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  • 10-K (Feb 22, 2013)
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Portland General Electric Co 10-K 2015
POR 2014 10K


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 78,228,827 shares 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

 
 
 
 
 
 
 
 
 
 
 
 
Item 1.
 
Item 1A.
 
Item 1B.
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
 
 
 
 
 
 
 
Item 5.
 
Item 6.
 
Item 7.
 
Item 7A.
 
Item 8.
 
Item 9.
 
Item 9A.
 
Item 9B.
 
 
 
 
 
 
 
 
 
 
 
 
Item 10.
 
Item 11.
 
Item 12.
 
Item 13.
 
Item 14.
 
 
 
 
 
 
 
 
 
 
 
 
Item 15.
 
 
 
 
 
 
 


3


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


4


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

5


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

6


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

7


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.


9


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.”


10


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.



11


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

12


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

16


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.


17


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,

19


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.

20



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

21


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 EPAs 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 PGEs customers, could affect the Companys 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

23


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 thermal generating 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 Companys 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.


31


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.


32


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

33


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.

34


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 868 holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $37.74 per share. The following table sets forth, for the periods indicated, the highest and lowest sales prices of PGE’s common stock as reported on the NYSE.
 
 
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.


35


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
%



36


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;

37


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

38


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 CasesOn 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,

39


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.


40


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

41


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: