Document


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, 2017

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 Data 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, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer
[x]
 
Accelerated filer
[ ]
Non-accelerated filer
[ ]
(Do not check if a smaller reporting company)
 
 
 
 
 
Smaller reporting company
[ ]
 
 
 
Emerging growth company
[ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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, 2017, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $4,048,647,464. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 2, 2018, there were 89,114,522 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 April 25, 2018.



PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2017

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.
 
 
 
 
 
 
 


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DEFINITIONS

The abbreviations or acronyms defined below are used throughout this Form 10-K:
 
Abbreviation or Acronym
 
Definition
AFDC
 
Allowance for funds used during construction
ARO
 
Asset retirement obligation
AUT
 
Annual Power Cost Update Tariff
Beaver
 
Beaver natural gas-fired generating plant
Biglow Canyon
 
Biglow Canyon Wind Farm
Boardman
 
Boardman coal-fired generating plant
BPA
 
Bonneville Power Administration
CAA
 
Clean Air Act
Carty
 
Carty 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
EIM
 
Energy Imbalance Market
EPA
 
United States Environmental Protection Agency
ESS
 
Electricity Service Supplier
FERC
 
Federal Energy Regulatory Commission
FMB
 
First Mortgage Bond
FPA
 
Federal Power Act
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
 
S&P Global Ratings
SEC
 
United States Securities and Exchange Commission
Trojan
 
Trojan nuclear power plant
Tucannon River
 
Tucannon River Wind Farm
USDOE
 
United States Department of Energy


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PART I
 
ITEM 1.     BUSINESS.

General

Portland General Electric Company (PGE or the Company), a vertically-integrated electric utility with corporate headquarters located in Portland, Oregon, is 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 meets its retail load requirement with both Company-owned generation and power purchased in the wholesale market. The Company participates in the wholesale market through the purchase and sale of electricity and natural gas in an effort to obtain reasonably-priced power to serve its retail customers. PGE, incorporated in 1930, is publicly-owned, with its common stock listed on the New York Stock Exchange. The Company operates as a single business 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 51 incorporated cities, of which Portland and Salem are the largest. The Company estimates that at the end of 2017 its service area population was 1.9 million, comprising approximately 46% of the population of the State of Oregon. During 2017, the Company added nearly 12,000 customers and as of December 31, 2017, served a total of 875,000 retail customers.

PGE had 2,906 employees as of December 31, 2017, with 785 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 732 and 53 employees and expire March 2020 and August 2022, 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

Federal and State of Oregon regulation both can have a significant impact on the operations of PGE. In addition to the 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, as described in the discussion that follows.

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 (FPA). As such, the Company is subject to regulation by the FERC in matters related to

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wholesale 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 in all markets in which it sells electricity except in its own Balancing Authority Area (BAA). The BAA is the area in which PGE is responsible for balancing customer demand with electricity generation, in real time. Continued market-based rate authority requires specific actions by PGE including the filing of triennial market power studies with the FERC, the filing of notices of change in status, and compliance with FERC rules. In May 2017, PGE filed with the FERC proposed revisions to its market-based rate tariff to reflect its participation in the California Independent System Operator’s (CAISO) Energy Imbalance Market (western EIM). In June 2017, PGE separately filed with the FERC a Notice of Change in Status requesting authorization to trade at market-based rates in that market.

On September 28, 2017, the FERC issued an Order accepting both of these filings and authorizing PGE to transact at market-based rates in the western EIM. On August 30, 2017, CAISO filed with the FERC an Informational Readiness Certification for PGE’s participation in the western EIM, which began on October 1, 2017. The entry into the western EIM does not change PGE’s restriction on non-EIM sales at market-based rates within its BAA, which restriction does not have a material impact on the Company. For further information on the western EIM, see “Purchased Power” in the Power Supply section of this Item 1.

Transmission—PGE offers electricity 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 electric transmission business on its Open Access Same-time Information System, also known as OASIS. In PGE’s Notice of Change in Status filed with the FERC on June 16, 2017, PGE stated that inbound western EIM transfers would take place on certain paths upon which the Company holds firm transmission rights, a portion of which it has committed for western EIM transfers. In the FERC’s September 28, 2017 Order accepting this filing, the FERC ordered PGE to submit a change in status filing if there were to be a decrease in the amount of firm transmission capacity committed to western EIM transfers. For additional information, see the Transmission and Distribution section in this Item 1. and 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 (CIP) 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.

Natural Gas Pipelines—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 the Kelso-Beaver (KB) 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); Port Westward Unit 2 (PW2); and Beaver. As the operator of record of the KB 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 FPA, PGE’s hydroelectric generating plants are subject to FERC licensing requirements. PGE holds FERC licenses for the Company’s projects on the Deschutes, Clackamas, and Willamette Rivers. The licenses specify certain operating procedures and require capital projects focused on fish protection and reintroduction. The FERC license process includes an extensive public review process that involves the

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consideration of numerous natural resource issues and environmental conditions. 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 FPA, 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 FPA and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. The Company, pursuant to an order issued by the FERC on January 3, 2018, has authorization to issue up to $900 million of short-term debt through February 6, 2020.

Spent Fuel Storage—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, and a number of other state agencies, as described in the discussion that follows.

The OPUC, comprised of three members appointed by the governor of Oregon to serve non-concurrent four-year terms, 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 regulates the issuance of securities, prescribes accounting policies and practices, regulates the sale of utility assets, reviews transactions with affiliated companies, and has jurisdiction over the acquisition of, or exertion of substantial influence over, public utilities. The OPUC also oversees the Retail Customer Choice Program, approves funding for energy efficiency, and directs the manner in which the public purpose charges are collected and remitted to the Energy Trust of Oregon (ETO).

Economic Regulation—Under Oregon law, the OPUC is required to ensure that prices and terms of service are fair and non-discriminatory, and to 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. For additional information regarding the Company’s most recent general rate cases, see “General Rate Cases” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Power Costs. In addition to price changes resulting from the general rate case process, the OPUC has approved the following mechanisms by which PGE can adjust retail customer prices to cover changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s consolidated statements of income) and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income.
Annual Power Cost Update Tariff (AUT). Under this tariff, customer prices are adjusted annually to reflect forecasted NVPC. An initial NVPC forecast, submitted to the OPUC by April 1 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). Under the PCAM, PGE shares a portion of the business risk or benefit associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year. For additional information, see “Power Operations” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Renewable Energy. The 2007 Oregon Renewable Energy Act (the 2007 Act) established a Renewable Portfolio Standard (RPS), which required that PGE serve at least 15% of its retail load with renewable resources by 2015, with future requirements of 20% by 2020 and 25% by 2025. PGE met the 2015 requirement and expects to meet the requirements going forward.

The 2007 Act allows renewable energy certificates (RECs), 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 2007 Act also provides for the recovery in customer prices of prudently incurred costs 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 may submit a filing by April 1 of each year for new renewable resources expected to be placed in service in the current year, with prices expected to become effective January 1 of the following year. In addition, the RAC provides for the deferral and subsequent recovery of eligible costs incurred prior to January 1 of the following year.

Under the RAC, the Company has submitted no material additions or deferrals for the three years 2015 through 2017.

The State of Oregon passed Senate Bill 1547, effective March 8, 2016, a law referred to as the Oregon Clean Electricity and Coal Transition Plan (OCEP). The legislation prevents large utilities from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for the Company’s output from the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip)), increases the RPS percentages in certain future years, changes the life of certain RECs, requires the development of community solar programs, seeks the development of transportation electrification programs, and requires that a portion of electricity come from small scale renewable or certain biomass projects.

For more information regarding the OCEP, and its impact on PGE, see the “Legal, Regulatory, and Environmental Matters” section of Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Decoupling. The decoupling mechanism provides a means for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts undertaken by residential and certain commercial customers. The mechanism, authorized by the OPUC through 2019,

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provides for: i) collections from customers if weather-adjusted energy use per customer is lower than levels anticipated in the Company’s most recent general rate case; or ii) refunds to customers if weather-adjusted use per customer exceeds levels anticipated in the most recent general rate case. For additional information, see “Legal, Regulatory, and Environmental” in 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 on the RAC, the OCEP, and other ratemaking proceedings, 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.”

Senate Bill 978—The State of Oregon legislature passed a bill in its 2017 session referred to as SB 978, which directs the OPUC to investigate and provide a report to the legislature by September 15, 2018 on how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. PGE is actively working on this initiative, both internally and in conjunction with the OPUC, to provide input and support development of the report. The OPUC recently opened a proceeding to collect input on possible changes to the regulatory model from stakeholders including regulated utilities such as PGE.

Integrated Resource Plan—Unless the OPUC grants an extension, PGE is required to file an Integrated Resource Plan (IRP) with the OPUC within two years of its previous IRP acknowledgment order. 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 a portfolio of 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 2016 IRP, see “Integrated Resource Plans” in the Overview section in this 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 daily market index-based pricing, and Direct Access, whereby customers purchase their electricity from an Electricity Service Supplier (ESS). All commercial and industrial customers are eligible for Direct Access, under which the Company receives revenue only for the transmission and delivery of the energy to the ESS customers, while only certain large commercial and industrial customers may elect to be served by PGE on a daily market index-based price.

