%	3.46%
First Mortgage Bonds - maximum rate		9.31%			9.31%	9.31%
Debt, Weighted Average Interest Rate		5.42%			5.42%	5.62%
Unsecured term bank loan rate - minimum		0.86%			0.86%
Unsecured term bank loan rate - maximum		0.93%			0.93%
Pollution Control Revenue Bonds owned by PGE		21			21	27
Long-term Pollution Control Bond, Rate		5.00%			5.00%	5.00%
Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								3.55%
Proceeds from Issuance of Long-term Debt								$ 75

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Schedule of Change in Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation			$ 100	$ 94	$ 87
Asset Retirement Obligation, Liabilities Incurred	7	8	15	4	0
Asset Retirement Obligation, Liabilities Settled			(3)	(4)	(3)
Asset Retirement Obligation, Accretion Expense			6	6	6
Asset Retirement Obligation, Revision of Estimate			2	0	4
Asset Retirement Obligation	$ 116	$ 116	$ 116	$ 100	$ 94

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Variable Interest Entities

12 Months Ended

Dec. 31, 2014

Variable interest Entities [Abstract]

VariableInterestEntities [Text Block]

VARIABLE INTEREST ENTITIES

PGE has determined that as of December 31, 2014it is the primary beneficiary of two VIEs(three as of December 31, 2013), and, therefore, consolidates the VIEs within the Company’s consolidated financial statements. Such arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties, and selling the energy generated by the facilities. The Company is the Managing Member and a financial institution is the Investor Member in each of the Limited Liability Companies (LLCs), holding equity interests of less than 1% and more than 99%, respectively, in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

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

Included in PGE’s consolidated balance sheets as of December 31, 2014 and 2013 are LLC net assets of $4 million and $5 million, respectively, primarily comprised of Electric utility plant, and includes Cash and cash equivalents of $1 million as of December 31, 2013. These assets can only be used to settle the obligations of the consolidated VIEs and their creditors have no recourse to the general credit of PGE.

In January 2015, PGE acquired the equity interest held by the Investor Member of one of the LLCs pursuant to the terms of the operating agreement. The transaction did not have a significant impact to the Company’s consolidated financial position, consolidated results of operations or consolidated cash flows.

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Basis of Presentation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 sqmi	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Basis of Presentation [Abstract]
Incorporated Cities	52
Service Area Sq Miles	4,000
Number of Retail Customers	842,273
Service area population	1,800,000
Percent of State's Population	46.00%
Entity Number of Employees	2,600
Number of Union Employees	780
Number of Union Employees Subject to Agreement A	743
Number of Union Employees Subject to Agreement B	37
revenue overstatment		$ 9	$ 3	$ 3	$ 2	$ 1
Margin Deposit Assets	11	9
Renewable adjustment clause deferrals			1
Cash Received from BPA	$ 13	$ 1	$ 0

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Revolving Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2014

Line of Credit Facility [Abstract]

Schedule of Short-term Debt [Table Text Block]

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

	Years Ended December 31,
	2014			2013			2012
Average daily amount of short-term debt outstanding	$	—		$	9		$	4
Weighted daily average interest rate *	—		%	0.4		%	0.4		%
Maximum amount outstanding during the year	$	—		$	54		$	44

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

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Long-term Debt Schedule of Long Term Debt Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048	$ 2,075	$ 1,795
Unsecured Debt, Current	305	0
Pollution Control Revenue Bonds, 5% rate, due 2033	142	148
Pollution Control Revenue Bonds owned by PGE	(21)	(27)
Total long-term debt	2,501	1,916
Less: current portion of long-term debt	(375)	0
Long-term debt, net of current portion	$ 2,126	$ 1,916

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Commitments and Guarantees (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrecorded Unconditional Purchase Obligation [Line Items]
Other Commitment	$ 43
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	14
Other Commitment, Due in Second Year	11
Other Commitment, Due in Third Year	11
Other Commitment, Due in Fourth Year	7
Operating Leases, Future Minimum Payments, Due in Three Years	1
percentage of output	25.00%
Operating Leases, Rent Expense	11	9	10
Operating Leases, Future Minimum Payments Receivable, Current	3
Operating Leases, Future Minimum Payments Receivable, in Two Years	2
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Five Years	1
Operating Leases, Rent Expense, Sublease Rentals	3	3	3
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Three Years	$ 1

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Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2014

Balance Sheet Components [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

The following is the activity in the allowance for uncollectible accounts (in millions):

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	6		$	5		$	6
Increase in provision	6			6			6
Amounts written off, less recoveries	(6		)	(5		)	(7		)
Balance as of end of year	$	6		$	6		$	5

Investments held in trust [Table Text Block]

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

	Nuclear     Decommissioning Trust				Non-Qualified Benefit     Plan Trust
	2014		2013		2014		2013
Cash equivalents	$	65	$	59	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		6		8
Debt securities	25		23		—		1
Insurance contracts, at cash surrender value	—		—		26		26
	$	90	$	82	$	32	$	35

Schedule of Other Assets and Other Liabilities [Table Text Block]

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

	As of December 31,
	2014		2013
Other current assets:
Prepaid expenses	$	39	$	38
Current deferred income tax asset	33		42
Accrued sales tax refund related to Tucannon River Wind Farm	23		—
Margin deposits	11		9
Assets from price risk management activities	6		13
Other	3		1
	$	115	$	103
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	60	$	1
Accrued employee compensation and benefits	51		46
Accrued interest payable	26		23
Dividends payable	23		22
Accrued taxes payable	22		21
Other	54		58
	$	236	$	171

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Other Investments	$ 120	$ 104
Business days after the invoice date	16
Days after the due date	45
Wholesale accounts receivable written off	0	0	0
Margin deposit	11	9
Letters of Credit Outstanding, Amount	30	29
Expenses related to Cascade Crossing	0	52	0
Public Utilities, Allowance for Funds Used During Construction, Rate	7.40%	7.50%	7.50%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	22	7	4
Allowance for equity funds used during construction	37	13	6
Depreciation expense rate	3.60%	3.70%	3.80%
Asset Retirement Removal Costs Included in Depreciation Expense	57	55	55
Finite-Lived Intangible Assets, Accumulated Amortization	191	170
Amortization of Intangible Assets	25	22	22
Future Amortization Expense, Year One	35
Future Amortization Expense, Year Two	33
Future Amortization Expense, Year Three	29
Future Amortization Expense, Year Four	28
Future Amortization Expense, Year Five	22
Power Cost Deadband - Lower Threshold	15
Power Cost Deadband - Upper Threshold	30
Public Utilities, Approved Return on Equity, Percentage	9.75%	10.00%	10.00%
Net Variable Power Cost Underrun	(7)		(17)
Net variable power cost overrun		11
Estimated Refund Under Power Cost Adjustment Mechanism	0	0	0
Actual Refund Under Power Cost Adjustment Mechanism		0	0
Franchise taxes	42	41	42
Deferred Tax Assets, Regulatory Assets and Liabilities	48	33
Noncurrent Regulatory Assets [Member]
Property, Plant and Equipment [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities	86	76
Noncurrent Regulatory Liabilities [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligations, Noncurrent	$ 39	$ 39

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Price Risk Management (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative, Collateral, Master Netting Arrangements, Letters of Credit	$ 11	$ 7
Net gain or loss recognized in the statement of income offset by regulatory accounting	83	120	42
Derivative, Net Liability Position, Aggregate Fair Value	216
Collateral Already Posted, Aggregate Fair Value	29
Collateral Aggregate Fair Value	213
Margin Deposit Assets	$ 11	$ 9

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Fair values of price risk management assets and liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets, Commodity Contracts:
Electricity	$ 4	$ 9
Natural Gas	2	4
Total current derivative assets	6	13
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	1	1
Derivative Asset, Noncurrent	1	1
Total derivative assets not designated as hedging instruments	7	14
Total derivative assets	7	14
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	54	20
Natural Gas	52	29
Total current derivative liabilities	106	49
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	58	107
Natural Gas	64	34
Total noncurrent derivative liabilities	122	141
Total derivative liabilities not designated as hedging instruments	228	190
Total derivative liabilities	$ 228	$ 190

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Years Ended December 31,
	2014	2013	2012
Weighted average common shares outstanding—basic	78,180	76,821	75,498
Dilutive effect of potential common shares	2,314	567	149
Weighted average common shares outstanding—diluted	80,494	77,388	75,647

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income	$ 174	$ 104	$ 140
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	301	248	248
Increase (decrease) in net liabilities from price risk management activities	45	(18)	(175)
Regulatory deferrals—price risk management activities	(45)	18	172
Cascade Crossing transmission project	0	52	0
Deferred income taxes	39	11	47
Allowance for equity funds used during construction	(37)	(13)	(6)
Pension and other postretirement benefits	33	37	27
Regulatory deferral of settled derivative instruments	10	7	(9)
Unrealized losses on non-qualified benefit plan trust assets	7	3	3
Decoupling mechanism deferrals, net of amortization	6	(6)	2
Power cost deferrals, net of amortization	0	(6)	(4)
Other non-cash income and expenses, net	12	18	17
Changes in working capital, net of effects from purchase of 10% interest in Boardman:
Decrease (increase) in receivables and unbilled revenues	8	0	(4)
(Increase) decrease in margin deposits	(2)	37	34
Income tax refund received	0	0	8
(Decrease) increase in payables and accrued liabilities	(13)	14	1
Other working capital items, net	(12)	17	1
Cash received to be returned to customers pursuant to the Residential Exchange Program	13	1	0
Proceeds received from Trojan spent fuel legal settlement	6	44	0
Contribution to non-qualified employee benefit trust	(8)	(6)	0
Contribution to voluntary employees’ benefit association trust	(3)	(3)	(2)
Other, net	(16)	(15)	(6)
Net cash provided by operating activities	518	544	494
Cash flows from investing activities:
Capital expenditures	(1,007)	(656)	(303)
Purchases of nuclear decommissioning trust securities	(19)	(26)	(26)
Sales of nuclear decommissioning trust securities	17	25	23
Contribution to nuclear decommissioning fund	(6)	(44)	0
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid	8	0	0
Proceeds received from insurance recoveries	3	6	0
Proceeds from sale of properties	5	0	10
Other, net	5	3	2
Net cash used in investing activities	(994)	(692)	(294)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	585	380	0
Payments on long-term debt	0	(100)	(100)
Proceeds from issuance of common stock, net of issuance costs	0	67	0
Borrowings on short-term debt	0	35	0
Payments on short-term debt	0	(35)	0
Maturities of commercial paper, net	0	(17)	(13)
Dividends paid	(87)	(84)	(81)
Debt issuance costs	(2)	(3)	0
Net cash provided by (used in) financing activities	496	243	(194)
Increase in cash and cash equivalents	20	95	6
Cash and cash equivalents, beginning of year	107	12	6
Cash and cash equivalents, end of year	127	107	12
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	86	90	97
Cash paid for income taxes	22	10	13
Non-cash investing and financing activities:
Accrued capital additions	70	84	19
Accrued dividends payable	23	22	21
Accrued sales tax refund	23	0	0
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	$ 0	$ 9	$ 0

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Net volumes related to price risk management activities (Details) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014 MMBTU MWh	Dec. 31, 2013 MWh MMBTU
Commodity contracts: [Abstract]
Electricity	16,000,000	14,000,000
Natural gas	127,000,000	106,000,000
Foreign currency exchange	7	7

XML

Long term debt (Tables)

12 Months Ended

Dec. 31, 2014

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

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

	As of December 31,
	2014			2013
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048	$	2,075		$	1,795
Unsecured term bank loans, rates range from 0.86% to 0.93%, due October 2015	305			—
Pollution Control Revenue Bonds, 5% rate, due 2033	142			148
Pollution Control Revenue Bonds owned by PGE	(21		)	(27		)
Total long-term debt	2,501			1,916
Less: current portion of long-term debt	(375		)	—
Long-term debt, net of current portion	$	2,126		$	1,916

Schedule of Maturities of Long-term Debt [Table Text Block]

As of December 31, 2014, the future minimum principal payments on long-term debt are as follows (in millions):

Years ending December 31:
2015	$	375
2016	67
2017	58
2018	75
2019	300
Thereafter	1,626
	$	2,501

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Cash and Cash Equivalents, Policy [Policy Text Block]

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents,

Trade and Other Accounts Receivable, Policy [Policy Text Block]

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice.

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

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable.

Derivatives, Policy [Policy Text Block]

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument.

Electricity sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets

Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block]

Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet

Inventory, Policy [Policy Text Block]

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

Property, Plant and Equipment, Policy [Policy Text Block]

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

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made.

Allowance for Funds Used During Construction, Policy [Policy Text Block]

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income.

Regulatory Depreciation and Amortization, Policy [Policy Text Block]

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage.

Depreciation Lives [Policy Text Block]

Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives,

Plant Retirement and Abandonment, Policy [Policy Text Block]

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

Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block]

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years.

Marketable Securities, Policy [Policy Text Block]

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.

Public Utilities, Policy [Policy Text Block]

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

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

Power Cost [Policy Text Block]

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while 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. PGE’s authorized ROE was 9.75% for 2014, and 10% for 2013 and for 2012.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review.

Asset Retirement Obligations, Policy [Policy Text Block]

An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

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

Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.

Commitments and Contingencies, Policy [Policy Text Block]

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

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

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

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

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

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

Revenue Recognition, Policy [Policy Text Block]

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation.

Franchise Tax [Policy Text Block]

Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes

Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]

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

As a rate-regulated utility, there are situations in which PGE recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

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

Income Tax, Policy [Policy Text Block]

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

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability.

Income Tax Uncertainties, Policy [Policy Text Block]

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

Interest and Penalties Related to Income Taxes [Policy Text Block]

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

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Basis of Presentation Basis of Presentation (Policies)

12 Months Ended

Dec. 31, 2014

Basis of Presentation [Abstract]

Consolidation, Policy [Policy Text Block]

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

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

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Jointly-owned Plant Jointly Owned Plant (Details) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 1985
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman transferred	10.00%	10.00%	10.00%	15.00%			15.00%
Property, Plant and Equipment, Additions	$ 7,000,000	$ 7,000,000	$ 7,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory	4,000,000	4,000,000	4,000,000
Asset Retirement Obligation, Liabilities Incurred	7,000,000	8,000,000	15,000,000	4,000,000	0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	6,000,000	6,000,000	6,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities	4,000,000	4,000,000	4,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	2,000,000	2,000,000	2,000,000
Asset Retirement Obligation Increase related to Boardman plant				7,000,000
Interest in Pacific Northwest Intertie							10.714%
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	$ 8,000,000	$ 8,000,000	$ 8,000,000	$ 1
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman	90.00%	90.00%	90.00%	80.00%		65.00%

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Balance Sheet Components (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Allowance for Doubtful Accounts Receivable, Current		$ 6	$ 6	$ 5	$ 6
Proceeds from Legal Settlements	$ 50	$ 6	$ 44	$ 0

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Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2014

Employee Benefits [Abstract]

Assets and Liabilities associated with Non Qualified Benefit Plans [Table Text Block]

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

	2014						2013
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	15	$	17	$	32	$	16	$	19	$	35
Non-qualified benefit plan liabilities *	25		80		105		22		79		101

* For the NQBP, excludes the current portion of $2 million in 2014 and in 2013, which is classified in Other current liabilities in the consolidated balance sheets.

Schedule of Allocation of Plan Assets [Table Text Block]

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

	As of December 31,
	2014				2013
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	66	%	67	%	67	%	67	%
Debt securities	34		33		33		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	66	%	67	%	58	%	58	%
Debt securities	34		33		42		42
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	19	%	13	%	24	%	16	%
Debt securities	1		7		1		9
Insurance contracts	80		80		75		75
Total	100	%	100	%	100	%	100	%

* The target for the Defined Benefit Pension 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.

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	65	$	—	$	65
Debt securities:
Domestic government	7		7		—		14
Corporate credit	—		11		—		11
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		1		—		5
International	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		4		1		5
Natural gas	—		2		—		2
	$	12	$	90	$	1	$	103
Liabilities - Liabilities from price risk management activities(1) (3):
Electricity	$	—	$	32	$	80	$	112
Natural gas	—		95		21		116
	$	—	$	127	$	101	$	228

(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 $26 million, which are recorded at cash surrender value.

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

	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	6		8		—		14
Corporate credit	—		9		—		9
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		3		—		7
International	1		—		—		1
Debt securities - domestic government	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		9		1		10
Natural gas	—		4		—		4
	$	12	$	92	$	1	$	105
Liabilities - Liabilities from price risk management activities (1) (3):
Electricity	$	—	$	10	$	117	$	127
Natural gas	—		40		23		63
	$	—	$	50	$	140	$	190

(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 $26 million, which are recorded at cash surrender value.

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

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2014:
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	$	42	$	146	$	—	$	188
International	—		171		—		171
Debt securities:
Domestic government and corporate credit	—		197		—		197
Private equity funds	—		—		29		29
	$	42	$	520	$	29	$	591
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	10		1		—		11
International	10		—		—		10
Debt securities—Domestic government	5		—		—		5
	$	25	$	7	$	—	$	32
As of December 31, 2013:
Defined Benefit Pension Plan assets:
Equity securities:
Domestic	$	166	$	19	$	—	$	185
International	185		—		—		185
Debt securities:
Domestic government and corporate credit	—		181		—		181
Corporate credit	14		—		—		14
Private equity funds	—		—		31		31
	$	365	$	200	$	31	$	596
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	10	$	—	$	10
Equity securities:
Domestic	8		2		—		10
International	9		—		—		9
Debt securities—Domestic government	3		—		—		3
	$	20	$	12	$	—	$	32

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy, which consists of Private equity funds, were as follows (in millions):

	Years Ended December 31,
	2014			2013
Level 3 balance as of beginning of year	$	31		$	32
Unrealized gains, net	2			4
Realized gains (losses), net	3			(2		)
Sales, net	(7		)	(3		)
Level 3 balance as of end of year	$	29		$	31

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2014 and 2013. Information related to the Other NQBP is not included in the following tables (dollars in millions):

	Defined Benefit Pension Plan						Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014			2013			2014			2013			2014			2013
Benefit obligation:
As of January 1	$	705		$	728		$	77		$	84		$	24		$	27
Service cost	15			17			2			2			—			—
Interest cost	34			30			4			3			1			1
Participants’ contributions	—			—			1			2			—			—
Actuarial (gain) loss	72			(38		)	4			(9		)	5			(2		)
Contractual termination benefits	—			—			1			1			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	777		$	705		$	83		$	77		$	27		$	24
Fair value of plan assets:
As of January 1	$	596		$	537		$	32		$	28		$	16		$	15
Actual return on plan assets	44			91			1			5			1			3
Company contributions	—			—			4			3			1			—
Participants’ contributions	—			—			1			2			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	591		$	596		$	32		$	32		$	15		$	16
Unfunded position as of December 31	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Accumulated benefit plan obligation as of December 31	$	691		$	631		N/A			N/A			$	27		$	24
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	15		$	16
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(186		)	(109		)	(51		)	(45		)	(25		)	(22		)
Net liability	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Amounts included in comprehensive income:
Net actuarial (gain) loss	$	67		$	(89	)	$	5		$	(11	)	$	5		$	(1	)
Amortization of net actuarial loss	(17		)	(24		)	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			(1		)	(1		)	—			—
	$	50		$	(113	)	$	3		$	(13	)	$	4		$	(2	)
Amounts included in AOCL*:
Net actuarial loss	$	236		$	186		$	10		$	6		$	13		$	9
Prior service cost	—			—			1			2			—			—
	$	236		$	186		$	11		$	8		$	13		$	9

	Defined Benefit Pension Plan				Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014		2013		2014			2013			2014		2013
Assumptions used:
Discount rate for benefit obligation	4.02	%	4.84	%	3.07	%	-	3.46	%	-	4.02	%	4.84	%
					4.10	%		4.96	%
Discount rate for benefit cost	4.84	%	4.24	%	3.46	%	-	2.77	%	-	4.84	%	4.24	%
					4.96	%		4.13	%
Weighted average rate of compensation increase for benefit obligation	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Weighted average rate of compensation increase for benefit cost	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Long-term rate of return on plan assets for benefit obligation	7.50	%	7.50	%	6.37	%		6.46	%		N/A		N/A
Long-term rate of return on plan assets for benefit cost	7.50	%	8.25	%	6.46	%		5.89	%		N/A		N/A

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

Schedule of Net Benefit Costs [Table Text Block]

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

	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2014			2013			2012			2014			2013			2012			2014		2013		2012
Service cost	$	15		$	17		$	14		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	34			30			31			4			3			3			1		1		1
Expected return on plan assets	(39		)	(40		)	(41		)	(2		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	—			—			—			1			1			1			—		—		—
Amortization of net actuarial loss	17			24			17			1			1			1			1		1		1
Net periodic benefit cost	$	27		$	31		$	21		$	6		$	6		$	6		$	2	$	2	$	2

Schedule of Expected Benefit Payments [Table Text Block]

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

	Payments Due
	2015		2016		2017		2018		2019		2020 - 2024
Defined benefit pension plan	$	35	$	37	$	38	$	40	$	41	$	221
Other postretirement benefits	5		5		5		5		5		26
Non-qualified benefit plans	2		2		2		2		3		9
Total	$	42	$	44	$	45	$	47	$	49	$	256

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Fair Value of Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2014

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments, Policy [Policy Text Block]

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2014 and 2013, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

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

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

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

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

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.

Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]

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

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

Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.

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

Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace.

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

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

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures and swaps.

Transfers in and out of Level 3 [Policy Text Block]

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Debt, Policy [Policy Text Block]

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities.

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Price Risk Management (Policies)

12 Months Ended

Dec. 31, 2014

Price Risk Management [Abstract]

Gross Reporting of Positive and Negative Exposures Related to Derivative Instruments [Policy Text Block]

PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit

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Consolidated Statements of Equity Consolidated Statement of Equity Parenthetical (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Issuance costs	$ 3
Common Stock, Dividends, Per Share, Declared	$ 1.115	$ 1.095	$ 1.075

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Asset Retirement Obligations (Policies)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations, Policy [Policy Text Block]

An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

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

Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.

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Employee Benefits Schedule of Net Benefit Costs (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 2	$ 2
Interest cost on benefit obligation	4	3	3
Expected return on plan assets	(2)	(1)	(1)
Amortization of prior service cost	1	1	1
Amortization of net actuarial loss	1	1	1
Net periodic benefit cost	6	6	6
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	15	17	14
Interest cost on benefit obligation	34	30	31
Expected return on plan assets	(39)	(40)	(41)
Amortization of prior service cost	0	0	0
Amortization of net actuarial loss	17	24	17
Net periodic benefit cost	27	31	21
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Expected return on plan assets	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net actuarial loss	1	1	1
Net periodic benefit cost	$ 2	$ 2	$ 2

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Regulatory Assets [Line Items]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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

	Weighted Average Remaining Life (1)	As of December 31,
		2014					2013
		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management (2)	3 years	$	100		$	121	$	36		$	140
Pension and other postretirement plans (2)	(3)	—			247		—			194
Deferred income taxes (2)	(4)	—			86		—			76
Debt issuance costs (2)	8 years	—			15		—			17
Deferred capital projects	1 year	19			—		16			18
Other (5)	Various	14			25		14			19
Total regulatory assets		$	133		$	494	$	66		$	464
Regulatory liabilities:
Asset retirement removal costs (6)	(4)	$	—		$	804	$	—		$	747
Trojan decommissioning activities	2 years	23			34		—			49
Asset retirement obligations (6)	(4)	—			39		—			39
Other	Various	37			29		1			30
Total regulatory liabilities		$	60	(7)	$	906	$	1	(7)	$	865

(1) As of December 31, 2014.

(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 $33 million and $16 million as of December 31, 2014 and 2013, respectively.

(6) Included in rate base for ratemaking purposes.

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

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Balance Sheet Components Allowance for Uncollectible accounts activity (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance as of beginning of year	$ 6	$ 5	$ 6
Increase in provision	6	6	6
Amounts written off, less recoveries	(6)	(5)	(7)
Balance as of end of year	$ 6	$ 6	$ 5

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Damages sought in USDOE claim					$ 112
Asset Retirement Obligation Rate Recovery related to Trojan Plant					4
Loss Contingency, Damages Awarded, Value			70		9
Proceeds from Legal Settlements				50	6	44	0
Asset Retirement Obligation, Liabilities Incurred	$ 7	$ 8			$ 15	$ 4	$ 0

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Consolidated Statements of Income (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues, net	$ 1,900	$ 1,810	$ 1,805
Operating expenses:
Purchased power and fuel	713	757	726
Generation, transmission and distribution	257	225	211
Cascade Crossing transmission project	0	52	0
Administrative and other	227	219	216
Depreciation and amortization	301	248	248
Taxes other than income taxes	109	103	102
Total operating expenses	1,607	1,604	1,503
Income from operations	293	206	302
Interest expense, net	96	101	108
Other income:
Allowance for equity funds used during construction	37	13	6
Miscellaneous income, net	1	7	4
Other income, net	38	20	10
Income before income taxes	235	125	204
Income tax expense	61	21	64
Net income	174	104	140
Less: net loss attributable to noncontrolling interest	(1)	(1)	(1)
Net income attributable to Portland General Electric Company	$ 175	$ 105	$ 141
Weighted-average shares outstanding (in thousands):
Basic	78,180	76,821	75,498
Diluted	80,494	77,388	75,647
Earnings per share:
Basic	$ 2.24	$ 1.36	$ 1.87
Diluted	$ 2.18	$ 1.35	$ 1.87

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Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

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

	Years Ended December 31,
	2014		2013		2012
Current:
Federal	$	20	$	10	$	16
State and local	2		—		1
	22		10		17
Deferred:
Federal	26		4		30
State and local	13		7		17
	39		11		47
Income tax expense	$	61	$	21	$	64

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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

	Years Ended December 31,
	2014		2013		2012
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(11.4	)	(21.8	)	(11.8	)
State and local taxes, net of federal tax benefit	3.9		3.4		3.5
Flow through depreciation and cost basis differences	(2.3	)	2.8		2.4
Adjustment to deferred taxes for change in blended composite state tax rate	—		—		2.6
Other	0.8		(2.6	)	(0.6	)
Effective tax rate	26.0	%	16.8	%	31.1	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

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

	As of December 31,
	2014			2013
Deferred income tax assets:
Employee benefits	$	161		$	122
Price risk management	88			71
Regulatory liabilities	48			33
Tax credits	13			51
Other	1			—
Total deferred income tax assets	311			277
Deferred income tax liabilities:
Depreciation and amortization	693			646
Regulatory assets	210			175
Total deferred income tax liabilities	903			821
Deferred income tax liability, net	$	(592	)	$	(544	)
Classification of net deferred income taxes:
Current deferred income tax asset *	$	33		$	42
Noncurrent deferred income tax liability	(625		)	(586		)
	$	(592	)	$	(544	)

* Included in Other current assets in the consolidated balance sheets.

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Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 MW	Dec. 31, 2013	Dec. 31, 2012
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 1,102
PGE Share of Output	8.60%
PGE Share of Capacity	163
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2052
commitment costs	14	14	14
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	215
PGE Share of Output	19.40%
PGE Share of Capacity	150
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2018
commitment costs	10	10	10
Portland Hydro [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	4
PGE Share of Output	100.00%
PGE Share of Capacity	36
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2017
commitment costs	$ 4	$ 4	$ 4

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Consolidated Balance Sheets Consolidated Balance Sheet Parentheticals (USD $)	Dec. 31, 2014	Dec. 31, 2013
Preferred Stock, No Par Value	$ 0	$ 0
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	160,000,000	160,000,000
Common Stock, Shares, Issued	78,228,339	78,085,559
Common Stock, Shares, Outstanding	78,228,339	78,085,559

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Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Shares Outstanding, Basic	78,180	76,821	75,498
Weighted Average Number Diluted Shares Outstanding Adjustment	2,314	567	149
Weighted Average Number of Shares Outstanding, Diluted	80,494	77,388	75,647

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Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net realized and unrealized losses	$ 15	$ 134
Settlements	(4)	(1)
Net transfers out of Level 3 to Level 2	(50)	(10)
Net liabilities from price risk management activities as of end of year	100	139	16
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	12	133
Net realized losses	$ 3	$ 1

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Jointly-owned Plant Schedule of Jointly-owned plant (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2013
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman	90.00%	80.00%	65.00%
Jointly Owned Plant, Boardman Plant In Service Year	1980
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service	$ 510
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation	350
Jointly Owned Utility Plant Ownership Amount of Construction Work In Progress Boardman	0
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%
Jointly Owned Plant, Colstrip Plant In Service Year	1986
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service	520
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation	334
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip	2
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte	66.67%
Jointly Owned Plant, Pelton Plant in Service Year	1958
Jointly Owned Plant, Round Butte in Service Year	1964
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service	237
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation	55
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte	8
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1,267
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	739
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 10

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Contingencies (Policies)

12 Months Ended

Dec. 31, 2014

Contingencies [Abstract]

Commitments and Contingencies, Policy [Policy Text Block]

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

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

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

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

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

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Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Commodity contracts:
Other Commitment, Due in Next Twelve Months	$ 14
Other Commitment, Due in Second Year	11
Other Commitment, Due in Third Year	11
Other Commitment, Due in Fourth Year	7
Total	43
Electricity [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	50
Other Commitment, Due in Second Year	19
Other Commitment, Due in Third Year	6
Other Commitment, Due in Fourth Year	5
Other Commitment, Due in Fifth Year	5
Other Commitment, Due after Fifth Year	22
Total	107
Natural Gas [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	49
Other Commitment, Due in Second Year	44
Other Commitment, Due in Third Year	18
Other Commitment, Due in Fourth Year	3
Other Commitment, Due in Fifth Year	0
Other Commitment, Due after Fifth Year	0
Total	114
Unrealized Gain Loss On Derivatives [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	99
Other Commitment, Due in Second Year	63
Other Commitment, Due in Third Year	24
Other Commitment, Due in Fourth Year	8
Other Commitment, Due in Fifth Year	5
Other Commitment, Due after Fifth Year	22
Total	$ 221

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Stock-based Compensation Expense

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

STOCK-BASED COMPENSATION EXPENSE

Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs) to non-employee directors, officers and certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table:

	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2011	491,404		$	18.54
Granted	186,495		24.72
Forfeited	(22,947	)	18.95
Vested	(214,390	)	15.67
Outstanding as of December 31, 2012	440,562		22.54
Granted	183,071		29.25
Forfeited	(7,007	)	27.15
Vested	(185,536	)	20.20
Outstanding as of December 31, 2013	431,090		26.31
Granted	203,410		31.49
Forfeited	(12,278	)	29.90
Vested	(158,329	)	24.95
Outstanding as of December 31, 2014	463,893		28.96

A total of 4,687,500 shares of common stock were registered for future issuance under the Plan, of which 3,554,884 shares remain available for future issuance as of December 31, 2014.

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

Time-based RSUs vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was less than $1 million for the years ended December 31, 2014, 2013, and 2012.

Performance-based RSUs vest if performance goals are met at the end of a three-year performance period. For grants prior to March 5, 2013, such goals include return on equity relative to allowed return on equity, and regulated asset base growth. Grants on and after March 5, 2013 are based on three equally-weighted metrics: return on equity relative to allowed return on equity; regulated asset growth; and a relative total shareholder return (TSR) of PGE’s common stock as compared to the Edison Electric Institute Regulated Index (EEI Index) during the performance period. Vesting of performance-based RSUs is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

For the return on equity and regulated asset base growth portions of the performance-based RSUs, fair value is measured based on the closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions:

	2014				2013
Risk-free interest rate			0.6	%			0.3	%
Expected dividend yield			—	%			—	%
Expected term (in years)			3.0				3.0
Volatility	12.4%	-	23.0%		12.1%	-	25.1%

The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 134.2%, 117.5%, and 112.0% of awarded performance-based RSUs for 2014, 2013, and 2012, respectively, with an estimated 5% forfeiture rate.

The total value of performance-based RSUs vested was $3 million for the years ended December 31, 2014, 2013, and 2012.

Stock-based compensation was $6 million for the year ended December 31, 2014, and $4 million in 2013 and in 2012, which is included in Administrative and other expense in the consolidated statements of income. Such amounts differ from those reported in the consolidated statements of equity for Stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. The net impact to equity from the income tax payments, partially offset by the issuance of DERs, resulted in a charge to equity of $1 million in 2014, $2 million in 2013, and $1 million in 2012, which is not included in Administrative and other expenses in the consolidated statements of income.

As of December 31, 2014, unrecognized stock-based compensation expense was $6 million, of which approximately $4 million and $2 million is expected to be expensed in 2015 and 2016, respectively. No stock-based compensation costs have been capitalized and the Plan had no material impact on cash flows for the years ended December 31, 2014, 2013, or 2012.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Estimated average service lives [Table Text Block]

Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):

Generation, excluding thermal:
Hydro	87
Wind	27
Transmission	53
Distribution	40
General	13

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Variable interest Entities [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net	$ 4	$ 5
Variable Interest Entity, Consolidated, Carrying Amount, Cash and Cash Equivalents		$ 1
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	1.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	99.00%
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%
Estimated Remaining Useful Life of Facility Acquired	75.00%

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Commitments and Guarantees

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Guarantees [Text Block]

COMMITMENTS AND GUARANTEES

Commitments

As of December 31, 2014, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):

	Payments Due
	2015		2016		2017		2018		2019		Thereafter		Total
Capital and other purchase commitments	$	242	$	21	$	2	$	2	$	2	$	74	$	343
Purchased power and fuel:
Electricity purchases	179		167		140		143		143		833		1,605
Capacity contracts	27		26		6		6		5		20		90
Public utility districts	8		7		5		4		2		23		49
Natural gas	56		37		40		40		36		244		453
Coal and transportation	23		14		11		5		5		—		58
Operating leases	10		11		12		11		8		192		244
Total	$	545	$	283	$	216	$	211	$	201	$	1,386	$	2,842

Capital and other purchase commitments—Certain commitments have been made for capital and other purchases for 2015 and beyond. Such commitments include those related to hydro licenses, upgrades to generating, distribution and transmission facilities, information systems, and system maintenance work. A large component of these commitments for 2015 are costs associated with the construction of Carty. Termination of these agreements could result in cancellation charges.

Electricity purchases and Capacity contracts—PGE has power purchase contracts with counterparties, which expire at varying dates through 2049, and power capacity contracts through 2019. In addition to the power purchase contracts with counterparties presented in the table, PGE has power sale contracts with counterparties of approximately $43 million that settle as follows: $14 million in 2015; $11 million in 2016 and 2017; and $7 million in 2018.

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

	Revenue Bonds as of December 31, 2014		PGE’s Share as of December 31, 2014			Contract Expiration	PGE Cost, including Debt Service
			Output		Capacity		2014		2013		2012
					(in MW)
Priest Rapids and Wanapum	$	1,102	8.6	%	163	2052	$	14	$	14	$	14
Wells	215		19.4		150	2018	10		10		10
Portland Hydro	4		100.0		36	2017	4		4		4

The agreements for Priest Rapids and Wanapum and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.

Natural gas—PGE has agreements for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. The Company also has a natural gas storage agreement for the purpose of fueling the Company’s natural gas-fired generating plants (Port Westward Unit 1 (PW1), PW2 and Beaver).

Coal and transportation—PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman, which expire at various dates through 2020.

Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities. The majority of the future minimum operating lease payments presented in the table consist of i) the corporate headquarters lease, which expires in 2018, but includes renewal period options through 2043, and ii) the Port of St. Helens land lease, where PW1, PW2 and Beaver are located, which expires in 2096. Rent expense was $11 million in 2014, $9 million in 2013, and $10 million in 2012.

The future minimum operating lease payments presented is net of sublease income of: $3 million in 2015; $2 million in 2016; and $1 million in 2017, 2018 and 2019. Sublease income was $3 million in 2014, 2013 and 2012.

Guarantees

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 2014, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.

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Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Remaining Recovery Period of Regulatory Assets, Price Risk Management	3 years
Remaining Recovery Period of Regulatory Asset, Debt Reacquisition Costs	8 years
Price risk management	$ 6	$ 13
Deferred income taxes	48	33
remaining recovery period of regulatory assets, deferred capital projects	1 year
Remaining refund period of regulatory liability, Trojan decommissioning activities	2 years
Current Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	0	0
Proceeds from Legal Settlements	23	0
Asset retirement obligations	0	0
Other	37	1
Total regulatory liabilities	60	1
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	804	747
Proceeds from Legal Settlements	34	49
Asset retirement obligations	39	39
Other	29	30
Total regulatory liabilities	906	865
Regulatory Assets, Current [Member]
Regulatory Assets [Line Items]
Price risk management	100	36
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Debt reacquisition costs	0	0
Deferred capital project	19	16
Other	14	14
Total regulatory assets	133	66
Noncurrent Regulatory Assets [Member]
Regulatory Assets [Line Items]
Price risk management	121	140
Pension and other postretirement plans	247	194
Deferred income taxes	86	76
Debt reacquisition costs	15	17
Deferred capital project	0	18
Other	25	19
Total regulatory assets	$ 494	$ 464

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Consolidated Statements of Equity (USD $) In Millions, except Share data, unless otherwise specified	Total USD ($)	Common Stock Shares	Common Stock Amount USD ($)	Accumulated Other Comprehensive Loss USD ($)	Retained Earnings USD ($)	Noncontrolling Interests' Equity USD ($)
Balance at Dec. 31, 2011			$ 836	$ (6)	$ 833	$ 3
Balance, shares at Dec. 31, 2011		75,362,956
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		193,316
Proceeds from issuance of shares pursuant to equity-based plans			1
Stock-based compensation			4	0	0	0
Dividends declared			0	0	(81)	0
Net income (loss)	140		0	0	141	(1)
Balance at Dec. 31, 2012			841	(6)	893	2
Balance, shares at Dec. 31, 2012		75,556,272
Issuances of common stock, net of issuance costs of $3		2,365,000
Issuances of common stock, net of issuance costs of $3			67
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		164,287
Proceeds from issuance of shares pursuant to equity-based plans			1
Stock-based compensation			2	0	0	0
Dividends declared			0	0	(85)	0
Net income (loss)	104		0	0	105	(1)
Other comprehensive income (loss)			0	1	0	0
Balance at Dec. 31, 2013	1,820		911	(5)	913	1
Balance, shares at Dec. 31, 2013		78,085,559
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		142,780
Proceeds from issuance of shares pursuant to equity-based plans			1
Stock-based compensation			6	0	0	0
Dividends declared			0	0	(88)	0
Net income (loss)	174		0	0	175	(1)
Other comprehensive income (loss)			0	(2)	0	0
Balance at Dec. 31, 2014	$ 1,911		$ 918	$ (7)	$ 1,000	$ 0
Balance, shares at Dec. 31, 2014		78,228,339

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$ 174	$ 104	$ 140
Other comprehensive income (loss) - Change in compensation retirement benefits liability and amortization, net of taxes of $2 in 2014 and $(1) in 2013	(2)	1	0
Comprehensive income	172	105	140
Less: comprehensive loss attributable to the noncontrolling interests	1	1	1
Comprehensive income attributable to Portland General Electric Company	$ 173	$ 106	$ 141

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Revolving Credit Facilities

12 Months Ended

Dec. 31, 2014

Line of Credit Facility [Abstract]

Revolving Credit Facilities

CREDIT FACILITIES

PGE has credit facilities with an aggregate capacity of $700 million as follows:

• A $400 million revolving credit facility, which is scheduled to terminate in November 2018; and

• A $300 million revolving credit facility, which is scheduled to terminate in December 2017.

Pursuant to the terms of the agreements, both revolving credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both revolving credit facilities contain two, one-year extensions subject to approval by the banks, require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2014, PGE was in compliance with this covenant with a 56.7% debt to total capital ratio.

PGE classifies any borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt in the consolidated balance sheets. As of December 31, 2014, PGE had no borrowings or commercial paper outstanding, $20 million of letters of credit issued, and an aggregate available capacity of $680 million under the revolving credit facilities.

In addition, PGE has two one-year $30 million letter of credit facilities, under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit are subject to the approval of the issuing institution. As of December 31, 2014, $56 million of letters of credit had been issued under these facilities.

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

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt up to $900 million through February 6, 2016. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

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

	Years Ended December 31,
	2014			2013			2012
Average daily amount of short-term debt outstanding	$	—		$	9		$	4
Weighted daily average interest rate *	—		%	0.4		%	0.4		%
Maximum amount outstanding during the year	$	—		$	54		$	44

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

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Stock-based Compensation Expense (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation	$ 6	$ 4	$ 4
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	4,687,500
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	3,554,884
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	1	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	3	0	0
Adjustments Related to Tax Withholding for Share-based Compensation	1	2	1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	6
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting	134.20%	117.50%	112.00%
Stock-based Compensation, Forfeiture Rate	5.00%
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	0	0	0
stock based compensation impact on cash flows	0	0	0
Performance based stock award percentage - minimum	0.00%
Performance based stock award percentage - maximum	150.00%
Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation				$ 2	$ 4

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Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Outstanding, Units	431,090	440,562	491,404
Outstanding, Weighted Average Grant Date Fair Value	$ 26.31	$ 22.54	$ 18.54
Granted, Units	203,410	183,071	186,495
Granted, Weighted Average Grant Date Fair Value	$ 31.49	$ 29.25	$ 24.72
Forfeited, Units	(12,278)	(7,007)	(22,947)
Forfeited, Weighted Average Grant Date Fair Value	$ 29.90	$ 27.15	$ 18.95
Vested, Units	(158,329)	(185,536)	(214,390)
Vested, Weighted Average Grant Date Fair Value	$ 24.95	$ 20.20	$ 15.67
Outstanding, Units	463,893	431,090	440,562
Outstanding, Weighted Average Grant Date Fair Value	$ 28.96	$ 26.31	$ 22.54

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DEI Document (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 10, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		78,228,827
Entity Public Float			$ 2,699,904,749
Trading Symbol	POR

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Long-term Debt

12 Months Ended

Dec. 31, 2014

Long-term Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT

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

	As of December 31,
	2014			2013
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048	$	2,075		$	1,795
Unsecured term bank loans, rates range from 0.86% to 0.93%, due October 2015	305			—
Pollution Control Revenue Bonds, 5% rate, due 2033	142			148
Pollution Control Revenue Bonds owned by PGE	(21		)	(27		)
Total long-term debt	2,501			1,916
Less: current portion of long-term debt	(375		)	—
Long-term debt, net of current portion	$	2,126		$	1,916

First Mortgage Bonds—During 2014, PGE issued a total of $280 million of FMBs, consisting of the following:

• In November, issued $80 million of 3.51% Series FMBs due 2024;

• In October, issued $100 million of 4.44% Series FMBs due 2046; and

• In August, issued $100 million of 4.39% Series FMBs due 2045.

The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs.

In January 2015, the Company issued $75 million of 3.55% Series FMBs due 2030.

Unsecured term bank loans—During 2014, PGE obtained four term loans pursuant to a credit agreement in an aggregate principal amount of $305 million. The term loan interest rates are set at the beginning of the interest period for periods ranging from one- to six-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 70 basis points, with no other fees. The credit agreement expires October 30, 2015, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults and other customary defaults. Interest is payable monthly on the unsecured term bank loans.

Pollution Control Revenue Bonds—In January 2014, PGE retired $6 million of Pollution Control Revenue Bonds (PCBs). The Company has the option to remarket through 2033 the $21 million of PCBs held by PGE as of December 31, 2014. At the time of any remarketing, the Company can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing. The PCBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on PCBs.

As of December 31, 2014, the future minimum principal payments on long-term debt are as follows (in millions):

Years ending December 31:
2015	$	375
2016	67
2017	58
2018	75
2019	300
Thereafter	1,626
	$	2,501

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Employee Benefits Schedule of Fair Value, Assets (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Pension Plan assets:
Money market funds	$ 6
Equity securities:
Domestic	188	185
International equity securities - defined benefit pension plan assets	171	185
Debt securities:
Domestic government and corporate credit	197	181
Corporate credit		14
Private equity funds	29	31
Defined Benefit Plan, Fair Value of Plan Assets	591	596
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	6	10
Domestic equity securities - Other postretirement benefit plan assets at fair value	11	10
International equity securities - other post retirement assets at fair value	10	9
Debt securities—Domestic government	5	3
Other post retirement benefit plan assets total	32	32
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Pension Plan assets:
Money market funds	0
Equity securities:
Domestic	42	166
International equity securities - defined benefit pension plan assets	0	185
Debt securities:
Domestic government and corporate credit	0	0
Corporate credit		14
Private equity funds	0	0
Defined Benefit Plan, Fair Value of Plan Assets	42	365
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	0	0
Domestic equity securities - Other postretirement benefit plan assets at fair value	10	8
International equity securities - other post retirement assets at fair value	10	9
Debt securities—Domestic government	5	3
Other post retirement benefit plan assets total	25	20
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Pension Plan assets:
Money market funds	6
Equity securities:
Domestic	146	19
International equity securities - defined benefit pension plan assets	171	0
Debt securities:
Domestic government and corporate credit	197	181
Corporate credit		0
Private equity funds	0	0
Defined Benefit Plan, Fair Value of Plan Assets	520	200
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	6	10
Domestic equity securities - Other postretirement benefit plan assets at fair value	1	2
International equity securities - other post retirement assets at fair value	0	0
Debt securities—Domestic government	0	0
Other post retirement benefit plan assets total	7	12
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Pension Plan assets:
Money market funds	0
Equity securities:
Domestic	0	0
International equity securities - defined benefit pension plan assets	0	0
Debt securities:
Domestic government and corporate credit	0	0
Corporate credit		0
Private equity funds	29	31
Defined Benefit Plan, Fair Value of Plan Assets	29	31	32
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	0	0
Domestic equity securities - Other postretirement benefit plan assets at fair value	0	0
International equity securities - other post retirement assets at fair value	0	0
Debt securities—Domestic government	0	0
Other post retirement benefit plan assets total	$ 0	$ 0

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Stock Purchase Plan Stock Purchase Plan (Details) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2014	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
stock offering			11,100,000
Proceeds from Issuance of Common Stock		$ 20,000,000	$ 47,000,000	$ 0	$ 67,000,000	$ 0
Share Price		$ 29.50
Common Stock, Discount on Shares		0.96
Equity Forward Sale Agreement, Settlement Threshold	10,400,000
equity forward sale agreement future settlement amount	275,000,000
Option Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value	119,000,000			119,000,000
Net share settlement	3,135,000			3,135,000
employee stock purchase plan shares authorized	625,000			625,000
Employee Stock Purchase Plan, Base Pay Threshold				10.00%
Employee Stock Purchase Plan, Purchased Stock Value Limitation				$ 25,000
Employee Stock Purchase Plan, Share Purchase Limitation				1,500
Employee Stock Purchase Plan, Purchase Price				95.00%
Employee Stock Purchase Plan, Number of Available Shares	427,021			427,021
Dividend Reinvestment and Direct Stock Purchase Plan Shares				2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares	2,481,110			2,481,110
Common Stock [Member]
Stock Issued During Period, Shares, New Issues		700,000	1,665,000		2,365,000

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Consolidated Statements of Comprehensive Income Consolidated Statement of Comprehensive Income Parentheticals (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Net Taxes on change in compensation retirement benefits liability and amortization	$ 2	$ (1)

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Balance Sheet Components

12 Months Ended

Dec. 31, 2014

Balance Sheet Components [Abstract]

Balance Sheet Components

BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of December 31, 2014 and 2013. The following is the activity in the allowance for uncollectible accounts (in millions):

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	6		$	5		$	6
Increase in provision	6			6			6
Amounts written off, less recoveries	(6		)	(5		)	(7		)
Balance as of end of year	$	6		$	6		$	5

Trust Accounts

PGE maintains two trust accounts as follows:

Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust includes amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein. In 2014 and 2013, the Company received $6 million and $44 million, respectively, from the settlement of a legal matter concerning costs associated with the operation of the ISFSI. Those funds were deposited into the Nuclear decommissioning trust. For additional information concerning the legal matter, see Note 7, Asset Retirement Obligations.

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

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

	Nuclear     Decommissioning Trust				Non-Qualified Benefit     Plan Trust
	2014		2013		2014		2013
Cash equivalents	$	65	$	59	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		6		8
Debt securities	25		23		—		1
Insurance contracts, at cash surrender value	—		—		26		26
	$	90	$	82	$	32	$	35

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

Other Current Assets and Accrued Expenses and Other Current Liabilities

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

	As of December 31,
	2014		2013
Other current assets:
Prepaid expenses	$	39	$	38
Current deferred income tax asset	33		42
Accrued sales tax refund related to Tucannon River Wind Farm	23		—
Margin deposits	11		9
Assets from price risk management activities	6		13
Other	3		1
	$	115	$	103
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	60	$	1
Accrued employee compensation and benefits	51		46
Accrued interest payable	26		23
Dividends payable	23		22
Accrued taxes payable	22		21
Other	54		58
	$	236	$	171

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $120 million and $104 million as of December 31, 2014 and 2013, respectively.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice.

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

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2014, 2013 and 2012.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument.

Electricity sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets and were $11 million and $9 million as of December 31, 2014 and 2013, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $30 million and $29 million as of December 31, 2014 and 2013, respectively.

Inventories

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

Electric Utility Plant

Capitalization Policy

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

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted.

During the year ended December 31, 2013, PGE charged $52 million of costs previously included in CWIP related to the Cascade Crossing Transmission Project (Cascade Crossing), which was originally proposed as a 215-mile, 500 kV transmission project between Boardman, Oregon and Salem, Oregon. Based on an updated forecast of demand and future transmission capacity in the region, PGE determined in the second quarter of 2013 that the original projections of transmission capacity limitations contemplated in the Company’s 2009 Integrated Resource Plan, as acknowledged by the OPUC, were not likely to fully materialize. As a result, PGE and Bonneville Power Administration (BPA) worked toward refining the scope of the project and executed a non-binding memorandum of understanding (MOU) in May 2013. In connection with the MOU, the parties explored a new option under which BPA could provide PGE with ownership of approximately 1,500 MW of transmission capacity rights. As a result of the changed conditions reflected in the MOU, PGE also suspended permitting and development of Cascade Crossing and charged the capitalized costs related to Cascade Crossing to expense in the second quarter of 2013. In October 2013, the parties determined that they would not be able to reach an agreement on the financial terms for the proposed ownership of transmission capacity rights and, therefore, agreed to discontinue discussions on this option. The Company has determined that, under current conditions, the best option for meeting its transmission needs is to continue to acquire transmission service offered under BPA’s Open Access Transmission Tariff. PGE has determined that it will not seek recovery of these costs.

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.4% in 2014, and 7.5% in 2013 and in 2012. AFDC from borrowed funds was $22 million in 2014, $7 million in 2013, and $4 million in 2012 and is reflected as a reduction to Interest expense. AFDC from equity funds was $37 million in 2014, $13 million in 2013, and $6 million in 2012 and is included in Other income, net.

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

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2014, 3.7% in 2013, and 3.8% in 2012. Estimated asset retirement removal costs included in depreciation expense were $57 million in 2014, and $55 million in 2013 and in 2012.

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recent depreciation study was completed for 2013, with an order received from the OPUC in September 2014 authorizing new depreciation rates effective January 1, 2015.

Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):

Generation, excluding thermal:
Hydro	87
Wind	27
Transmission	53
Distribution	40
General	13

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

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $191 million and $170 million as of December 31, 2014 and 2013, respectively, with amortization expense of $25 million in 2014, and $22 million in 2013 and in 2012. Future estimated amortization expense as of December 31, 2014 is as follows: $35 million in 2015; $33 million in 2016; $29 million in 2017; $28 million in 2018; and $22 million in 2019.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.

Regulatory Accounting

Regulatory Assets and Liabilities

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

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

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

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while 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. PGE’s authorized ROE was 9.75% for 2014, and 10% for 2013 and for 2012.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review.

For 2014, actual NVPC was below baseline NVPC by $7 million, which is within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2014. A final determination regarding the 2014 PCAM results will be made by the OPUC through a public filing and review in 2015.

For 2013, actual NVPC was above baseline NVPC by $11 million, which is within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2013. A final determination regarding the 2013 PCAM results was made by the OPUC through a public filing and review in 2014, which confirmed no collection from customers pursuant to the PCAM for 2013.

For 2012, actual NVPC was below baseline NVPC by $17 million, and exceeded the lower deadband threshold of $15 million. However, based on results of the regulated earnings test, no estimated refund to customers was recorded as of December 31, 2012. A final determination regarding the 2012 PCAM results was made by the OPUC through a public filing and review in 2013, which confirmed no refund to customers pursuant to the PCAM for 2012.

