UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-K
[x]FORM10-K
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20172020


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)
Oregon93-0256820
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 valueNew York Stock Exchange
(Title of class)(Trading symbol)(Name of exchange on which registered)
Common Stock, no par valuePORNew York Stock Exchange
9.31% Medium-Term Notes due 2021POR 21New York Stock Exchange
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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, 2017,2020, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $4,048,647,464.$3,725,882,304. For purposes of this calculation, executive officers and directors are considered affiliates.


As of February 2, 2018,10, 2021, there were 89,114,52289,539,034shares of common stock outstanding.


Documents Incorporated by Reference


Part III, Items 10 - 14Portions 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, 2018.28, 2021.




PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 20172020


TABLE OF CONTENTS


4
PART I
Item 1.
45
Item 1A.
Item 1.
Business.21
5
Item 1A.1B.
22
Item 1B.
Unresolved Staff Comments.
2827
Item 2.
2827
Item 3.
3029
Item 4.
3029
PART II
Item 5.
3029
Item 6.
3129
Item 7.
3130
Item 7A.
5960
Item 8.
63
Item 9.
117120
Item 9A.
117120
Item 9B.
117120
PART III
Item 10.
117121
Item 11.
117121
Item 12.
117121
Item 13.
118121
Item 14.
118121
PART IV
Item 15.
119122
Item 16.
123
SIGNATURES
121124


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Table of Contents


DEFINITIONS


The abbreviations or acronyms defined below are used throughout this Form 10-K:
 
Abbreviation or AcronymDefinition
AFDCAllowance for funds used during construction
AROAsset retirement obligation
AUTAnnual Power Cost Update Tariff
BeaverBeaver natural gas-fired generating plant
Biglow CanyonBiglow Canyon Wind Farm
BoardmanBoardman coal-fired generating plant
BPABonneville Power Administration
CAACartyClean Air Act
CartyCarty natural gas-fired generating plant
ColstripColstrip Units 3 and 4 coal-fired generating plant
Coyote SpringsCoyote Springs Unit 1 natural gas-fired generating plant
CWIPConstruction work-in-progress
Dth
DthDecatherm = 10 therms = 1,000 cubic feet of natural gas
DEQOregon Department of Environmental Quality
EFSAEIMEquity forward sale agreement
EIMEnergy Imbalance Market
EPAUnited States Environmental Protection Agency
ESSElectricity Service Supplier
FERCFederal Energy Regulatory Commission
FMBFirst Mortgage Bond
FPAFederal Power Act
GRCGeneral Rate Case for a specified test year
IRPIntegrated Resource Plan
ISFSIIndependent Spent Fuel Storage Installation
kVKilovolt = one thousand volts of electricity
Moody’sMoody’s Investors Service
MWMegawatts
MWaAverage megawatts
MWhMegawatt hours
NRCNuclear Regulatory Commission
NVPCNet Variable Power Costs
OATTOpen Access Transmission Tariff
OPUCPublic Utility Commission of Oregon
PCAMPower Cost Adjustment Mechanism
PW1PTCFederal production tax credit
PW1Port Westward Unit 1 natural gas-fired generating plant
PW2Port Westward Unit 2 natural gas-fired flexible capacity generating plant
RPSQFPURPA qualifying facility
RACRenewable Adjustment Clause
RPSRenewable Portfolio Standard
S&PS&P Global Ratings
SECUnited States Securities and Exchange Commission
TrojanTrojan nuclear power plant
Tucannon RiverTucannon River Wind Farm
USDOEUnited States Department of Energy


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Table of Contents


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 Statestate 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.Exchange (NYSE). 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 approximately4,000four thousand 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 approximately46% of the population of the State of Oregon.cities. During 2017,2020, the Company added nearly 12,00013 thousand customers, and as of December 31, 2017,2020, served a total of 875,000908 thousand 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 cover732 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,periodic and current reports, 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 Statestate of Oregon (State) regulation both caneach 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 securitycybersecurity 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,supply, in real time. Continued market-based rate authority requires specific actions by PGE includingtime, and 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 forexception within 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.