All non-residential retail customers have an option to be served by an ESS for a one-year period. 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.

The retail customer choice program does not have a material impact on PGE’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 PGE. 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. For further information regarding Direct Access deliveries, see “Customers and Demand” in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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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 ETO and other agencies for administration of these programs. The Company collected $53 million from customers for this charge in 2017, $50 million in 2016, and $51 million in 2015.

In addition to the public purpose charge, PGE also remits to the ETO amounts collected from its customers under an Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. This charge was 3.6%, 2.7%, and 2.4% of retail revenues for applicable customers in 2017, 2016, and 2015, respectively. Under the tariff, $66 million, $48 million, and $42 million were collected from eligible customers in 2017, 2016, and 2015, respectively.

Siting—Oregon’s Energy Facility Siting Council (EFSC) has regulatory and siting responsibility for large electric generating facilities, certain 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 the governor of Oregon, 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.”

Customers and Revenues

PGE generates revenue primarily through the sale and delivery of electricity to retail customers located exclusively in Oregon within a service area approved by the OPUC. In addition, the Company distributes power to commercial and industrial customers that choose to purchase their energy from an ESS. Although 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 applicable transition adjustments for these Direct Access customers. The Company conducts retail electric operations within its service territory and 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. Energy efficiency and conservation measures, as well as an increasing trend toward rooftop solar generation in recent years, also influence customer demand.

Retail Revenues

Retail customers are classified as residential, commercial, or industrial, with no single customer representing more than 6% of PGE’s total retail revenues or 9% of total retail deliveries. While the twenty largest commercial and industrial customers constituted 11% of total retail revenues in 2017, they represented nine different groups including high tech, paper manufacturing, governmental agencies, health services, and retailers.

PGE’s Retail revenues, retail energy deliveries, and average number of retail customers consist of the following:
 
Years Ended December 31,
 
2017
 
2016
 
2015
Retail revenues(1) (dollars in millions):
 
 
 
 
 
 
 
 
 
 
 
Residential
$
969

 
52
%
 
$
907

 
51
%
 
$
895

 
50
%
Commercial
669

 
36

 
665

 
37

 
662

 
37

Industrial
212

 
11

 
208

 
12

 
228

 
13

Subtotal
1,850

 
99

 
1,780

 
100

 
1,785

 
100

Other accrued (deferred) revenues, net
10

 
1

 
3

 

 
(10
)
 

Total retail revenues
$
1,860

 
100
%
 
$
1,783

 
100
%
 
$
1,775

 
100
%
Retail energy deliveries(2) (MWh in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
7,880

 
40
%
 
7,348

 
39
%
 
7,325

 
38
%
Commercial
7,555

 
38

 
7,457

 
39

 
7,511

 
39

Industrial
4,283

 
22

 
4,166

 
22

 
4,546

 
23

Total retail energy deliveries
19,718

 
100
%
 
18,971

 
100
%
 
19,382

 
100
%
Average number of retail customers:
 
 
 
 
 
 
 
 
 
 
 
Residential
762,211

 
88
%
 
752,365

 
88
%
 
742,467

 
88
%
Commercial
107,855

 
12

 
106,773

 
12

 
105,802

 
12

Industrial
267

 

 
258

 

 
255

 

Total
870,333

 
100
%
 
859,396

 
100
%
 
848,524

 
100
%
 
 
 
 
 
(1)
Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.
(2)
Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.


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Additional averages for retail customers are as follows:
 
Years Ended December 31,
 
2017
 
2016
 
2015
Residential
 
 
 
 
 
Revenue per customer (in dollars):
$
1,181

 
$
1,114

 
$
1,139

Usage per customer (in kilowatt hours):
10,338

 
9,766

 
9,866

Revenue per kilowatt hour (in cents):

11.42
¢
 

11.40
¢
 

11.55
¢
Commercial

 
 
 
 
Revenue per customer (in dollars):
$
6,142

 
$
6,166

 
$
6,254

Usage per customer (in kilowatt hours):
70,046

 
69,839

 
70,987

Revenue per kilowatt hour (in cents):

8.77
¢
 

8.83
¢
 

8.81
¢
Industrial
 
 
 
 
 
Revenue per customer (in dollars):
$
792,466

 
$
804,953

 
$
876,866

Usage per customer (in kilowatt hours):
16,041,461

 
16,146,371

 
17,485,281

Revenue per kilowatt hour (in cents):

4.94
¢
 

4.99
¢
 

5.01
¢
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, summer peaks have exceeded winter peaks and long-term load forecasts expect that trend to continue. Economic conditions can also affect residential demand; strong job growth and population growth in PGE’s service territory have led to increasing customer growth rates. 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 2017, total residential deliveries increased 7.2% compared with 2016. PGE witnessed a 1.3% increase in the average number of residential customers served during the year and average usage per customer increased 5.9% driven by favorable weather compared to the prior year. Temperatures in 2017 were characterized by both a cold heating season in the first quarter and a warm cooling season over the summer months, increasing residential energy deliveries. The year-over-year impact was intensified by unseasonably warm heating season temperatures seen in 2016, which decreased residential energy deliveries in that year. On a weather-adjusted basis, energy deliveries to residential customers decreased by 2.2% in 2017 when compared with 2016.

During 2016, residential customer count increased by 1.3%, however the summer cooling season was not as extreme as experienced in 2015 leading to a decrease in average use per customer of 1.0%. The overall result was that total residential energy deliveries increased 0.3% in 2016 compared with 2015. On a weather-adjusted basis, energy deliveries to residential customers increased by 1.4% in 2016 when compared with 2015.

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.


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The Company’s commercial customers are somewhat less susceptible to weather conditions than the residential customer, although weather does affect commercial demand to some extent. Economic conditions and fluctuations in total employment in the region can also lead to changes in energy demand from commercial customers. Energy efficiency measures also impact commercial demand, although the Company’s decoupling mechanism partially mitigates the financial effects of such measures.

In 2017, a 1.0% growth in the average number of commercial customers and a cold first quarter heating season drove a 1.3% increase in commercial deliveries compared with 2016. Weather-adjusted, deliveries to commercial customers decreased by 0.7% in 2017. Deliveries to several retail sectors decreased, including food and merchandise stores and office, finance, insurance, and real estate. These decreases were only partially offset by increases in the miscellaneous and other services sectors, which are driven by a strong construction cycle and data center growth. Energy efficiency continues to impact growth, and conservation and building codes and standards are likely reducing energy deliveries beyond the impact of energy efficiency programs.

Deliveries to commercial customers decreased 0.7% in 2016 compared with 2015, which was primarily due to unfavorable weather conditions and slightly lower demand from a few groups, including food stores, which were impacted by a series of mergers and bankruptcies, government and education, and irrigation and pumping load in 2016 due to the extremely dry conditions that existed in 2015. On a weather-adjusted basis, commercial deliveries for 2016 were comparable to 2015, while a 0.9% increase in the average number of commercial customers occurred.

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 2.8% in 2017 from 2016, reflecting increases across several manufacturing sectors, with the strongest increases to customers in high tech manufacturing and their suppliers. These increases were largely offset by the closure of a large paper manufacturing customer that ceased operations in October 2017.

The 8.4% decrease in 2016 from 2015 was largely due to another large paper manufacturing customer, to which PGE had delivered approximately 450 thousand Megawatt hours (MWh) annually, with corresponding revenues of approximately $20 million, having ceased operations in late 2015. Although the majority of power this customer purchased was under the Company’s daily market index-based price option, a portion was at cost of service prices. Adjusted for that one customer, industrial energy deliveries were 1.4% higher in 2016 than 2015 levels driven by continued, albeit slowed, increases in energy deliveries to 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, among other things, deferrals recorded under the RAC and the decoupling mechanism. For further information on these items, see “OPUC and Other 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 and wind conditions, and daily and seasonal retail demand. Wholesale revenues represented 5% of total revenues in each of the past three years.

The majority of PGE’s wholesale electricity sales is to utilities and power marketers and is predominantly short-term. The Company may choose to net its purchases and sales with the same counterparty rather than

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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 natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, excess fuel sales, pole contact rentals, and other electric services provided to customers. Other operating revenues have represented 2% of total revenues in each of the past three years.

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 electricity.

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
2017
4,558
 
700
2016
3,552
 
548
2015
3,461
 
785
15-year average
4,233
 
471
 
 
 
 
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 3,976 MW occurred in August 2017. The following table presents PGE’s average winter (defined as January, February, and December) and summer (defined as July, August, and September) loads for the periods presented, along with the corresponding peak load (in MWs) and month in which such peak occurred. As the table below illustrates, although the average winter loads continue to run higher than average summer loads, the Company has experienced its highest peak loads during summer in each of the past three years:
 
Winter Loads
 
Summer Loads
 
Average
 
Peak
 
Month
 
Average
 
Peak
 
Month
2017
2,698
 
3,727
 
January
 
2,380
 
3,976
 
August
2016
2,537
 
3,716
 
December
 
2,246
 
3,726
 
August
2015
2,509
 
3,255
 
December
 
2,390
 
3,914
 
July

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. 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. 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 seven thermal plants (natural gas- and coal-fired), two wind farms, and seven hydroelectric facilities. Capacity of the thermal plants represents the MW the plant is capable of generating under normal operating conditions, which is affected by ambient temperatures, net of electricity used in the operation of the plant. 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,
 
2017
 
2016
 
2015
 
Capacity
 
%
 
Capacity
 
%
 
Capacity
 
%
Generation:
 
 
 
 
 
 
 
 
 
 
 
Thermal:
 
 
 
 
 
 
 
 
 
 
 
Natural gas
1,831

 
39
%
 
1,805

 
38
%
 
1,371

 
30
%
Coal
814

 
17

 
814

 
17

 
814

 
17

Total thermal
2,645

 
56

 
2,619

 
55

 
2,185

 
47

Wind (1)
717

 
15

 
717

 
15

 
717

 
16

Hydro (2)
495

 
10

 
495

 
11

 
495

 
11

Total generation
3,857

 
81

 
3,831

 
81

 
3,397

 
74

Purchased power:
 
 
 
 
 
 
 
 
 
 
 
Long-term contracts:
 
 
 
 
 
 
 
 
 
 
 
Capacity/exchange
100

 
2

 
250

 
5

 
250

 
5

Hydro
531

 
12

 
534

 
12

 
592

 
13

Wind
39

 
1

 
39

 
1

 
39

 
1

Solar
13

 

 
13

 

 
13

 

Other
18

 

 
18

 

 
118

 
3

Total long-term contracts
701

 
15

 
854

 
18

 
1,012

 
22

Short-term contracts
185

 
4

 
45

 
1

 
200

 
4

Total purchased power
886

 
19

 
899

 
19

 
1,212

 
26

Total resource capacity
4,743

 
100
%
 
4,730

 
100
%
 
4,609

 
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 net capacity 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, 2017, 2016, and 2015, 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.

Thermal
The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty. These natural gas-fired generating plants provided approximately 33% of PGE’s total retail load requirement in 2017, 32% in 2016, and 25% in 2015.

The Company operates, and has a 90% ownership interest in Boardman 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 18% of the Company’s total retail load requirement in 2017, compared with 19% in 2016, and 22% in 2015. Boardman is scheduled to cease coal-fired operations at the end of 2020, and pursuant to Oregon Senate Bill 1547, PGE’s portion of Colstrip is scheduled to be fully depreciated by 2030, with the potential to utilize the output of the facility, in Oregon, until 2035. For additional information on Senate Bill 1547, see “Legal, Regulatory,

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and Environmental Matters” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
    
The thermal plants provide reliable power and capacity reserves for PGE’s customers. These resources have a combined capacity of 2,645 MW, representing approximately 69% of the net capacity of PGE’s generating portfolio. Thermal plant availability, excluding Colstrip, was 88% in 2017, 92% in 2016, and 89% in 2015, while Colstrip availability was 86% in 2017, compared with 85% in 2016 and 93% in 2015.

Wind
PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River Wind Farm (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, placed in service in December 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 9% of the Company’s total retail load requirement in 2017, 10% in 2016, and 9% in 2015. Availability for these resources was 96% in 2017, compared with 95% in 2016 and 97% in 2015. 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 495 MW, actual energy received is dependent upon river flows. Energy from these resources provided 9% of the Company’s total retail load requirement in 2017, 9% in 2016, and 8% in 2015, with availability of 95% in 2017, and 99% in both 2016 and in 2015. 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 455 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 December 31, 2021. The Tribes have a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. 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 provide NERC-required operating reserves. As of December 31, 2017, there were 59 sites with a total DSG capacity of 123 MW. Additional DSG projects are being pursued with a total goal of 135 MW online by the end of 2021.

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 twelve 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 Northwest Pipeline, an interstate natural gas pipeline operating

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between British Columbia and New Mexico. Currently, PGE transports natural 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 natural 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 as needed. The Company expects to utilize this resource when economic factors favor its use or in the event that natural gas supplies are interrupted. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PW1, PW2, and Beaver.

PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-mile pipeline, that will be designed to provide no-notice storage services to these PGE generating plants. Pursuant to the agreement, on September 30, 2016, PGE issued NW Natural a Notice To Proceed with construction of the expansion project, which NW Natural estimates will be completed during the winter of 2018-2019, at a cost of approximately $132 million.

Beaver has the capability to operate on fuel oil when it is economical or if the plant’s natural gas supply is interrupted. PGE had an approximate five day supply of ultra-low sulfur diesel fuel oil at the plant site as of December 31, 2017. 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.

To serve Coyote Springs and Carty, PGE has access to 119,500 Dth per day of firm natural gas transportation capacity on three pipeline systems accessing gas fields in Alberta, Canada. PGE believes that sufficient market supplies of natural gas are available for Coyote Springs and Carty for the foreseeable future, based on anticipated operation of the plants. 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, together with existing inventory, will provide coal sufficient for the anticipated operating needs for Boardman during 2018. The coal is obtained from surface mining operations in Wyoming and is delivered by rail under two separate transportation contracts which extend through 2020.

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 coal-fired operations of Boardman through 2020.

The Colstrip co-owners currently obtain coal to fuel the plant via conveyor belt from a mine that lies adjacent to the facility. The current contract for coal supply extends through 2019 and the Colstrip co-owners continue negotiations to extend the contract.

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 39 years and expire at varying dates through 2055.

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

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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 one contract that provides the Company with firm capacity to help meet peak loads. The agreement allows for up to 100 MW of seasonal peaking capacity during winter periods through February 2019.

Hydro—During 2017, the Company had three contracts that provided for the purchase of power generated from hydroelectric projects with an aggregate capacity of 56 MW and contract expirations between 2018 and 2032. 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. One contract representing 150 MW of capacity expires in 2018 and a 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 and capacity amounts may decline over time.

Confederated Tribes—PGE has a long-term agreement under which the Company purchases, at index prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides approximately 162 MW of net 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. In 2014, PGE entered into an agreement with the Tribes under which the Tribes have agreed to sell, on modified payment terms, their share of the energy generated from the Pelton/Round Butte hydroelectric project exclusively to the Company through 2024.

Wind—PGE has three contracts that provide for the purchase of renewable wind-generated electricity and extend to various dates between 2028 and 2035. The expected energy from these wind contracts differs from the nameplate capacity and is expected to approximate 39 MWa, dependent upon wind conditions.

Solar—PGE has three agreements that expire during 2036 and 2037 to purchase power generated from photovoltaic solar projects, which 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. The expected energy from these solar resources will vary from the nameplate capacity due to varying solar conditions.

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 requirements.

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.”

PGE began participating in the western EIM on October 1, 2017. As a market participant in the western EIM PGE allows certain of its generating plants to receive automated dispatch signals from the CAISO that allows for load balancing with other western EIM participants in five-minute intervals. The Company expects such load balancing will help integrate more renewable energy into the grid by better matching the variable output of renewable resources. Additionally, participation in the western EIM gives PGE access to the lowest-cost energy available in

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the region to meet changes in real-time energy loads and short-term variations in customer demand. The Company expects that participation in the western EIM will reduce costs for PGE customers.

Future Energy Resource Strategy

PGE’s IRP outlines the Company’s plan to meet future customer demand and describes PGE’s future energy supply strategy. For a detailed discussion of the IRPs, see “Integrated Resource Plan” within the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 2017, PGE delivered approximately 23 million MWh in its balancing authority area through 1,250 circuit miles of transmission lines operating at or above 115 kilovolts (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 Bonneville Power Administration (BPA) to transmit a significant amount of the Company’s generation to serve 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 generally 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 federal and state lands primarily under franchises, easements or other rights that are generally subject to termination;

Under or over private property primarily pursuant to easements obtained 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, 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.

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


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

To maintain compliance with the various air quality standards, PGE manages its air emissions at its thermal generating plants 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 emissions controls and the continued use of low sulfur fuel, are anticipated to be sufficient to permit the Company to meet its air emissions compliance requirements.

DEQ has initiated a rulemaking to overhaul its air toxic permit program for industrial sources. DEQ placed proposed rules on public notice and has accepted comments. PGE is evaluating potential impacts the proposed regulations could have on its thermal generating plants.

Climate Change—In August 2015, the EPA released a rule, which it called the “Clean Power Plan” (CPP). Under the rule, each state would have to reduce carbon dioxide emissions from its power sector on a state-wide basis by an amount specified by the EPA. The rule was intended to result in a reduction of carbon dioxide emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030.

In February 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP, pending the resolution of legal challenges to the rule. On March 28, 2017, the President of the United States issued an Executive Order that directed various agencies to review existing regulations that potentially burden the development of the nation’s energy resources. The Department of Justice (DOJ) filed requests with the U.S. Court of Appeals for the D.C. Circuit (DC Circuit Court) to suspend and hold in abeyance the current litigation over the CPP in light of the Executive Order while EPA reviews the rule and determines its next steps. The DC Circuit Court granted the requests.

In October 2017, the EPA published in the Federal Register for public comment a proposed CPP repeal rule, in which it outlined the rationale for repealing the CPP. The public comment period for the repeal rule is open until April 26, 2018. Additionally, on December 28, 2017, the EPA published in the Federal Register an Advance Notice of Proposed Rulemaking (ANPR) seeking public comment on specific topics for the EPA to consider in developing any subsequent replacement rule. Public comment on the ANPR is open until February 26, 2018.

The Company cannot predict the impact of the stay, the ultimate outcome of the legal challenges and the regulatory process of the EPA, or whether Oregon will continue to develop an implementation plan in light of recent activities. The Company continues to monitor the developments around the potential new rule.


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The State of Oregon established a non-binding policy guideline that sets a goal to reduce GHG emissions to 10% below 1990 levels by 2020 and at least 75% below 1990 levels by 2050. Although the guideline does not mandate reductions by any specific entity, nor include penalties for failure to meet the goal, the Company is required to report to the DEQ the amount of GHG emissions produced along with the total amount of energy produced or purchased by PGE for consumption in Oregon.

State of Oregon legislators have proposed Senate Bill 1070 referred to as the Clean Energy Jobs Bill in an effort to reduce greenhouse gas emissions that contribute to climate change through a statewide cap and trade program. This proposal is under consideration in the 35-day legislative session that began in early February. The program would set a statewide cap on greenhouse gas emissions that is reduced over time and would require about 100 companies, including PGE, to acquire permits for the greenhouse gas emissions they produce. PGE continues to monitor the status of this proposed legislation.

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, Carty, and the Company’s ownership interest in coal-fired facilities, Boardman and Colstrip, provided, in total, approximately 69% of the Company’s net generating capacity at December 31, 2017. 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.

Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill 1547, effective March 8, 2016. The legislation prevents large utilities from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030. For more information regarding the OCEP, and its impact on PGE, see the “Legal, Regulatory, and Environmental Matters” section of Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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. The Company is subject to litigation with regard to water quality conditions on the Deschutes River. For additional information on this litigation see “Deschutes River Alliance Clean Water Act Claims” in see Note 17, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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 continue to have operational impacts on many of the region’s hydroelectric projects. PGE purchases power in the wholesale market, some of which is sourced from other affected hydroelectric facilities in the Pacific Northwest, to serve its retail load requirements. In addition, the Company 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 (USFWS) and the National Marine Fisheries Service under their authority granted in the ESA and the FPA. 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 a total of 50 MWa of output from those facilities included as part of the Company’s renewable energy portfolio used

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to meet the requirements of the RPS. Conditions required with the operating licenses are expected to result in a minor reduction in power production and continued capital spending to modify the facilities to enhance fish passage and survival.

Avian Protection—Various statutes, including the Migratory Bird Treaty Act and Bald and Golden Eagle Protection Act, contain provisions for civil, criminal, and administrative penalties resulting from the unauthorized take of migratory birds and eagles. Because PGE operates facilities that can pose risks to a variety of such birds, the Company developed an avian protection plan to help address and reduce risks to bird species that may be affected by Company operations. PGE has implemented such a plan for its transmission, distribution, and thermal generation facilities and continues to finalize similar plans, for its wind generation facilities. In 2015, PGE submitted an application, along with a draft Eagle Conservation Plan, to the USFWS, pertaining to Biglow Canyon that would address the incidental take of eagles, and submitted a similar draft application for Tucannon River in 2017.

Hazardous Material

PGE has a comprehensive program to comply with requirements of both federal and state regulations related to the storage, handling, and disposal of hazardous materials. The handling and disposal of hazardous materials from Company facilities is subject to regulation under the federal Resource Conservation and Recovery Act (RCRA). In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, are regulated under the federal Toxic Substances Control Act.

The generation of electricity at Boardman and Colstrip produces a by-product known as coal combustion residuals (CCRs), which have historically not been considered hazardous materials under the RCRA. In December 2014, the EPA signed a final rule, which became effective in October 2015, to regulate CCRs under the RCRA. Boardman produces dry CCRs that have historically been disposed at an on-site landfill, which is permitted and regulated by the State of Oregon under requirements similar to the CCR rule. PGE has determined that it will continue use of the on-site landfill in compliance with the CCR rule, and the Company believes the CCR rule will not have a material effect on operations at Boardman. Based on information from the Colstrip operator, the CCR rule will have an effect on operations at Colstrip, which produces wet CCRs, and as a result, in 2015 PGE updated its Asset Retirement Obligation and adjusted its cost assumptions, accordingly. For further information, see Note 2, Summary of Significant Accounting Policies and “Utility plant” in Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

An investigation by the EPA that began in 1997 of a segment of the Willamette River in Oregon known as Portland Harbor, has 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. The EPA has listed PGE among the more than one hundred Potentially Responsible Parties (PRPs) in this matter, as PGE has historically owned or operated property near the river.

On January 6, 2017, the EPA issued a Record of Decision (ROD), which outlined the EPA’s selected remediation alternative to clean-up Portland Harbor. The estimated total cost of the remedy had a discounted present value of $1.05 billion with an estimated remediation period of 13 years. PGE is participating in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Certain PRPs have entered an agreement with the EPA to conduct further sampling in the river in an attempt to refine the remediation needed. PGE is not among those parties. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including a final allocation methodology and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability.


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In July 2016, the Company filed a deferral application with the OPUC seeking the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test. For additional information regarding the EPA action on Portland Harbor, see Note 17, 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 2034. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

ITEM 1A.     RISK FACTORS.

Certain risks and uncertainties that could have a significant impact on PGE’s business, financial condition, results of operations, or cash flows, or that may cause the Company’s actual results to vary 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.

PGE attempts to manage its costs at levels consistent with the OPUC approved prices. 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.


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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 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. 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 winter seasons or cooler-than-normal summer seasons 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. 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.


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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 supplements 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.

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 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 S&P Global Ratings (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 remediation efforts related to the Portland Harbor site and the Carty related litigation and cost recovery, which 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 17, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


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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.

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 envisioned.

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.

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 GHG 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 GHG emissions from the Company’s fossil fuel-fired generation facilities. Compliance with any GHG 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 GHG 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.


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Changes in tax laws may have an adverse impact on the Company’s financial position, results of operations, and cash flows.
PGE makes judgments and interpretations about the application of tax law when determining the provision for taxes. Such judgments include the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. Additionally, treatment of tax benefits and costs for ratemaking purposes could be different than what the Company anticipates or requests from the state regulatory commission, which could have a negative effect on the Company’s financial condition and results of operations.
PGE owns and operates wind generating facilities, which generate Production Tax Credits (PTCs) that PGE uses to reduce its federal tax obligations. The amount of PTCs earned depends on the level of electricity output generated and the applicable tax credit rate. A variety of operating and economic parameters, including adverse weather conditions and equipment reliability, could significantly reduce the PTCs generated by the Company’s wind facilities resulting in a material adverse impact on PGE’s financial condition and results of operations. These PTCs generate tax credit carryforwards that the Company plans to utilize in the future to reduce income tax obligations. If PGE cannot generate enough taxable income in the future to utilize all of the tax credit carryforwards before the credits expire, the Company may incur material charges to earnings.
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 a syndicated unsecured revolving credit facility with several banks for an aggregate amount of $500 million. The revolving credit facility provides a primary source of liquidity and may be used to supplement operating cash flow and as backup for commercial paper borrowings. The revolving credit facility represents 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 the credit facility. 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 facility.

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.


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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.

Development of alternative technologies may negatively impact the value of 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.

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 and distribution 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

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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.

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.
 
ITEM 1B.     UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.     PROPERTIES.

PGE’s principal property, plant, and equipment are generally 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.


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Generating Facilities

The following are generating facilities owned by PGE as of December 31, 2017:
Facility
 
Location
 
Net
Capacity (1)
 
Wholly-owned:
 
 
 
 
 
Natural Gas/Oil:
 
 
 
 
 
Beaver
 
Clatskanie, Oregon
 
509

MW
Carty
 
Boardman, Oregon
 
437

 
Port Westward Unit 1 (PW1)
 
Clatskanie, Oregon
 
411

 
Coyote Springs
 
Boardman, Oregon
 
249

 
Port Westward Unit 2 (PW2)
 
Clatskanie, Oregon
 
225

 
Wind:
 
 
 
 
 
Biglow Canyon
 
Sherman County, Oregon
 
450

 
Tucannon River
 
Columbia County, Washington
 
267

 
Hydro:
 
 
 
 
 
North Fork
 
Clackamas River
 
58

 
Faraday
 
Clackamas River
 
46

 
Oak Grove
 
Clackamas River
 
45

  
River Mill
 
Clackamas River
 
25

  
T.W. Sullivan
 
Willamette River
 
18

  
Jointly-owned (2):
 
 
 
 
 
Coal:
 
 
 
 
 
Boardman (3)
 
Boardman, Oregon
 
518

  
Colstrip (4)
 
Colstrip, Montana
 
296

  
Hydro:
 
 
 
 
 
Round Butte (5)
 
Deschutes River
 
230

 
Pelton (5)
 
Deschutes River
 
73

  
Net capacity
 
 
 
3,857

MW 
 
 
 
 
 
 
 
 
 
 
 
(1)
Represents net capacity of generating unit as demonstrated by actual operating or test experience, net of electricity used in the operation of a given facility. For wind-powered generating facilities, nameplate ratings are used in place of net capacity. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer.
(2)
Reflects PGE’s ownership share.
(3)
PGE operates Boardman and has a 90% ownership interest.
(4)
Talen Montana, LLC operates Colstrip and PGE has a 20% ownership interest.
(5)
PGE operates Pelton and Round Butte and has a 66.67% ownership interest.

PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the FPA. 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, 2017, PGE owned an electric transmission system consisting of 1,250 circuit miles as follows: 287 circuit miles of 500 kV line; 402 circuit miles of 230 kV line; and 561 miles of 115 kV line. The Company also has 27,457 circuit miles of distribution lines that deliver electricity to its customers.

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The Company also has an ownership interest in, and capacity on, the following:
Approximately 15% of the Colstrip Project Transmission facilities from Colstrip to BPA’s transmission system; and
Approximately 20% of the Pacific Northwest Intertie, a 4,800 MW transmission facility between the John Day Substation near the Columbia River in northern Oregon, and Malin, 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 3,490 MW of firm BPA transmission on BPA’s system to PGE’s service territory in Oregon; and
150 MW of firm BPA transmission from the Mid-Columbia projects in Washington to the northern end of the Pacific Northwest AC Intertie, near John Day, Oregon, 5 MW to Tucannon River, and 5 MW to Biglow Canyon.

ITEM 3.     LEGAL PROCEEDINGS.

See Note 17, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data,” for information regarding legal proceedings.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

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 2, 2018, there were 752 holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $41.40 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
2017
 
 
 
 
 
 
Fourth Quarter
 
$
50.11

 
$
44.70

 
$
0.34

Third Quarter
 
48.22

 
44.20

 
0.34

Second Quarter
 
48.06

 
44.04

 
0.34

First Quarter
 
46.05

 
42.41

 
0.32

2016
 
 
 
 
 
 
Fourth Quarter
 
$
44.32

 
$
40.28

 
$
0.32

Third Quarter
 
45.21

 
41.51

 
0.32

Second Quarter
 
44.12

 
37.77

 
0.32

First Quarter
 
40.48

 
35.27

 
0.30

While PGE expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant and may include, but are not limited to, PGE’s results of

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operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

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,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In millions, except per share amounts)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues, net
$
2,009

 
$
1,923

 
$
1,898

 
$
1,900

 
$
1,810

Income from operations
376

 
333

 
309

 
293

 
206

Net income
187

 
193

 
172

 
174

 
104

Net income attributable to Portland General Electric Company
187

 
193

 
172

 
175

 
105

Earnings per share—basic
2.10

 
2.17

 
2.05

 
2.24

 
1.36

Earnings per share—diluted
2.10

 
2.16

 
2.04

 
2.18

 
1.35

Dividends declared per common share
1.340

 
1.260

 
1.180

 
1.115

 
1.095

Statement of Cash Flows Data:
 
 
 
 
 
 
 
 
 
Capital expenditures
514

 
584

 
598

 
1,007

 
656

 
As of December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars in millions)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
7,838

 
$
7,527

 
$
7,210

 
$
7,030

 
$
6,090

Total long-term debt
2,426

 
2,350

 
2,193

 
2,489

 
1,905

Total capital lease obligations
51

 
54

 

 

 

Total Portland General Electric Company shareholders’ equity
2,416

 
2,344

 
2,258

 
1,911

 
1,819

Common equity ratio
49.4
%
 
49.4
%
 
50.7
%
 
43.4
%
 
48.9
%
 
 
 
 
 

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 the Company to have a reasonable basis including, but

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not limited to, management’s examination of historical operating trends and data contained either in internal records or 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 17, 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, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;
the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of 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 power and natural gas purchase agreements;
changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;
capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of 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;
future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such 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, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
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;
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;

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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;
cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and a significant number of employees approaching retirement;
new federal, state, and local laws that could have adverse effects on operating results, including the potential impact of the U.S. Tax Cuts and Jobs Act;
political and economic conditions;
natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;
changes in 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 or 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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.

PGE is responding proactively to an evolving landscape of customer expectations, technology changes, and regulatory frameworks by focusing efforts on four strategic initiatives: 1) delivering exceptional customer service, 2) investing in a reliable and clean energy future, 3) building a smarter, more resilient grid and 4) pursuing excellence in its work.

Delivering exceptional customer service requires PGE to be responsive to the changing expectations of our growing customer base. PGE’s IRP, 2019 GRC, customer information system, and planned infrastructure investments are part of a strategy focused on providing power supply, distribution reliability, and customer service that meet these expectations.

PGE’s investments in a reliable and clean energy future are a key element of the IRP, which will require compliance with statutory renewable standards and consideration of state and local government initiatives to decarbonize the local economy.

Building a smarter, more resilient grid is essential to affordably delivering the clean energy future that customers want. This requires embracing new technologies, modernizing the Company’s existing infrastructure, and implementing a new customer information system to create a foundation to integrate emerging technologies. PGE’s capital requirements contemplate the impact of making these improvements to its transmission, distribution, and information technology infrastructure.


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The discussion that follows in this MD&A more fully describes these and other operating activities and provides additional information related to the Company’s legal, regulatory, and environmental matters, results of operations, and liquidity and financing.

Integrated Resource Plans—PGE’s 2016 IRP (2016 IRP) was filed with the OPUC in November 2016 and outlines the Company’s plan to meet future customer demand and describes PGE’s future energy supply strategy. The 2016 IRP addressed acquisition of additional resources to meet RPS requirements and replace energy and capacity from Boardman, which will cease coal-fired operations at the end of 2020. Further actions identified through 2021 are expected to offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities. The 2016 IRP is available on PGE’s website. All portfolios analyzed in the 2016 IRP pursued:
Compliance with the RPS through 2050;
Inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and
Retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.

The 2016 IRP also considered the effects of a law referred to as the Oregon Clean Electricity and Coal Transition Plan (OCEP), which, among other things, increased the RPS requirements for 2025 and future years. For further information on the OCEP, see the “Legal, Regulatory, and Environmental” section of the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

In August 2017, the OPUC acknowledged PGE’s 2016 IRP and the following primary action plan items:
Meet additional capacity needs of 561 MW, of which 240 MW must be dispatchable, in 2021;
Acquire a total of 135 MWa of cost-effective energy efficiency;
Acquire at least 77 MW (winter) and 69 MW (summer) demand response through 2020 and 16 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies;
Deploy 1 MWa of conservation voltage reduction through 2020;
Submit one or more energy storage proposals in accordance with Oregon House Bill 2193, by January 1, 2018; and
Perform various research and studies related to flexible capacity and curtailment metrics, customer insights, decarbonization, risks associated with Direct Access, treatment of market capacity, access to resources from Montana, and improvements to load forecasting.

The State of Oregon continues to promote a decarbonized economy that initially began with the decision to cease coal-fired generation at Boardman by the end of 2020. As part of the 2016 IRP, the Company put forth a variety of scenarios in which it envisioned replacement of the output of Boardman. As a result of the public review process, the Company has pursued bilateral contract arrangements with capacity providers in the region. Additional contract requests from Qualifying Facilities have also reduced the need for the Company to build new generation.

Capacity—In August 2017, the Company filed with the OPUC a request for a waiver of the OPUC’s competitive bidding guidelines. In that filing, PGE requested a waiver to procure capacity to partially satisfy PGE’s capacity needs. The OPUC approved the waiver request in December 2017 and PGE has now finalized bilateral power purchase agreements, summarized as follows:
200 MW of annual capacity with five-year terms beginning January 1, 2021; and
100 MW of seasonal peak capacity during the summer and winter seasons with a term that would begin July 1, 2019 and continue through February 29, 2024.

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Renewables—The OPUC, in its August 2017 acknowledgement, asked the Company to work with OPUC staff and parties to prepare and submit a revised proposal for acquiring renewable resources. In the fourth quarter of 2017, PGE submitted to the OPUC an addendum to the 2016 IRP, which proposed a 100 MWa procurement target for the addition of RPS compliant renewable resources and included a request for the issuance of an RFP for renewable resources. In December 2017, the OPUC acknowledged the addendum and, as a result, the Company plans to move forward with the procurement of additional renewable resources during 2018. The RFP process will include oversight by an independent evaluator and review by the OPUC.

Since issuing the 2016 IRP, PGE has identified a potential benchmark wind resource that could have a nameplate capacity of up to 300 MW that would meet the acknowledged need for renewable resources and qualify for the federal production tax credit. The Company continues to explore this option and should due diligence be completed and agreements reached, the potential benchmark resource would be submitted into the RFP and considered along with other renewable resource proposals.

Energy Storage—Pursuant to OPUC acknowledgment of the 2016 IRP, and in accordance with Oregon House Bill 2193, PGE filed an energy storage proposal in November 2017. The proposal calls for 39 MW of storage to be developed over the next several years at various locations across the grid, at a cost of $50 to $100 million.