Asset Retirement Obligations

Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheet. An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is classified as Depreciation and amortization expense in the Company’s consolidated statements of income.

The difference between the timing of the recognition of the AROs’ depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. PGE had a regulatory liability related to AROs in the amount of $39 million as of December 31, 2014 and 2013. See Note 6, Regulatory Assets and Liabilities.

Contingencies

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

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

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

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

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $42 million in 2014, $41 million in 2013, and $42 million in 2012.

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

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

Stock-Based Compensation

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

Income Taxes

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

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $86 million and $76 million as of December 31, 2014 and 2013, respectively, and will be included in prices when the temporary differences reverse.

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

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

Recent Accounting Pronouncement

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations in the contract; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which is January 1, 2017 for the Company, with early adoption prohibited. The impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows of the adoption of ASU 2014-09 is not known at this time.

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Earnings Per Share

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) unvested time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the EFSA. See Note 12, Equity-based Plans, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria has been met.

Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computation. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Years Ended December 31,
	2014	2013	2012
Weighted average common shares outstanding—basic	78,180	76,821	75,498
Dilutive effect of potential common shares	2,314	567	149
Weighted average common shares outstanding—diluted	80,494	77,388	75,647

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Employee Benefits

12 Months Ended

Dec. 31, 2014

Employee Benefits [Abstract]

Employee Benefits

EMPLOYEE BENEFITS

Pension and Other Postretirement Plans

Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan. The plan has been closed to most new employees since January 31, 2009 and to all new employees since January 1, 2012. No changes were made to the benefits provided to existing participants when the plan was closed to new employees.

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

PGE made no contributions to the pension plan in 2014, 2013, and 2012. No contributions to the pension plan are expected in 2015.

In 2014, the Company offered certain eligible participants of the pension plan the option to select a lump sum distribution. As a result of this offering, PGE made lump sum distributions totaling $16 million on July 1, 2014.

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

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

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

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

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

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

	2014						2013
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	15	$	17	$	32	$	16	$	19	$	35
Non-qualified benefit plan liabilities *	25		80		105		22		79		101

* For the NQBP, excludes the current portion of $2 million in 2014 and in 2013, which is classified in Other current liabilities in the consolidated balance sheets.

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

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

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

	As of December 31,
	2014				2013
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	66	%	67	%	67	%	67	%
Debt securities	34		33		33		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	66	%	67	%	58	%	58	%
Debt securities	34		33		42		42
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	19	%	13	%	24	%	16	%
Debt securities	1		7		1		9
Insurance contracts	80		80		75		75
Total	100	%	100	%	100	%	100	%

* The target for the Defined Benefit Pension 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.

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

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2014:
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	$	42	$	146	$	—	$	188
International	—		171		—		171
Debt securities:
Domestic government and corporate credit	—		197		—		197
Private equity funds	—		—		29		29
	$	42	$	520	$	29	$	591
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	10		1		—		11
International	10		—		—		10
Debt securities—Domestic government	5		—		—		5
	$	25	$	7	$	—	$	32
As of December 31, 2013:
Defined Benefit Pension Plan assets:
Equity securities:
Domestic	$	166	$	19	$	—	$	185
International	185		—		—		185
Debt securities:
Domestic government and corporate credit	—		181		—		181
Corporate credit	14		—		—		14
Private equity funds	—		—		31		31
	$	365	$	200	$	31	$	596
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	10	$	—	$	10
Equity securities:
Domestic	8		2		—		10
International	9		—		—		9
Debt securities—Domestic government	3		—		—		3
	$	20	$	12	$	—	$	32

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

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

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

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

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

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

Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy, which consists of Private equity funds, were as follows (in millions):

	Years Ended December 31,
	2014			2013
Level 3 balance as of beginning of year	$	31		$	32
Unrealized gains, net	2			4
Realized gains (losses), net	3			(2		)
Sales, net	(7		)	(3		)
Level 3 balance as of end of year	$	29		$	31

The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2014 and 2013. Information related to the Other NQBP is not included in the following tables (dollars in millions):

	Defined Benefit Pension Plan						Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014			2013			2014			2013			2014			2013
Benefit obligation:
As of January 1	$	705		$	728		$	77		$	84		$	24		$	27
Service cost	15			17			2			2			—			—
Interest cost	34			30			4			3			1			1
Participants’ contributions	—			—			1			2			—			—
Actuarial (gain) loss	72			(38		)	4			(9		)	5			(2		)
Contractual termination benefits	—			—			1			1			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	777		$	705		$	83		$	77		$	27		$	24
Fair value of plan assets:
As of January 1	$	596		$	537		$	32		$	28		$	16		$	15
Actual return on plan assets	44			91			1			5			1			3
Company contributions	—			—			4			3			1			—
Participants’ contributions	—			—			1			2			—			—
Benefit payments	(48		)	(32		)	(6		)	(6		)	(3		)	(2		)
Administrative expenses	(1		)	—			—			—			—			—
As of December 31	$	591		$	596		$	32		$	32		$	15		$	16
Unfunded position as of December 31	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Accumulated benefit plan obligation as of December 31	$	691		$	631		N/A			N/A			$	27		$	24
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	15		$	16
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(186		)	(109		)	(51		)	(45		)	(25		)	(22		)
Net liability	$	(186	)	$	(109	)	$	(51	)	$	(45	)	$	(12	)	$	(8	)
Amounts included in comprehensive income:
Net actuarial (gain) loss	$	67		$	(89	)	$	5		$	(11	)	$	5		$	(1	)
Amortization of net actuarial loss	(17		)	(24		)	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			(1		)	(1		)	—			—
	$	50		$	(113	)	$	3		$	(13	)	$	4		$	(2	)
Amounts included in AOCL*:
Net actuarial loss	$	236		$	186		$	10		$	6		$	13		$	9
Prior service cost	—			—			1			2			—			—
	$	236		$	186		$	11		$	8		$	13		$	9

	Defined Benefit Pension Plan				Other Postretirement   Benefits						Non-Qualified Benefit Plans
	2014		2013		2014			2013			2014		2013
Assumptions used:
Discount rate for benefit obligation	4.02	%	4.84	%	3.07	%	-	3.46	%	-	4.02	%	4.84	%
					4.10	%		4.96	%
Discount rate for benefit cost	4.84	%	4.24	%	3.46	%	-	2.77	%	-	4.84	%	4.24	%
					4.96	%		4.13	%
Weighted average rate of compensation increase for benefit obligation	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Weighted average rate of compensation increase for benefit cost	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Long-term rate of return on plan assets for benefit obligation	7.50	%	7.50	%	6.37	%		6.46	%		N/A		N/A
Long-term rate of return on plan assets for benefit cost	7.50	%	8.25	%	6.46	%		5.89	%		N/A		N/A

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

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

	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2014			2013			2012			2014			2013			2012			2014		2013		2012
Service cost	$	15		$	17		$	14		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	34			30			31			4			3			3			1		1		1
Expected return on plan assets	(39		)	(40		)	(41		)	(2		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	—			—			—			1			1			1			—		—		—
Amortization of net actuarial loss	17			24			17			1			1			1			1		1		1
Net periodic benefit cost	$	27		$	31		$	21		$	6		$	6		$	6		$	2	$	2	$	2

PGE estimates that $23 million will be amortized from AOCL into net periodic benefit cost in 2015, consisting of a net actuarial loss of $20 million for pension benefits, $1 million for non-qualified benefits and $1 million for other postretirement benefits, and prior service cost of $1 million for other postretirement benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset.

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

	Payments Due
	2015		2016		2017		2018		2019		2020 - 2024
Defined benefit pension plan	$	35	$	37	$	38	$	40	$	41	$	221
Other postretirement benefits	5		5		5		5		5		26
Non-qualified benefit plans	2		2		2		2		3		9
Total	$	42	$	44	$	45	$	47	$	49	$	256

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

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

• For 2014, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019;

• For 2013, 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; and

• 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.

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

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes 5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay.

For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $16 million in 2014, 2013 and 2012.

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Employee Benefits Schedule of Expected Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 42
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	45
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	47
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	49
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	256
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	35
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	37
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	38
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	40
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	41
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	221
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	5
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	26
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 9

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

REGULATORY ASSETS AND LIABILITIES

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

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

	Weighted Average Remaining Life (1)	As of December 31,
		2014					2013
		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management (2)	3 years	$	100		$	121	$	36		$	140
Pension and other postretirement plans (2)	(3)	—			247		—			194
Deferred income taxes (2)	(4)	—			86		—			76
Debt issuance costs (2)	8 years	—			15		—			17
Deferred capital projects	1 year	19			—		16			18
Other (5)	Various	14			25		14			19
Total regulatory assets		$	133		$	494	$	66		$	464
Regulatory liabilities:
Asset retirement removal costs (6)	(4)	$	—		$	804	$	—		$	747
Trojan decommissioning activities	2 years	23			34		—			49
Asset retirement obligations (6)	(4)	—			39		—			39
Other	Various	37			29		1			30
Total regulatory liabilities		$	60	(7)	$	906	$	1	(7)	$	865

(1) As of December 31, 2014.

(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 $33 million and $16 million as of December 31, 2014 and 2013, respectively.

(6) Included in rate base for ratemaking purposes.

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

As of December 31, 2014, PGE had regulatory assets of $63 million earning a return on investment at the following rates: i) $33 million earning a return by inclusion in rate base; ii) $19 million at PGE’s cost of debt of 5.54%; iii) $9 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 1.77%, depending on the year of approval; and iv) $2 million at PGE’s cost of capital of 7.65%.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management.

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

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

Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date.

Deferred capital projects represents costs related to four capital projects that were deferred for future accounting treatment pursuant to the Company’s 2011 GRC. The recovery of these project costs in customer prices began January 1, 2014.

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

Trojan decommissioning activities represents proceeds received for the settlement of a legal matter concerning the reimbursement from the United States Department of Energy of certain monitoring costs incurred related to spent nuclear fuel at Trojan. The proceeds will be returned to customers over a three-year period beginning January 1, 2015 and offset amounts previously collected from customers in relation to Trojan decommissioning activities. To conform with the 2014 presentation, PGE reclassified tax credits to be returned to customers related to the operation of the ISFSI in the amount of $8 million from Other to Trojan decommissioning activities in the noncurrent regulatory liabilities section as of December 31, 2013 in the preceding table.

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

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Fair Value of Financial Instruments (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Net realized losses	$ 3,000,000	$ 1,000,000
Long-term Debt, Fair Value	2,901,000,000	2,074,000,000
Long-term Debt	2,501,000,000	1,916,000,000
Defined Benefit Plan, Transfers Between Measurement Levels	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	2,596,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 305,000,000

XML

Fair Value of FInancial Instruments

12 Months Ended

Dec. 31, 2014

Fair Value of Financial Instruments Note [Abstract]

Fair Value of FInancial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2014 and 2013, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

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

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

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

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

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the years ended December 31, 2014 and 2013, except those transfers from Level 3 to Level 2 presented in this note.

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

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	65	$	—	$	65
Debt securities:
Domestic government	7		7		—		14
Corporate credit	—		11		—		11
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		1		—		5
International	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		4		1		5
Natural gas	—		2		—		2
	$	12	$	90	$	1	$	103
Liabilities - Liabilities from price risk management activities(1) (3):
Electricity	$	—	$	32	$	80	$	112
Natural gas	—		95		21		116
	$	—	$	127	$	101	$	228

(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 $26 million, which are recorded at cash surrender value.

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

	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	6		8		—		14
Corporate credit	—		9		—		9
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		3		—		7
International	1		—		—		1
Debt securities - domestic government	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		9		1		10
Natural gas	—		4		—		4
	$	12	$	92	$	1	$	105
Liabilities - Liabilities from price risk management activities (1) (3):
Electricity	$	—	$	10	$	117	$	127
Natural gas	—		40		23		63
	$	—	$	50	$	140	$	190

(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 $26 million, which are recorded at cash surrender value.

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

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

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

Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.

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

Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace.

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

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

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures and swaps.

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:

						Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)
As of December 31, 2014:
Electricity physical forward	$	—	$	77	Discounted cash flow	Electricity forward price (per MWh)	$	11.97	$	122.72	$	37.43
Natural gas financial swaps	—		21		Discounted cash flow	Natural gas forward price (per Dth)	2.88		4.86		3.41
Electricity financial futures	1		3		Discounted cash flow	Electricity forward price (per MWh)	11.97		39.26		27.88
	$	1	$	101
As of December 31, 2013:
Electricity physical forward	$	—	$	103	Discounted cash flow	Electricity forward price (per MWh)	$	9.63	$	77.95	$	40.18
Natural gas financial swaps	—		23		Discounted cash flow	Natural gas forward price (per Dth)	3.16		4.49		3.71
Electricity financial futures	1		14		Discounted cash flow	Electricity forward price (per MWh)	9.63		46.07		33.01
	$	1	$	140

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, the Company uses internally-developed price curves that employ the mid-point of the market’s bid-ask spread derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These internally-developed price curves are validated against nonbinding broker quotes, market data from a regulated exchange and benchmark price assessments from a pricing vendor. For certain longer term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such circumstances, the Company uses internally-developed price curves, which utilize observable data and regression techniques to derive future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):

	Years Ended December 31,
	2014			2013
Net liabilities from price risk management activities as of beginning of year	$	139		$	16
Net realized and unrealized losses *	15			134
Settlements	(4		)	(1		)
Net transfers out of Level 3 to Level 2	(50		)	(10		)
Net liabilities from price risk management activities as of end of year	$	100		$	139
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	12		$	133

* Includes realized losses, net of $3 million in 2014 and $1 million in 2013.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans is classified as Level 3 fair value measurement and is estimated based on the terms of the loans and the Company’s creditworthiness. These significant unobservable inputs to the Level 3 fair value measurement include the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximates their carrying value.