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Transmission—PGE offers wholesale 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 SecurityCybersecurity Standards—Pursuant to the Energy Policy Act of 2005, theThe 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 frameworkand are intended to identify andhelp protect critical cyber assets used to support reliable operation of the bulk power system.operations.


Natural Gas Pipelines—The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide the FERC has 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 Port Westward Unit 1 (PW1), Port Westward Unit 2 (PW2), and Beaver, the Company’s natural gas-fired generating plants located near Clatskanie, Oregon: Port Westward Unit 1 (PW1); Port Westward Unit 2 (PW2);Oregon, and Beaver.to the North Mist storage facility. 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—UnderAs required 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.all Company-owned hydroelectric generating plants. 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—PursuantPGE prepares periodic and current reports in accordance with accounting principles generally accepted in the United States of America (GAAP). In addition, the Company prepares, 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 byFor additional information on the FERC on January 3, 2018, has authorization to issue up to $900 millionCompany’s Short-term Debt, see Short-term Debt in the Debt and Equity section of short-term debt through February 6, 2020.Liquidity and Capital Resources in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


Spent Fuel Storage—The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s decommissioned 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 7,8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”Data” and “Hazardous Material” in the Environmental Matters section of this Item 1.


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,which 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-annualbiennial 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. Customercustomer 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,may include PGE, OPUC staff, and intervenors representing PGE customer groups.groups, as well as other interested parties. The
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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 rateas part of return to investors. Such changes are requested pursuant to a comprehensive general rate case process that includesreflects revenue requirements based on a forecasted test year,year. The OPUC authorizes the Company’s 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 Discussionreturn, and Analysis of Financial Condition and Results of Operations.”
customer prices.

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•Annual Power CostsCost Updates. In addition to price changes resulting from the general rate case process, theThe OPUC has approved the following mechanismsan Annual Power Cost Update Tariff (AUT) by which PGE can adjust retail customer prices annually to coverreflect forecasted 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.income as Revenues, net. The OPUC has also authorized a Power Cost Adjustment Mechanism (PCAM), under which PGE may share with customers a portion of actual cost variances associated with NVPC.
◦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) establishedState maintains a Renewable Portfolio Standard (RPS), which required that requires PGE to serve at least 15%a portion of its retail load with renewable resources by 2015,resources. In conjunction with future requirements of 20% by 2020 and 25% by 2025. PGE met the 2015 requirement and expects to meetRPS, the requirements going forward.

The 2007 ActState established a Renewable Adjustment Clause (RAC) mechanism that 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 retail customer prices, outside of a general rate case, 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 Oregonalso 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))(SB 1547), increaseswhich, among its provisions, increased the RPS percentages in certain future years, changesyears. For further information on SB 1547, see “Carbon Legislation and Administrative Actions” in 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”Overview 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’sUnder cost of service pricing, residential and small commercial customers may select portfolio options from PGE that include time-of-use and industrial customers have access to pricingrenewable resource pricing.

Pricing options other than cost of service are available to certain commercial and industrial customers for a one-year period, including daily market index-based pricing under which the Company provides the electricity, and Direct Access, whereby customers purchase their electricity directly from an Electricity Service Supplier (ESS). All commercial and industrial customers are eligible for

PGE receives revenue from Direct Access under which the Company receives revenuecustomers only for the transmission and delivery of the energyvolume of electricity delivered, along with fixed transition adjustments intended to mitigate the shifting of excess charges 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.Company’s cost of service customers. 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 athe daily market index-based price.price option. Participation in the fixed three-year and minimum five-year opt-out programs for existing and planned load is capped at 300 average megawatts (MWa) in aggregate. The majority of

In 2018, 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 haveOPUC created and approved rules for a material impact on PGE’s financial condition or operating results as revenue changes resulting from increases or decreases in electricity sales toNew Large Load Direct Access customers are substantially offset by changes(NLDA) program, which is capped at 119 MWa, for unplanned, large, new loads and large load growth at existing sites. In January 2020, the OPUC issued an order that required PGE to begin offering enrollment in the Company’s cost of purchased power and fuel. Further, theNLDA program provides for transition adjustment charges or credits to Direct Access and market-based pricingeligible 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. in early February 2020.