IRP Update—The Company plans to file an update to its 2016 IRP in March 2018. As part of the IRP Update filing, PGE’s capacity need will have been updated to reflect the bilateral capacity contracts, changes to load forecast, and additional Qualified Facilities executed contracts. The remaining capacity need of approximately 100 MW is expected to be filled through contributions from the acquisition of energy storage, incremental renewables procured through an RFP, contracts with Qualifying Facilities, and market purchases.

General Rate Cases—On February 15, 2018, PGE filed with the OPUC a general rate case based on a 2019 test year (2019 GRC). After adjusting for the effects of tax reform, the Company’s filing requests an approximate 4.8% overall increase relative to currently approved prices and would result in an $86 million increase in the annual revenue requirement. The filing seeks recovery of costs related to better serving customers and building a smarter, more resilient system and includes the expectation of higher net variable power costs in 2019.

Primary elements include:

A new customer information system to provide better, more secure service;
Replacement and upgrades to equipment to ensure system safety and reliability;
Equipping substations with technology to address potential outages and shorten those that do occur;
Strengthening safeguards that protect against cyber attacks and other potential threats; and
Adding infrastructure to support rapid growth in the region.

The net increase in annual revenue requirement is based upon:
A capital structure of 50% debt and 50% equity;
A return on equity of 9.50%
A cost of capital of 7.31%, and
A rate base of $4.86 billion.

Regulatory review of the 2019 GRC will continue throughout 2018, with a final order targeted to be issued by the OPUC by December 2018. New customer prices are expected to become effective January 1, 2019.

On January 1, 2018, new customer prices went into effect pursuant to the OPUC order issued on PGE’s 2018 GRC, which was based on a 2018 test year and included recovery of costs related to upgrades to PGE’s transmission and

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distribution system, investments in strengthening and safeguarding the grid, and base business costs. The OPUC authorized a $16 million increase in annual revenues, representing an approximate 1% overall increase in customer prices. In addition, the order approved a capital structure of 50% debt and 50% equity, return on equity of 9.50%, cost of capital of 7.35%, and rate base of $4.5 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.

Tax Reform—On December 22, 2017, the Tax Cuts and Jobs Act (the TCJA) was enacted and signed into law by the President of the United States with substantially all of the provisions of the TCJA having an effective date of January 1, 2018. Among other provisions, the reduction of the federal corporate tax rate from 35% to 21%, which required the Company to remeasure its existing deferred income tax balances as of December 31, 2017, had the most impact on PGE’s financial condition. As a result of the Company’s remeasurement, net deferred tax liabilities on the Company’s consolidated balance sheets were reduced by $340 million.

Of the remeasurement amount, $357 million has been deferred as a regulatory liability and is expected to be refunded to customers over time. These deferred tax items relate primarily to Electric utility plant and other rate base items subject to tax normalization rules that require the benefits to be passed on to customers through future prices over the remaining useful life of the underlying assets for which the deferred income taxes relate. The Company plans to use the average rate assumption method to account for the refund to customers. A portion of the remeasurement is not subject to tax normalization rules and will be amortized over time.
The remaining and offsetting remeasurement amount of $17 million represents a reduction to net deferred tax assets related to other business items, primarily comprised of deferred tax assets related to the Company’s non-qualified employee benefit plans. The Company has recorded a $17 million charge to the results of operations, reflected as an increase in Income tax expense in the Company’s consolidated statements of income for the period ended December 31, 2017.
As a result of the TCJA, PGE expects to incur lower income tax expense in 2018 than what was estimated in setting customer prices in the Company’s 2018 GRC. In addition to the effects of the 2017 remeasurement of deferred income taxes, PGE has proposed to defer and refund the 2018 expected net benefits of the TCJA under a deferral application filed with the OPUC on December 29, 2017. If approved as requested, any refund to customers of the net benefits associated with the TCJA in 2018 would be subject to an earnings test and limited by the Company’s previously authorized regulated return on equity.
Other specific provisions in the TCJA that relate to regulated public utilities include general allowance for the continued deductibility of interest expense, and continued normalization requirements for accelerated depreciation benefits. These other provisions are not expected to have a material impact on the Company’s financial condition, results of operation, or cash flows.
For more information regarding the Company’s proposed deferral application, see the “Legal, Regulatory, and Environmental Matters” Section of this Item 7.

Capital Requirements and Financing—PGE’s capital requirements amounted to $511 million for 2017, with $49 million related to the customer information system, excluding AFDC. The remainder of the 2017 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 and construction. In addition, the Company repaid $150 million of debt that was due to mature in November 2017. During 2017, the combination of cash from operations in the amount of $597 million and proceeds from issuances of FMBs in the amount of $225 million funded the Company’s capital requirements.

Capital requirements in 2018 are expected to approximate $551 million. PGE plans to fund the 2018 capital requirements with cash from operations during 2018, which is expected to range from $575 million to $625 million and the issuance of debt securities of up to $100 million. For further information, see the “Liquidity” and the “Debt and Equity Financings” sections of this Item 7.

Operating Activities—PGE, as a vertically-integrated electric utility, engages in the generation, transmission, distribution, and sale of electricity to retail customers within in its approved service territory in the State of Oregon. In addition, the Company purchases and sells electricity in the wholesale market to meet its retail load requirements. In 2017, the Company began participation in the western EIM, which the Company expects will help integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess

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gas back into the wholesale market. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers.

The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has been a winter-peaking utility that typically experiences its highest retail energy demand during the winter heating season. Increased use of air conditioning in the Company’s service territory, however, has caused the summer peaks to increase in recent years and the long-term load forecasts indicate summer peaks will exceed winter peaks. PGE’s all time summer peak load occurred during August 2017 while the all-time winter peak load was experienced in December 1998. Retail customer price changes and usage patterns, which can be affected by the economy, also have an impact on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations.

Customers and Demand—In 2017, retail energy deliveries increased 3.9% from 2016. All retail categories contributed to the increase, which was led by residential deliveries, which are most sensitive to fluctuations in weather. For 2017 and 2016, the average number of retail customers and deliveries, by customer type, were as follows:
 
2017
 
2016
 
Increase/
(Decrease)
in Energy
Deliveries
 
Average
Number of
Customers
 
Energy
Deliveries *
 
Average
Number of
Customers
 
Energy
Deliveries *
 
Residential
762,211

 
7,880

 
752,365

 
7,348

 
7.2
 %
 
 
 
 
 
 
 
 
 
 
Commercial (PGE sales only)
107,364

 
6,932

 
106,460

 
6,932

 
 %
     Direct Access
491

 
623

 
313

 
525

 
18.7
 %
Total Commercial
107,855

 
7,555

 
106,773

 
7,457

 
1.3
 %
 
 
 
 
 
 
 
 
 
 
Industrial (PGE sales only)
199

 
2,943

 
195

 
2,968

 
(0.8
)%
     Direct Access
68

 
1,340

 
63

 
1,198

 
11.9
 %
Total Industrial
267

 
4,283

 
258

 
4,166

 
2.8
 %
 
 
 
 
 
 
 
 
 
 
Total (PGE sales only)
869,774

 
17,755

 
859,020

 
17,248

 
2.9
 %
     Total Direct Access
559

 
1,963

 
376

 
1,723

 
13.9
 %
Total
870,333

 
19,718

 
859,396

 
18,971

 
3.9
 %
 
 
 
 
 
 *
In thousands of MWh.

In 2017, heating degree-days, an indication of electricity use for heating, were 28% greater than 2016, although only 8% above the 15-year average. Heating degree-days in the first quarter of 2017 were unusually high, in contrast to the unseasonably warm weather that occurred in the first quarter of 2016. While heating degree-days totaled near average for the last three quarters of 2017, they continued to be considerably more than experienced during 2016. Cooling degree-days, a similar indication of the extent to which customers are likely to have used electricity for cooling, were 28% above the 2016 level and 48% above the 15-year normal.

Residential energy deliveries were 7.2% higher in 2017 than 2016 due to the effects of cooler temperatures during the winter season and warmer temperatures during the summer cooling season, as well as customer growth of 1.3%. See “Revenues” in the 2017 Compared to 2016 section of Results of Operations within this Item 7, for further information on heating and cooling degree days.

Commercial deliveries also increased by 1.3% as a result of favorable weather conditions and a 1.0 % increase in the average number of customers.

The 2.8% increase in industrial energy deliveries is due to continued increases in energy deliveries to the high-tech manufacturing sector. These increases were partially offset by the closure of a large paper customer in October 2017.

On a weather-adjusted basis, total retail deliveries decreased 0.6% from 2016 reflecting a 2.2% decline in residential deliveries, as residential usage per customer continues a pattern of long-term decline, a 0.7% reduction in commercial deliveries and an additional day in 2016 due to the leap year.

ESSs supplied Direct Access customers with energy representing 10% of the Company’s total retail energy deliveries during 2017 and 9% for 2016. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 13% of the Company’s total retail energy deliveries for 2017, and 14% in 2016.