As of December 31, 2014, the carrying amount of PGE’s long-term debt was $2,501 million and its estimated aggregate fair value was $2,901 million, consisting of $2,596 million and $305 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2013, the carrying amount of PGE’s long-term debt was $1,916 million and its estimated aggregate fair value was $2,074 million, all classified as Level 2 in the fair value hierarchy.

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

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Price Risk Management (Notes)

12 Months Ended

Dec. 31, 2014

Price Risk Management [Abstract]

Price Risk Management

PRICE RISK MANAGEMENT

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

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

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

	As of December 31,
	2014			2013
Current assets:
Commodity contracts:
Electricity	$	4		$	9
Natural gas	2			4
Total current derivative assets	6		(1)	13		(1)
Noncurrent assets:
Commodity contracts:
Electricity	1			1
Total noncurrent derivative assets	1		(2)	1		(2)
Total derivative assets not designated as hedging instruments	$	7		$	14
Total derivative assets	$	7		$	14
Current liabilities:
Commodity contracts:
Electricity	$	54		$	20
Natural gas	52			29
Total current derivative liabilities	106			49
Noncurrent liabilities:
Commodity contracts:
Electricity	58			107
Natural gas	64			34
Total noncurrent derivative liabilities	122			141
Total derivative liabilities not designated as hedging instruments	$	228		$	190
Total derivative liabilities	$	228		$	190

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

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

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): 

	As of December 31,
	2014			2013
Commodity contracts:
Electricity	16		MWh	14		MWh
Natural gas	127		Dth	106		Dth
Foreign currency exchange	$	7	Canadian	$	7	Canadian

PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table below.

Information related to price risk management liabilities subject to master netting agreements is as follows (in millions):

	Gross		Gross		Net		Gross Amounts Not Offset in
	Amounts		Amounts		Amounts		Consolidated Balance Sheets
	Recognized		Offset		Presented		Derivatives			Cash Collateral(1)		Net Amount
As of December 31, 2014:
Liabilities:
Commodity contracts:
Electricity(2)	$	55	$	—	$	55	$	(55	)	$	—	$	—
Natural gas(2)	17		—		17		(17		)	—		—
	$	72	$	—	$	72	$	(72	)	$	—	$	—
As of December 31, 2013:
Liabilities:
Commodity contracts:
Electricity(2)	$	91	$	—	$	91	$	(91	)	$	—	$	—
Natural gas(2)	1		—		1		(1		)	—		—
	$	92	$	—	$	92	$	(92	)	$	—	$	—

(1) As of December 31, 2014 and 2013, the Company had collateral posted of $11 million and $7 million, respectively, which consists entirely of letters of credit.

(2) Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.

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

	Years Ended December 31,
	2014		2013		2012
Commodity contracts:
Electricity	$	13	$	78	$	56
Natural Gas	72		28		19
Foreign currency exchange	—		1		—

Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2014, 2013, and 2012, $83 million, $120 million, and $42 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 2014 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):

	2015		2016		2017		2018		2019		Thereafter		Total
Commodity contracts:
Electricity	$	50	$	19	$	6	$	5	$	5	$	22	$	107
Natural gas	49		44		18		3		—		—		114
Net unrealized loss	$	99	$	63	$	24	$	8	$	5	$	22	$	221

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

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2014 was $216 million, for which the Company had posted $29 million in collateral, consisting primarily of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2014, the cash requirement to either post as collateral or settle the instruments immediately would have been $213 million. As of December 31, 2014, PGE had posted an additional $11 million in cash collateral for derivative instruments with no credit-risk-related contingent features, which is classified as Margin deposits on the Company’s consolidated balance sheet.

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

	As of December 31,
	2014		2013
Assets from price risk management activities:
Counterparty A	63	%	53	%
Counterparty B	14		6
	77	%	59	%
Liabilities from price risk management activities:
Counterparty C	22	%	43	%
Counterparty D	12		11
	34	%	54	%

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

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Asset Retirement Obilgations

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):

	As of December 31,
	2014		2013
Trojan decommissioning activities	$	41	$	41
Utility plant	64		49
Non-utility property	11		10
Asset retirement obligations	$	116	$	100

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

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs were seeking approximately $112 million in damages incurred through 2009.

A trial before the U.S. Court of Federal Claims concluded in 2012, with the U.S. Court of Federal Claims issuing a judgment awarding certain damages to the Plaintiffs. In 2013, the Plaintiffs received $70 million for the settlement of this matter. The settlement agreement also provided for a process to submit claims for allowable costs for the period 2010 through 2013, and was subsequently extended to cover 2014 through 2016. In 2014, the Plaintiffs received $9 million for costs related to 2010 through 2013. The Company will seek recovery of any costs for subsequent periods in future extensions of the agreement.

PGE has received proceeds of $50 million related to its share in this legal matter, with $44 million received in 2013 and $6 million received in 2014. Such funds were deposited into the Nuclear decommissioning trust and recorded as a regulatory liability to offset amounts previously collected in relation to Trojan decommissioning activities. In December 2014, the OPUC issued an order on the Company’s 2015 GRC, authorizing the return of the $50 million of proceeds received related to this legal matter to customers over a three-year period beginning January 1, 2015.

The ARO related to Trojan decommissioning activities is not impacted by the outcome of this legal matter because the proceeds received in connection with the settlement of this legal matter are for past Trojan decommissioning costs and this ARO reflects future Trojan decommissioning costs.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets where disposal is governed by environmental regulation. During 2014, the Company incurred AROs totaling $8 million related to the three new generating resources: Port Westward Unit 2 (PW2), Tucannon River Wind Farm (Tucannon River), and Carty Generating Station (Carty).

In December 2014 and 2013, PGE increased its ARO related to Boardman by $7 million and $4 million, respectively, in connection with the acquisition of additional interests in Boardman, with corresponding increases in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. For additional information regarding the Company’s acquisition of additional interests in Boardman, see Note 17, Jointly-owned Plant.

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

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

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	100		$	94		$	87
Liabilities incurred	15			4			—
Liabilities settled	(3		)	(4		)	(3		)
Accretion expense	6			6			6
Revisions in estimated cash flows	(2		)	—			4
Balance as of end of year	$	116		$	100		$	94

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

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

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

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Net realized and unrealized gains and losses on derivative transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commodity contracts: [Abstract]
Electricity	$ 13	$ 78	$ 56
Natural Gas	72	28	19
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency	$ 0	$ 1	$ 0

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Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Benefits [Abstract]
Pension Contributions	$ 0	$ 0	$ 0
Defined Benefit Plan, Benefits Paid	16
Contribution to health reimbursement account - sick time	58.00%
Contribution to health reimbursement account - earned time off	100.00%
OtherPostretirementDefinedBenefitPlanLiabilityCurrent	2	2
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	23
Net actuarial loss portion of amortization from AOCL for pension benefits	20
Net Actuarial Loss Portion of Amortization from AOCL for Non-qualified benefits	1
Net actuarial loss portion of amortiztion of AOCL for other postretirement benefits	1
Prior service cost portion of amortization of AOCL for other postretirement benefits	1
Defined benefit plan, current annual rate of health care cost increase	7.00%	7.50%	8.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	0.50%	0.50%	0.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.00%	5.00%	5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	0
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	0
Company match pre 2009 hire	6.00%
Company match post 2008 hire	5.00%
Company contribution percentage to 401k for post 2008 hires	5.00%
Company contribution percent to 401k for bargaining employees	1.00%
401k Plan Company contributions	$ 16	$ 16	$ 16

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Counterparties representing 10% or more (Details)	Dec. 31, 2014	Dec. 31, 2013
Assets from price risk management activities:
Counterparty A	63.00%	53.00%
Counterparty B	14.00%	6.00%
Concentration of Risk, Derivative Instruments, Assets	77.00%	59.00%
Liabilities from price risk management activities: [Abstract]
Counterparty C	22.00%	43.00%
Counterparty D	12.00%	11.00%
Concentration of Risk, Derivative Instruments, Liabilities	34.00%	54.00%

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Price Risk Management Price risk management assets and liabilities subject to master netting agreements (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Electricity [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (55)	$ (91)
Electricity [Member] | Gross amounts offset [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Electricity [Member] | net amount presented [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(55)	(91)
Electricity [Member] | Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(55)	(91)
Electricity [Member] | Securities Pledged as Collateral [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Electricity [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Natural Gas [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(17)	(1)
Natural Gas [Member] | Gross amounts offset [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Natural Gas [Member] | net amount presented [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(17)	(1)
Natural Gas [Member] | Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(17)	(1)
Natural Gas [Member] | Securities Pledged as Collateral [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Natural Gas [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Liabilities, Total [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(72)	(92)
Liabilities, Total [Member] | Gross amounts offset [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Liabilities, Total [Member] | net amount presented [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(72)	(92)
Liabilities, Total [Member] | Derivative [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(72)	(92)
Liabilities, Total [Member] | Securities Pledged as Collateral [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Liabilities, Total [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 0	$ 0

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Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.60%	0.30%
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	3	3
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	12.40%	12.10%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	23.00%	25.10%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%	0.00%

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Commitments and Guarantees (Policies)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Minimum Guarantees, Policy [Policy Text Block]

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities.

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Summary of Significant Accounting Policies Estimated average service lives (Details)	12 Months Ended
	Dec. 31, 2014
Production, excluding thermal:
Hydro	87
Wind	27
Transmission	53
Distribution	40
General	13

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Stock Purchase Plan

12 Months Ended

Dec. 31, 2014

Employee Stock Purchase Plan Note [Abstract]

Stock Purchase Plan [Text Block]

EQUITY-BASED PLANS

Equity Forward Sale Agreement

PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 11,100,000 shares of its common stock in June 2013. In connection with such public offering, the underwriters exercised their over-allotment option in full and PGE issued 1,665,000 shares of its common stock for net proceeds of $47 million. Pursuant to the terms of the EFSA, a forward counterparty borrowed 11,100,000 shares of PGE’s common stock from third parties in the open market and sold the shares to a group of underwriters for $29.50 per share, less an underwriting discount equal to $0.96 per share. The underwriters then sold the shares in a public offering. PGE receives proceeds from the sale of common stock when the EFSA is physically settled (described below), and at that time PGE issues new shares of common stock and records the proceeds in equity. Through December 31, 2014, the Company has issued 700,000 shares of its common stock pursuant to the EFSA for net proceeds of $20 million.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of: i) physical; ii) cash; or iii) net share settlement, in whole or in part, at any time on or prior to June 11, 2015, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $29.50 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

The EFSA had no initial fair value since it was entered into at the then market price of the common stock. Accordingly, PGE concluded that the EFSA was an equity instrument which does not qualify as a derivative because the EFSA was indexed to the Company’s stock. PGE anticipates settling the EFSA through physical settlement on or before June 11, 2015.

As of December 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares to the forward counterparty in exchange for cash of $275 million. In addition, at December 31, 2014, the Company could have elected to make a cash settlement by paying approximately $119 million, or a net share settlement by delivering approximately 3,135,000 shares of common stock. To the extent that PGE makes a cash or net share settlement, the Company would receive no additional proceeds from the public offering.

Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

Employee Stock Purchase Plan

PGE has an employee stock purchase plan (ESPP), under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. There are two six-month offering periods each year, January 1 through June 30 and July 1 through December 31, during which eligible employees may purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2014, there were 427,021 shares available for future issuance pursuant to the ESPP.

Dividend Reinvestment and Direct Stock Purchase Plan

PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2014, there were 2,481,110 shares available for future issuance pursuant to the DRIP.

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Jointly-owned Plant

12 Months Ended

Dec. 31, 2014

Jointly-owned Plant [Abstract]

Jointly-owned Plant [Text Block]

JOINTLY-OWNED PLANT

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

In 1985, PGE sold a 15% undivided interest in Boardman and a 10.714% undivided interest in the Company’s share of the Pacific Northwest Intertie transmission line (jointly, the Facility Assets) to an unrelated third party (Purchaser). Under terms of the original 1985 agreements, on December 31, 2013, PGE acquired the Facility Assets from the Purchaser in exchange for $1 from the Purchaser. PGE assumed responsibility for the ARO related to that 15% interest in Boardman in the amount of $7 million. The acquisition of the 15% interest in Boardman increased the Company’s ownership share from 65% to 80% on December 31, 2013. Such transaction is non-cash and is excluded from investing activities in the consolidated statement of cash flows for the year ended December 31, 2013.

On December 31, 2014, PGE acquired an additional 10% interest in Boardman from another co-owner, whereby the Company received net cash of $8 million from the co-owner to assume the net liabilities associated with the ownership of this 10% interest. In connection with this transaction, PGE recorded Electric utility plant of $7 million, inventory of $4 million, an ARO of $7 million, a regulatory liability of $6 million to be returned to customers in 2015 and 2016, a regulatory liability of $4 million related to future additional decommissioning and environmental costs, and deferred revenue of $2 million. The acquisition of the 10% interest in Boardman increased the Company’s ownership share from 80% to 90%.

As of December 31, 2014, PGE had the following investments in jointly-owned plant (dollars in millions):

	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	90.00	%	1980			$	510	$	350	$	—
Colstrip	20.00		1986			520		334		2
Pelton/Round Butte	66.67		1958	/	1964	237		55		8
Total						$	1,267	$	739	$	10

* Excludes AROs and accumulated asset retirement removal costs.

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Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Capital Additions [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 343
Unrecorded Unconditional Purchase Obligation, Due within One Year	242
Unrecorded Unconditional Purchase Obligation, Due within Two Years	21
Unrecorded Unconditional Purchase Obligation, Due within Three Years	2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	2
Unrecorded Unconditional Purchase Obligation, Due after Five Years	74
Long-term Contract for Purchase of Electric Power [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	1,605
Unrecorded Unconditional Purchase Obligation, Due within One Year	179
Unrecorded Unconditional Purchase Obligation, Due within Two Years	167
Unrecorded Unconditional Purchase Obligation, Due within Three Years	140
Unrecorded Unconditional Purchase Obligation, Due within Four Years	143
Unrecorded Unconditional Purchase Obligation, Due within Five Years	143
Unrecorded Unconditional Purchase Obligation, Due after Five Years	833
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	90
Unrecorded Unconditional Purchase Obligation, Due within One Year	27
Unrecorded Unconditional Purchase Obligation, Due within Two Years	26
Unrecorded Unconditional Purchase Obligation, Due within Three Years	6
Unrecorded Unconditional Purchase Obligation, Due within Four Years	6
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	20
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	49
Unrecorded Unconditional Purchase Obligation, Due within One Year	8
Unrecorded Unconditional Purchase Obligation, Due within Two Years	7
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	2
Unrecorded Unconditional Purchase Obligation, Due after Five Years	23
Natural gas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	453
Unrecorded Unconditional Purchase Obligation, Due within One Year	56
Unrecorded Unconditional Purchase Obligation, Due within Two Years	37
Unrecorded Unconditional Purchase Obligation, Due within Three Years	40
Unrecorded Unconditional Purchase Obligation, Due within Four Years	40
Unrecorded Unconditional Purchase Obligation, Due within Five Years	36
Unrecorded Unconditional Purchase Obligation, Due after Five Years	244
Coal and transportationSupply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	58
Unrecorded Unconditional Purchase Obligation, Due within One Year	23
Unrecorded Unconditional Purchase Obligation, Due within Two Years	14
Unrecorded Unconditional Purchase Obligation, Due within Three Years	11
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Operatomg leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	244
Unrecorded Unconditional Purchase Obligation, Due within One Year	10
Unrecorded Unconditional Purchase Obligation, Due within Two Years	11
Unrecorded Unconditional Purchase Obligation, Due within Three Years	12
Unrecorded Unconditional Purchase Obligation, Due within Four Years	11
Unrecorded Unconditional Purchase Obligation, Due within Five Years	8
Unrecorded Unconditional Purchase Obligation, Due after Five Years	192
Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	2,842
Unrecorded Unconditional Purchase Obligation, Due within One Year	545
Unrecorded Unconditional Purchase Obligation, Due within Two Years	283
Unrecorded Unconditional Purchase Obligation, Due within Three Years	216
Unrecorded Unconditional Purchase Obligation, Due within Four Years	211
Unrecorded Unconditional Purchase Obligation, Due within Five Years	201
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 1,386

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Jointly-owned Plant (Tables)

12 Months Ended

Dec. 31, 2014

Jointly-owned Plant [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31, 2014, PGE had the following investments in jointly-owned plant (dollars in millions):

	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	90.00	%	1980			$	510	$	350	$	—
Colstrip	20.00		1986			520		334		2
Pelton/Round Butte	66.67		1958	/	1964	237		55		8
Total						$	1,267	$	739	$	10

* Excludes AROs and accumulated asset retirement removal costs.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

AROs consist of the following (in millions):

	As of December 31,
	2014		2013
Trojan decommissioning activities	$	41	$	41
Utility plant	64		49
Non-utility property	11		10
Asset retirement obligations	$	116	$	100

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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

	Years Ended December 31,
	2014			2013			2012
Balance as of beginning of year	$	100		$	94		$	87
Liabilities incurred	15			4			—
Liabilities settled	(3		)	(4		)	(3		)
Accretion expense	6			6			6
Revisions in estimated cash flows	(2		)	—			4
Balance as of end of year	$	116		$	100		$	94

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 127	$ 107
Accounts receivable, net	149	146
Unbilled revenues	93	104
Inventories, at average cost:
Materials and supplies	42	41
Fuel	40	24
Regulatory assets--current	133	66
Other current assets	115	103
Total current assets	699	591
Electric utility plant:
Generation	3,742	2,968
Transmission	440	417
Distribution	3,075	2,943
General	426	381
Intangible	478	386
Construction work-in-progress	417	508
Total electric utility plant	8,578	7,603
Accumulated depreciation and amortization	(2,899)	(2,723)
Electric utility plant, net	5,679	4,880
Regulatory assets--noncurrent	494	464
Nuclear decommissioning trust	90	82
Non-qualified benefit plan trust	32	35
Other noncurrent assets	48	49
Total assets	7,042	6,101
Current liabilities:
Accounts payable	156	173
Liabilities from price risk management activities-current	106	49
Current portion of long-term debt	375	0
Accrued expenses and other current liabilities	236	171
Total current liabilities	873	393
Long-term debt, net of current portion	2,126	1,916
Regulatory liabilities--noncurrent	906	865
Deferred income taxes	625	586
Unfunded status of pension and postretirement plans	237	154
Liabilities from price risk management activities--noncurrent	122	141
Asset retirement obligations	116	100
Non-qualified benefit plan liabilities	105	101
Other noncurrent liabilities	21	25
Total liabilities	5,131	4,281
Commitments and Contingencies (see notes)
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	0	0
Common stock, no par value, 160,000,000 shares authorized; 78,228,339 and 78,085,559 shares issued and outstanding as of December 31, 2014 and 2013, respectively	918	911
Accumulated other comprehensive loss	(7)	(5)
Retained earnings	1,000	913
Total Portland General Electric Company shareholders’ equity	1,911	1,819
Noncontrolling interests' equity	0	1
Total equity	1,911	1,820
Total liabilities and equity	$ 7,042	$ 6,101

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Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred income tax assets:
Price risk management	$ 88	$ 71
Employee benefits	161	122
Deferred Tax Assets, tax credits, net of valuation allowance	13	51
Deferred income taxes	48	33
Deferred Tax Assets, Tax Deferred Expense, Other	1	0
Total deferred income tax assets	311	277
Deferred income tax liabilities:
Depreciation and amortization	693	646
Regulatory assets	210	175
Total deferred income tax liabilities	903	821
Deferred income tax liability, net	(592)	(544)
Classification of net deferred income taxes:
Current deferred income tax asset	33	42
Noncurrent deferred income tax liability	$ (625)	$ (586)

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Basis of Presentation

12 Months Ended

Dec. 31, 2014

Basis of Presentation [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

Nature of Operations

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power marketers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of December 31, 2014, PGE served 842,273 retail customers with a service area population of approximately 1.8 million, comprising approximately 46% of the state’s population.

As of December 31, 2014, PGE had 2,600 employees, with 780 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 743 and 37 employees and expire in February 2016 and August 2017, respectively.

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

Consolidation Principles

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

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

Use of Estimates

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

Customer Billing Matter

In May 2013, PGE discovered that it had over-billed an industrial customer during a period of several years as a result of a meter configuration error. An analysis of the data determined that the Company’s revenues were overstated by approximately $3 million in 2012 and in 2011, $2 million in 2010, and $1 million in 2009. PGE believes the customer billing error is not material to any annual reporting period. The Company corrected this matter in the second quarter of 2013 as an out of period adjustment, and recorded, as a reduction to Revenues, net, a refund to the customer in the amount of $9 million.

Reclassifications

To conform with the 2014 presentation, PGE has reclassified Margin deposits of $9 million with Other current assets in the consolidated balance sheet as of December 31, 2013. In addition, the Company reclassified Renewable adjustment clause deferrals of $1 million to Other non-cash income and expenses, net in the operating activities section of the consolidated statement of cash flows for the year ended December 31, 2012 and separately presented Cash received to be returned to customers pursuant to the Residential Exchange Program of $1 million from Other non-cash income and expenses, net for the year ended December 31, 2013.

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Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	$ 11.97	$ 9.63
Natural gas financial swaps	2.88	3.16
Fnancial swaps - electricity	11.97	9.63
Maximum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	122.72	77.95
Natural gas financial swaps	4.86	4.49
Fnancial swaps - electricity	39.26	46.07
Weighted Average [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	37.43	40.18
Natural gas financial swaps	3.41	3.71
Fnancial swaps - electricity	27.88	33.01
Assets [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	0	0
Natural gas financial swaps	0	0
Fnancial swaps - electricity	1,000,000	1,000,000
Total commodity contracts	1,000,000	1,000,000
Liabilities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	77,000,000	103,000,000
Natural gas financial swaps	21,000,000	23,000,000
Fnancial swaps - electricity	3,000,000	14,000,000
Total commodity contracts	$ 101,000,000	$ 140,000,000

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Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Benefit payments	$ (16)
As of January 1	596			591
Noncurrent asset	(32)	(35)
Noncurrent liability	(237)	(154)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
As of January 1	777	705	728
Service cost	15	17	14
Interest cost on benefit obligation	34	30	31
Participants’ contributions	0	0
Actuarial loss (gain)	72	(38)
Defined Benefit Plan, Special Termination Benefits	0	0
Benefit payments	(48)	(32)
Defined Benefit Plan, Administration Expenses	(1)	0
As of January 1	596	537		591
Unfunded position as of December 31	186	109
Net actuarial loss (gain) included in comprehensive income	67	(89)
Defined Benefit Plan, Amortization of Gains (Losses)	(17)	(24)	(17)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	0
Total Amounts included in comprehensive income	50	(113)
Defined Benefit Plan, Accumulated Benefit Obligation	691	631
Actual return on plan assets	44	91
Company contributions	0	0
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(186)	(109)
Net actuarial loss	236	186
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	236	186
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate	4.02%	4.84%
Discount rate used to calculate benefit obligation	4.84%	4.24%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase	3.65%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.65%	3.65%
Long-term rate of return on plan assets	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.50%	8.25%
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
As of January 1	83	77	84
Service cost	2	2	2
Interest cost on benefit obligation	4	3	3
Participants’ contributions	1	2
Actuarial loss (gain)	4	(9)
Defined Benefit Plan, Special Termination Benefits	1	1
Benefit payments	(6)	(6)
Defined Benefit Plan, Administration Expenses	0	0
As of January 1	32	28		32
Unfunded position as of December 31	51	45
Net actuarial loss (gain) included in comprehensive income	5	(11)
Defined Benefit Plan, Amortization of Gains (Losses)	(1)	(1)	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(1)	(1)	(1)
Total Amounts included in comprehensive income	3	(13)
Actual return on plan assets	1	5
Company contributions	4	3
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(51)	(45)
Net actuarial loss	10	6
Prior service cost	1	2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	11	8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate	3.07%	3.46%
Defined Benefit Plan Discount rate - upper range	4.10%	4.96%
Discount rate used to calculate benefit obligation	3.46%	2.77%
Defined Benefit Plan Cost Discount rate - upper range	4.96%	4.13%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase	4.58%	4.58%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.58%	4.58%
Long-term rate of return on plan assets	6.37%	6.46%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.46%	5.89%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
As of January 1	27	24	27
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Participants’ contributions	0	0
Actuarial loss (gain)	5	(2)
Defined Benefit Plan, Special Termination Benefits	0	0
Benefit payments	(3)	(2)
Defined Benefit Plan, Administration Expenses	0	0
As of January 1	16	15		15
Unfunded position as of December 31	12	8
Net actuarial loss (gain) included in comprehensive income	5	(1)
Defined Benefit Plan, Amortization of Gains (Losses)	(1)	(1)	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	0
Total Amounts included in comprehensive income	4	(2)
Defined Benefit Plan, Accumulated Benefit Obligation	27	24
Actual return on plan assets	1	3
Company contributions	1	0
Noncurrent asset	(15)	(16)
Current liability	(2)	(2)
Noncurrent liability	(25)	(22)
Net actuarial loss	13	9
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 13	$ 9
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate	4.02%	4.84%
Discount rate used to calculate benefit obligation	4.84%	4.24%

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Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets Earning a Return, Other Category	$ 33	$ 16
Regulatory Assets Earning a Return	63
Regulatory Assets Earning a Rate of Return at the Cost of Debt	19
Authorized Cost of Debt	5.54%
Regulatory Assets Earning a Rate of Return at the Cost of Capital	2
Authorized Cost of Capital	7.65%
Regulatory Assets Earning a Rate of Return by Inclusion in Rate Base	33
Regulatory Assets Earning a Rate of Return at the Approved Rate	9
Approved Rate for Deferred Account Under Amortization, Low End of Range	1.47%
Approved Rate for Deferred Accounts under Amortization, High End of Range	1.77%
Trojan ISFSI pollution control tax credits		$ 8

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Contingencies

12 Months Ended

Dec. 31, 2014

Contingencies [Abstract]

Contingencies [Text Block]

CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

Trojan Investment Recovery

Regulatory Proceedings. In 1993, PGE closed Trojan and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

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

In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining investment in Trojan as of September 30, 2000, along with several largely offsetting regulatory liabilities. After offsetting the investment in Trojan with these liabilities, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan was no longer included in prices charged to customers, either through a return of or a return on that investment. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

The OPUC then issued an order in 2008 (2008 Order) that required PGE to provide refunds, including interest from September 30, 2000, to customers who received service from the Company during the period from October 1, 2000 to September 30, 2001. The Company recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below separately appealed the 2008 Order to the Oregon Court of Appeals.