Energy efficiency and conservation efforts by retail customers influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated through the decoupling mechanism, which 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. The mechanism provides for collection from (or refund to) customers if

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weather-adjusted use per customer is less (or more) than the projected baseline set in the Company’s most recent approved general rate case. See “Legal, Regulatory, and Environmental” in this Overview section of Item 7, for further information on the decoupling mechanism.

For 2017, PGE recorded an estimated collection of $13 million under the mechanism as weather-adjusted energy use per customer was less than that estimated and approved in the Company’s 2016 GRC. A final determination of the 2017 estimate will be made by the OPUC through a public filing and review in 2018. Any resulting collection from customers is expected to begin January 1, 2019. The $3 million estimated collection for the 2016 year began January 1, 2018. For 2015, amortization of the net $9 million refund amount occurred in 2017 following a final determination of the amount by the OPUC.

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 90% for the year ended December 31, 2017, and 93% for 2016, and 2015, with the availability of Colstrip, which PGE does not operate, approximating 86%, 85%, and 93%, respectively. During the year ended December 31, 2017, the Company’s generating plants provided approximately 69% of its retail load requirement compared to 70% in 2016 and 65% in 2015.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increased 8% in 2017 compared to 2016, due to more favorable hydro conditions in 2017. These resources provided 18% of the Company’s retail load requirement for 2017, compared with 17% for 2016 and 16% for 2015. Energy received from these sources exceeded projected levels included in PGE’s AUT by 6% in 2017, did not materially differ from the projections included in the Company’s AUT in 2016, and fell short of projections by 7% in 2015. 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 hydroelectric conditions represent the level of energy forecasted to be received from hydroelectric resources for the year and is based on average regional hydro conditions over a recent 30-year period. Any shortfall is generally replaced with power from higher cost sources, while any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources. See “Purchased power and fuel” in the 2017 Compared to 2016 section of Results of Operations in this Item 7, for further detail on regional hydro results.

Energy expected to be received from wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT based on historical generation. 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 18% in 2017, 7% in 2016, and 15% in 2015. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation shortfalls, production tax credits have not materialized to the extent contemplated in the Company’s prices.

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), as established under the AUT, 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 beyond the deadband to be collected from or refunded to

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customers, respectively, subject to a regulated earnings test. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2017, 2016, and 2015:

For 2017, actual NVPC was above baseline NVPC by $15 million, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2017. A final determination regarding the 2017 PCAM results will be made by the OPUC through a public filing and review in 2018.

For 2016, actual NVPC was below baseline NVPC by $10 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2016. A final determination regarding the 2016 PCAM results was made by the OPUC through a public filing and review in 2017, which confirmed no refund to customers pursuant to the PCAM for 2016.

For 2015, actual NVPC was below baseline NVPC by $3 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2015. A final determination regarding the 2015 PCAM results was made by the OPUC through a public filing and review in 2016, which confirmed no refund to customers pursuant to the PCAM for 2015.

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

Western EIM—The Company’s participation in the western EIM began October 1, 2017. As a market participant in the western EIM, PGE allows certain of its generating plants to receive automated dispatch signals from the CAISO that allows for load balancing with other western EIM participants in five-minute intervals. The Company expects such load balancing will help integrate more renewable energy into the grid by better matching the variable output of renewable resources. Shortly after the entry into the EIM, PGE began to self-integrate its Company-owned wind generation. Additionally, participation in the western EIM gives PGE access to the lowest-cost energy available in the region to meet changes in real-time energy loads and short-term variations in customer demand. For further information on the Company’s participation in the western EIM, see “Federal Regulation” in the Regulatory section of Item 1.—“Business.”

Gas Storage—PGE has contractual access to natural gas storage in Mist, Oregon from which it can draw in the event that natural gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the construction of a new reservoir, compressor station, and 13-miles of pipeline, which will collectively be designed to provide no-notice storage services to these PGE generating plants. NW Natural estimates construction will be completed during the winter of 2018-2019, at a cost of approximately $132 million. Due to the level of PGE’s involvement during the construction period, the Company is deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE has recorded $108 million to construction work-in-progress (CWIP) and a corresponding liability for the same amount to Other noncurrent liabilities in the condensed consolidated balance sheets as of December 31, 2017. Upon completion of the facility, PGE will assess whether the assets and liabilities qualify as a successful sale-leaseback transaction in which the asset and liability are removed and accounted for as either a capital or operating lease.

Carty—Pursuant to the final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, the Company was authorized to include in customer prices the capital costs for Carty of up to $514 million, as well as Carty’s operating costs, effective August 1, 2016, following the placement of the plant into service on July 29, 2016. As the final construction cost, $637 million, exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. This higher cost of service is primarily due to depreciation and amortization on the incremental capital cost, interest expense, and legal expense, all of which totaled $14 million for the year ended December 31, 2017 and is estimated to be approximately $14 million for the full year 2018.


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On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent GRC proceeding. The Company has requested the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost of service will be recognized in the Company’s results of operations. Any amounts approved by the OPUC for recovery under the deferral filing will be recognized in earnings in the period of such approval.

For additional details regarding various legal and regulatory proceedings related to Carty, see Note 17, Contingencies, in the Notes to the Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

An ongoing environmental investigation of Portland Harbor; and
The termination of the Construction Agreement for Carty and recovery of related incremental costs.

For additional information regarding the above and other matters, see Note 17, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Clean Power Plan—In August 2015, the EPA released a final rule, which it calls the Clean Power Plan (CPP). Under the final 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 rule established state-specific goals and is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030. On February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP pending the resolution of legal challenges to the rule. The EPA has proposed repealing the CPP and has stated that the agency will put forward a replacement rule. For additional information regarding this new rule, see “Air Quality” in the Environmental Matters section of Item 1.—“Business.”

Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill 1547, effective in March 2016, a law referred to as the OCEP. The legislation has impacted PGE in several ways, including preventing the Company from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for PGE’s output from the Colstrip facility). As a result, in October 2016, the Company filed a tariff request, and the OPUC approved the request, to incorporate in customer prices, on January 1, 2017, the approximate $6 million annual effect of accelerating recovery of the Colstrip facility from 2042 to 2030, as required under the legislation.

Future effects under the new law include:
an increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
a limitation on the life of renewable energy certificates (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022; and
an allowance for energy storage costs in its renewable adjustment clause mechanism (RAC) filings.

The Company has evaluated the potential impacts and incorporated the effects of the legislation into its 2016 IRP. For further information on the OCEP, see “State of Oregon Regulation” in the Regulation section of Item 1.—“Business.”


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Senate Bill 978—The State of Oregon legislature passed a bill in its 2017 session referred to as SB 978, which directs the OPUC to investigate and provide a report to the legislature by September 15, 2018 on how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. PGE is actively working on this initiative, both internally and in conjunction with the OPUC, to provide guidance and support development of the report. The OPUC recently opened a proceeding to collect input on possible changes to the regulatory model from stakeholders including regulated utilities such as PGE.

Senate Bill 1070—The State of Oregon legislators have proposed Senate Bill 1070 referred to as the Clean Energy Jobs Bill in an effort to reduce greenhouse gas emissions that contribute to climate change through a statewide cap and trade program. This will be discussed in the 35-day legislative session that began in February. The program would set a statewide cap on greenhouse gas emissions that is reduced over time and would require about 100 companies, including PGE, to acquire permits for the greenhouse gas emissions they produce. PGE continues to monitor the status of this proposed legislation.

Recovery of Utility License Fees—In May 2011, the city of Gresham, Oregon (Gresham), which is within PGE’s service territory, adopted a resolution to increase utility license fees from 5% to 7%, effective July 1, 2011. The Company believed that these utility license fees met the definition of privilege taxes within the Oregon statutes and that Gresham’s increase violated the statutory 5% limitation on such taxes. PGE began collecting the incremental 2% tax from customers in Gresham, but filed suit against Gresham in Multnomah County Circuit Court, claiming that such an increase in privilege taxes violated Oregon law. In January, 2012, the Multnomah County Circuit Court ruled in favor of PGE, and the Company ceased collecting from Gresham customers the incremental 2% tax. Gresham appealed the Multnomah County Circuit Court decision to the Oregon Court of Appeals, which subsequently ruled in Gresham’s favor.

PGE appealed the Court of Appeals’ ruling to the Oregon Supreme Court and on August 4, 2016, the Oregon Supreme Court issued its appellate judgment in favor of Gresham. As a result of this ruling, the Company was required to pay Gresham $0.8 million, which represented the amount it had already collected from customers, plus $7 million for the remaining accrued, but uncollected, amount of incremental taxes that were not paid to Gresham when due, covering the period from July 1, 2011 through September 1, 2016. PGE recorded a corresponding regulatory asset for the $7 million.

On February 24, 2017, the Company made a filing requesting that the OPUC allow recovery of the $7 million from customers in Gresham over a five-year period. In November 2017, the OPUC ruled to allow such recovery, which is expected to begin in the first quarter of 2018.

Other Regulatory Matters—The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for 2017 compared with 2016, or have affected retail customer prices, as authorized by the OPUC. In some cases, the Company has 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. 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.
    

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For further information, see “Power Operations” in the Operating Activities section of this Overview, above.