On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. On May 31, 2013, the Court of Appeals denied the appellants’ request for reconsideration of the decision. On October 18, 2013, the Oregon Supreme Court granted plaintiffs’ petition seeking review of the February 6, 2013 Oregon Court of Appeals decision.

On October 2, 2014, the Oregon Supreme Court, in a unanimous decision, affirmed the February 6, 2013 Oregon Court of Appeals decision that upheld the OPUC’s 2008 Order. On January 15, 2015, the Oregon Supreme Court denied the plaintiffs petition seeking reconsideration of the October 2, 2014 decision.

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

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

The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court.

The October 2, 2014 Oregon Supreme Court decision described above expressly noted that the plaintiffs in the class action must address any request to lift the abatement with the Marion County Circuit Court. PGE is evaluating how to proceed with respect to the class actions.

PGE believes that the October 2, 2014 Oregon Supreme Court decision has reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain pending, management believes that it is still reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss, or to estimate a range of potential loss.

Pacific Northwest Refund Proceeding

In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. Upon appeal of the decision to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit), the Ninth Circuit remanded the case to the FERC to, among other things, address market manipulation evidence in detail and account for the evidence in any future orders regarding the award or denial of refunds in the proceedings.

In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. The orders held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also expanded the scope of the hearing to allow parties to pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule of a statutory requirement. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund claimants have filed petitions for appeal of these procedural orders with the Ninth Circuit.

Pursuant to a FERC-ordered settlement process, the Company received notice of two claims and reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012.

Additionally, the settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement, including the California Energy Resource Scheduling division of the California Department of Water Resources (CERS), as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The above-referenced settlements resulted in a release of the Company as a named respondent in the first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.

During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of CERS, presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of the two CERS’ respondents, but that CERS had produced evidence that the remaining CERS respondent had engaged in unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. The Administrative Law Judge determined that in the second phase the remaining respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. The findings in the Initial Decision are subject to further FERC action. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.

Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds from any of the current respondents, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, will pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss.

EPA Investigation of Portland Harbor

A 1997 investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In January 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017.

The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss.

DEQ Investigation of Downtown Reach

The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In January 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in December 2011 and entered into a consent order with the DEQ in July 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. The draft feasibility study report, which describes possible remediation alternatives that range in estimated cost from $3 million to $8 million, was submitted to the DEQ in February 2014. Following the DEQ’s evaluation of the draft feasibility study, PGE submitted a final feasibility study to the DEQ in September 2014. The estimated costs in the final feasibility study did not differ significantly from those in the draft feasibility study. Using the Company’s best estimate of the probable cost for the remediation effort from the set of alternatives provided in the feasibility study report, PGE has a $3 million reserve for this matter as of December 31, 2014.

Based on the available evidence of previous rate recovery of incurred environmental remediation costs for PGE, as well as for other utilities operating within the same jurisdiction, the Company has concluded that the estimated cost of $3 million to remediate the Downtown Reach is probable of recovery. As a result, the Company also has a regulatory asset of $3 million for future recovery in prices as of December 31, 2014. The Company included recovery of the regulatory asset in its 2015 GRC filed with the OPUC. The final order issued by the OPUC in the 2015 GRC includes revenues to offset the amortization of the regulatory asset over a two year period beginning January 1, 2015.

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleges certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and states that the Sierra Club and MEIC will: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees.

The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.

On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.

On May 3, 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emissions increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment.

On August 27, 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed on September 26, 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is ongoing with trial now scheduled for November 2015.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.

Oregon Tax Court Ruling

On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue (DOR) interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue is whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. The DOR has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld. Oral argument occurred in May 2014 and the parties now await a Court decision.

If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $7 million due to an increase in the tax rate at which deferred tax liabilities would be recognized in future years. During the third quarter of 2013, the Company entered into a closing agreement with the DOR, under which the DOR agreed to the tax apportionment methodology utilized on the tax returns relating to open tax years 2008 through 2012.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome.

Other Matters

PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

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Revolving Credit Facilities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Line of Credit Facility [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity	$ 700,000,000
Credit Facilities - $400 million revolver	400,000,000
Credit Facilities - $300 million revolver	300,000,000
Line of Credit Facitlity, Covenant Terms, One Month Term	one
Line of Credit Facitlity, Covenant Terms, Two Month Term	two
Line of Credit Facitlity, Covenant Terms, Three Month Term	three
Line of Credit Facitlity, Covenant Terms, Six Month Term	six
Debt Instrument, Covenant Description	.65
Ratio of Indebtedness to Net Capital	0.567
Commercial Paper, Maximum Term	270
FERC Authorized Short-term Debt, effective through February 6, 2014	900,000,000
Short-term Debt	0
Line of Credit Facility, Amount Outstanding	20,000,000
Line of Credit Facility, Remaining Borrowing Capacity	680,000,000
letter of credit facility	30,000,000
Letters of Credit Outstanding, Amount	$ 56,000,000

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value of Financial Instruments [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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

	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	65	$	—	$	65
Debt securities:
Domestic government	7		7		—		14
Corporate credit	—		11		—		11
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		1		—		5
International	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		4		1		5
Natural gas	—		2		—		2
	$	12	$	90	$	1	$	103
Liabilities - Liabilities from price risk management activities(1) (3):
Electricity	$	—	$	32	$	80	$	112
Natural gas	—		95		21		116
	$	—	$	127	$	101	$	228

(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 $26 million, which are recorded at cash surrender value.

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

	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust (1):
Money market funds	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	6		8		—		14
Corporate credit	—		9		—		9
Non-qualified benefit plan trust (2):
Equity securities:
Domestic	4		3		—		7
International	1		—		—		1
Debt securities - domestic government	1		—		—		1
Assets from price risk management activities (1) (3):
Electricity	—		9		1		10
Natural gas	—		4		—		4
	$	12	$	92	$	1	$	105
Liabilities - Liabilities from price risk management activities (1) (3):
Electricity	$	—	$	10	$	117	$	127
Natural gas	—		40		23		63
	$	—	$	50	$	140	$	190

(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 $26 million, which are recorded at cash surrender value.

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

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

	Level 1		Level 2		Level 3		Total
As of December 31, 2014:
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	$	42	$	146	$	—	$	188
International	—		171		—		171
Debt securities:
Domestic government and corporate credit	—		197		—		197
Private equity funds	—		—		29		29
	$	42	$	520	$	29	$	591
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	6	$	—	$	6
Equity securities:
Domestic	10		1		—		11
International	10		—		—		10
Debt securities—Domestic government	5		—		—		5
	$	25	$	7	$	—	$	32
As of December 31, 2013:
Defined Benefit Pension Plan assets:
Equity securities:
Domestic	$	166	$	19	$	—	$	185
International	185		—		—		185
Debt securities:
Domestic government and corporate credit	—		181		—		181
Corporate credit	14		—		—		14
Private equity funds	—		—		31		31
	$	365	$	200	$	31	$	596
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	10	$	—	$	10
Equity securities:
Domestic	8		2		—		10
International	9		—		—		9
Debt securities—Domestic government	3		—		—		3
	$	20	$	12	$	—	$	32

Fair Value, Option, Quantitative Disclosures [Table Text Block]

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:

						Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)
As of December 31, 2014:
Electricity physical forward	$	—	$	77	Discounted cash flow	Electricity forward price (per MWh)	$	11.97	$	122.72	$	37.43
Natural gas financial swaps	—		21		Discounted cash flow	Natural gas forward price (per Dth)	2.88		4.86		3.41
Electricity financial futures	1		3		Discounted cash flow	Electricity forward price (per MWh)	11.97		39.26		27.88
	$	1	$	101
As of December 31, 2013:
Electricity physical forward	$	—	$	103	Discounted cash flow	Electricity forward price (per MWh)	$	9.63	$	77.95	$	40.18
Natural gas financial swaps	—		23		Discounted cash flow	Natural gas forward price (per Dth)	3.16		4.49		3.71
Electricity financial futures	1		14		Discounted cash flow	Electricity forward price (per MWh)	9.63		46.07		33.01
	$	1	$	140

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):

	Years Ended December 31,
	2014			2013
Net liabilities from price risk management activities as of beginning of year	$	139		$	16
Net realized and unrealized losses *	15			134
Settlements	(4		)	(1		)
Net transfers out of Level 3 to Level 2	(50		)	(10		)
Net liabilities from price risk management activities as of end of year	$	100		$	139
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	12		$	133

* Includes realized losses, net of $3 million in 2014 and $1 million in 2013.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

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Income Taxes

12 Months Ended

Dec. 31, 2014

Income Taxes Note [Abstract]

Income Taxes

INCOME TAXES

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

	Years Ended December 31,
	2014		2013		2012
Current:
Federal	$	20	$	10	$	16
State and local	2		—		1
	22		10		17
Deferred:
Federal	26		4		30
State and local	13		7		17
	39		11		47
Income tax expense	$	61	$	21	$	64

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

	Years Ended December 31,
	2014		2013		2012
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(11.4	)	(21.8	)	(11.8	)
State and local taxes, net of federal tax benefit	3.9		3.4		3.5
Flow through depreciation and cost basis differences	(2.3	)	2.8		2.4
Adjustment to deferred taxes for change in blended composite state tax rate	—		—		2.6
Other	0.8		(2.6	)	(0.6	)
Effective tax rate	26.0	%	16.8	%	31.1	%

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

	As of December 31,
	2014			2013
Deferred income tax assets:
Employee benefits	$	161		$	122
Price risk management	88			71
Regulatory liabilities	48			33
Tax credits	13			51
Other	1			—
Total deferred income tax assets	311			277
Deferred income tax liabilities:
Depreciation and amortization	693			646
Regulatory assets	210			175
Total deferred income tax liabilities	903			821
Deferred income tax liability, net	$	(592	)	$	(544	)
Classification of net deferred income taxes:
Current deferred income tax asset *	$	33		$	42
Noncurrent deferred income tax liability	(625		)	(586		)
	$	(592	)	$	(544	)

* Included in Other current assets in the consolidated balance sheets.

To conform with the 2014 presentation, the Company reclassified $17 million to Regulatory liabilities from Other in the 2013 deferred income tax assets section of the preceding table.

As of December 31, 2014, PGE has federal and state tax credit carryforwards of $10 million and $3 million, respectively, which will expire at various dates from 2021 through 2036.

PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2014 and 2013 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2014 and 2013, PGE had no unrecognized tax benefits.

PGE and its subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Oregon, California, Montana, and certain local jurisdictions. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2010 and all issues were resolved related to those years. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

Further guidance was issued during 2014 that clarified final regulations issued on September 13, 2013, regarding the deduction and capitalization of expenditures related to tangible property. The final regulations under Internal Revenue Code Sections 162, 167 and 263(a) apply to amounts paid to acquire, produce, or improve tangible property, as well as dispositions of such property and have been adopted by PGE as of the January 1, 2014 effective date. The adoption of these regulations, including the consideration of subsequent guidance, did not have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

House of Representatives Bill 5771—The Tax Increase Prevention Act of 2014 was signed into law on December 19, 2014. PGE has examined the new law and while the Company intends to take advantage of some of the provisions, no provision will materially impact its consolidated financial position.

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Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 claims	Dec. 31, 2012 claims	Dec. 31, 1997	Dec. 31, 2013	Jun. 30, 2013 claims	Sep. 30, 2008	Sep. 30, 2000	Dec. 31, 1993
Loss Contingencies [Line Items]
Investment in Trojan								87.00%
Regulatory asset related to Trojan							$ 5,000,000
Refund to customers for Trojan Investment including interest						33,100,000
Class action damages sought	260,000,000
Loss Contingency, Claims Settled, Number		2
contracts	119
Site Contingency, Names of Other Potentially Responsible Parties	100		69
Low estimate of range of cost of Portland Harbor cleanup in total	169,000,000
Upper estimated range of total cost of Portland harbor cleanup	1,800,000,000
Loss Contingency, Range of Possible Loss, Minimum	3,000,000
Loss Contingency, Range of Possible Loss, Maximum	8,000,000
Loss Contingency, Estimate of Possible Loss				3,000,000
regulatory asset for recovery of loss contingencies	3,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%
Potential Income Tax Liability related to State Tax Court Ruling	7,000,000
Civil Penalty Claim - Per day per violation through January 12, 2009	32,500
Civil Penalty Claim - Per day per violation after January 12, 2009	$ 37,500
Claims moved to dismiss					36
Loss Contingency, Pending Claims, Number					39
projects added to plaintiff's suit	2
projects encompassed by suit	40