PGE’s forecast of power costs for 2016 was approved by the OPUC with an expected reduction in annual revenues of $31 million. This amount was included in the expected net annual revenue requirement increase the OPUC authorized under the Company’s 2016 GRC. Actual NVPC for 2016, as calculated for regulatory purposes under the PCAM, was $10 million below the 2016 baseline NVPC.

As a result of the OCEP legislation described above, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year. Prior to this legislative change, PGE included forecasts of PTCs only in General Rate Case proceedings. The inclusion of PTCs in the AUT provides for annual forecast updates for these estimated tax credits, thus reducing the risk of regulatory lag in terms of adjusting customer prices.

The 2017 AUT filing, approved by the OPUC in November 2016 and included in customer prices effective January 1, 2017, projected a reduction in power costs for 2017, and a corresponding reduction in annual revenue requirement, of $56 million from 2016 levels. Actual NVPC for 2017, as calculated for regulatory purposes under the PCAM, was $15 million above the 2017 baseline NVPC.

As part of its 2018 GRC, PGE included an initial projected reduction in power costs of $29 million that was included in the overall request submitted to the OPUC. As approved by the OPUC in December 2017, the 2018 GRC included a final projected reduction in power costs for 2018 and a corresponding reduction in annual revenue requirement, of $40 million from 2017 levels.

Renewable Resource Costs—Pursuant to the 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 1 each year, with prices expected to become effective January 1 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 1 effective date. No significant filings have been submitted under the RAC during 2017, 2016, or 2015.

Decoupling Mechanism—The decoupling mechanism, which the OPUC has authorized through 2019, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, 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.

The Company recorded an estimated collection of $13 million during the year ended December 31, 2017, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2016 GRC. Collections under the decoupling mechanism are subject to an annual limitation, which for 2017 stood at $18 million. Any collection from customers for the 2017 year is expected to occur over a one-year period, which would begin January 1, 2019.

The Company recorded an estimated collection of $3 million during the year ended December 31, 2016, as a result of variances from amounts established in the 2016 GRC. Collection for the year ended December 31, 2016 will occur over a one-year period, which began January 1, 2018.

The $9 million refund recorded in 2015 that resulted from variances between actual weather adjusted use per customer and that projected in the 2015 GRC, occurred during 2017. Similarly, a refund of the $5 million recorded during 2014 occurred during 2016.

Storm Restoration Costs—Beginning in 2011, the OPUC authorized the Company to collect $2 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer

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any amount not utilized in the current year. The 2018 GRC, as approved by the OPUC, increases the annual collection amount to $3 million, beginning in 2018.

As a result of a series of storm events in the first half of 2017, the Company exhausted the $2 million storm collection authorized for 2017. Consequently, PGE was exposed to the incremental costs related to such major storms events, which totaled $11 million during 2017, less the amount collected in 2017. During 2015 and 2016, PGE fully used the reserve balance as a result of restoration costs associated with storm damage occurring during those years.

As a result of the additional costs incurred, during the first quarter of 2017, PGE filed an application with the OPUC requesting authorization to defer incremental storm restoration costs from the date of the application through the end of 2017. Net of the $2 million being collected annually under the existing methodology, the application seeks deferral of $9 million. The Company is unable to predict how the OPUC will ultimately rule on this application. As a result, no deferral has been recorded as of December 31, 2017.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—In July 2016, the Company filed an application with the OPUC seeking the deferral of the future environmental remediation costs, as well as seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. In the first quarter of 2017, the OPUC approved the recovery mechanism, which will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test.

Deferral of 2018 Net Benefits Associated with the U.S. Tax Cuts and Jobs Act—On December 29, 2017, PGE filed with the OPUC an application to defer the 2017 and 2018 financial impacts resulting from the new tax law. If the deferral application is approved as requested, the refund of the net benefits associated with tax reform will be subject to an earnings test and limited by the Company’s previously authorized regulated return on equity. For more information regarding the effects of the new tax law on the Company, see the “Tax Reform” of the Overview section of this Item 7.
 
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.

PGE defines Gross margin as Revenues, net less Purchased power and fuel. Gross margin is considered a non-GAAP measure as it excludes depreciation and amortization and other operation and maintenance expenses. The presentation of Gross margin is intended to supplement an understanding of PGE’s operating performance in relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company’s definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.

The results of operations are as follows for the years presented (dollars in millions):

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Years Ended December 31,
 
2017
 
2016
 
2015
 
Amount
 
As %
of Rev
 
Amount
 
As %
of Rev
 
Amount
 
As %
of Rev
Revenues, net (1)
$
2,009

 
100
%
 
$
1,923

 
100
%
 
$
1,898

 
100
%
Purchased power and fuel (1)
592

 
30

 
617

 
32

 
661

 
35

Gross margin
1,417

 
70

 
1,306

 
68

 
1,237

 
65

Other operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Generation, transmission and distribution
309

 
16

 
286

 
15

 
266

 
14

Administrative and other
264

 
13

 
247

 
13

 
241

 
13

Depreciation and amortization
345

 
17

 
321

 
16

 
305

 
16

Taxes other than income taxes
123

 
6

 
119

 
6

 
116

 
6

Total other operating expenses
1,041

 
52

 
973

 
50

 
928

 
49

Income from operations
376

 
18

 
333

 
18

 
309

 
16

Interest expense, net (2)
120

 
6

 
112

 
6

 
114

 
6

Other income:
 
 
 
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
12

 
1

 
21

 
1

 
21

 
1

Miscellaneous income, net
5

 

 
1

 

 
1

 

Other income, net
17

 
1

 
22

 
1

 
22

 
1

Income before income taxes
273

 
13

 
243

 
13

 
217

 
11

Income tax expense
86

 
4

 
50

 
3

 
45

 
2

Net income
$
187

 
9
%
 
$
193

 
10
%
 
$
172

 
9
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) As reported on PGE’s Consolidated Statements of Income
(2) Includes an allowance for borrowed funds used during construction of $6 million in 2017, $11 million in 2016, and $13 million in 2015.


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Revenues, energy deliveries (presented in MWh), and average number of retail customers consist of the following for the years presented:
 
Years Ended December 31,
 
2017
 
2016
 
2015
Revenues(1) (dollars in millions):
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
Residential
$
969

 
48
%
 
$
907

 
47
%
 
$
895

 
47
 %
Commercial
669

 
33

 
665

 
35

 
662

 
35

Industrial
212

 
11

 
208

 
11

 
228

 
12

Subtotal
1,850

 
92

 
1,780

 
93

 
1,785

 
94

Other accrued (deferred) revenues, net
10

 
1

 
3

 

 
(10
)
 
(1
)
Total retail revenues
1,860

 
93

 
1,783

 
93

 
1,775

 
93

Wholesale revenues
105

 
5

 
103

 
5

 
88

 
5

Other operating revenues
44

 
2

 
37

 
2

 
35

 
2

Total revenues
$
2,009

 
100
%
 
$
1,923

 
100
%
 
$
1,898

 
100
 %
 
 
 
 
 
 
 
 
 
 
 
 
Energy deliveries(2) (MWh in thousands):
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
Residential
7,880

 
34
%
 
7,348

 
33
%
 
7,325

 
33
 %
Commercial
7,555

 
33

 
7,457

 
33

 
7,511

 
34

Industrial
4,283

 
19

 
4,166

 
19

 
4,546

 
21

Total retail energy deliveries
19,718

 
86

 
18,971

 
85

 
19,382

 
88

Wholesale energy deliveries
3,193

 
14

 
3,352

 
15

 
2,560

 
12

Total energy deliveries
22,911

 
100
%
 
22,323

 
100
%
 
21,942

 
100
 %
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers:
 
 
 
 
 
 
 
 
 
 
 
Residential
762,211

 
88
%
 
752,365

 
88
%
 
742,467

 
88
 %
Commercial
107,855

 
12

 
106,773

 
12

 
105,802

 
12

Industrial
267

 

 
258

 

 
255

 

Total
870,333

 
100
%
 
859,396

 
100
%
 
848,524

 
100
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those customers that purchase their energy from ESSs. Commercial revenues from ESS customers were $17 million, $13 million, and $12 million for 2017, 2016, and 2015, respectively. Industrial revenues from ESS customers were $20 million, $15 million, and $16 million for 2017, 2016, and 2015, respectively.
(2)
Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs. Commercial deliveries to ESS customers, in thousands of MWhs, were: 623 in 2017; 525 in 2016; and 509 in 2015. Industrial deliveries to ESS customers, in thousands of MWhs, were: 1,340 in 2017; 1,198 in 2016; and 1,177 in 2015.

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PGE’s sources of energy, total system load, and retail load requirement for the years presented are as follows:
 
Years Ended December 31,
 
2017
 
2016
 
2015
Sources of energy (MWh in thousands):
 
 
 
 
 
 
 
 
 
 
 
Generation:
 
 
 
 
 
 
 
 
 
 
 
Thermal:
 
 
 
 
 
 
 
 
 
 
 
Natural gas
6,228

 
28
%
 
5,811

 
27
%
 
4,783

 
22
%
Coal
3,344

 
15

 
3,492

 
16

 
4,128

 
19

Total thermal
9,572

 
43

 
9,303