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 acceptedprepares financial statements in the United States of America (GAAP)accordance with GAAP and, as a regulated public utility, the effects of rate regulation are reflected in its financial statements. These principles provideGAAP provides 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 be recognized as revenue or reduce expense can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE
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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 6,7, 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.Oregon. 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.ESSs. Energy efficiency, and conservation measures as well asand distributed solar generation also have an increasing trend toward rooftop solar generation in recent years, also influence on customer demand.


Retail Revenues


Retail customers are classified as residential, commercial, or industrial, with no single customer representing more than 6%8% of PGE’s total retail revenues or 9%12% 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,Years Ended December 31,
2017 2016 2015202020192018
Retail revenues(1) (dollars in millions):
           
Retail revenues (1) (dollars in millions):
Residential$969
 52% $907
 51% $895
 50%Residential$1,030 53 %$981 52 %$948 53 %
Commercial669
 36
 665
 37
 662
 37
Commercial634 33 654 35 665 37 
Industrial212
 11
 208
 12
 228
 13
Industrial246 13 222 12 210 12 
Subtotal1,850
 99
 1,780
 100
 1,785
 100
Subtotal1,910 99 1,857 99 1,823 102 
Alternative revenue programs, net of amortizationAlternative revenue programs, net of amortization(6)— 2 — 3 — 
Other accrued (deferred) revenues, net(2)10
 1
 3
 —
 (10) —
28 1 22 1 (45)(2)
Total retail revenues$1,860
 100% $1,783
 100% $1,775
 100%Total retail revenues$1,932 100 %$1,881 100 %$1,781 100 %
Retail energy deliveries(2) (MWh in thousands):
           
Retail energy deliveries (3) (MWh in thousands):
Retail energy deliveries (3) (MWh in thousands):
Residential7,880
 40% 7,348
 39% 7,325
 38%Residential7,756 40 %7,471 38 %7,416 39 %
Commercial7,555
 38
 7,457
 39
 7,511
 39
Commercial6,855 35 7,318 38 7,430 39 
Industrial4,283
 22
 4,166
 22
 4,546
 23
Industrial4,932 25 4,671 24 4,376 22 
Total retail energy deliveries19,718
 100% 18,971
 100% 19,382
 100%Total retail energy deliveries19,543 100 %19,460 100 %19,222 100 %
Average number of retail customers:           Average number of retail customers:
Residential762,211
 88% 752,365
 88% 742,467
 88%Residential791,119 88 %779,673 88 %772,389 88 %
Commercial107,855
 12
 106,773
 12
 105,802
 12
Commercial110,851 12 110,084 12 109,107 12 
Industrial267
 —
 258
 —
 255
 —
Industrial267 — 262 — 270 — 
Total870,333
 100% 859,396
 100% 848,524
 100%Total902,237 100 %890,019 100 %881,766 100 %
(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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(1)Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of Contentsenergy to those commercial and industrial customers that purchase their energy from ESSs.

(2)Amounts for the years ended December 31, 2020 and 2019 are primarily comprised of $24 million and $23 million of amortization, respectively, including interest, related to the $45 million deferral reflected in 2018 for the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA).

(3)Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.
Additional
The following table presents additional averages for retail customerscustomers. Certain supplemental tariff collections are excluded from revenues as follows:
they are not considered a part of the Company’s base retail prices for these calculations.
Years Ended December 31,Years Ended December 31,
2017 2016 2015 202020192018
Residential     Residential
Revenue per customer (in dollars):$1,181
 $1,114
 $1,139
Revenue per customer (in dollars):$1,226 $1,177 $1,153 
Usage per customer (in kilowatt hours):10,338
 9,766
 9,866
Usage per customer (in kilowatt hours):9,804 9,582 9,601 
Revenue per kilowatt hour (in cents):
11.42¢ 
11.40¢ 
11.55¢Revenue per kilowatt hour (in cents):12.50 ¢12.28 ¢12.01 ¢
Commercial
    Commercial
Revenue per customer (in dollars):$6,142
 $6,166
 $6,254
Revenue per customer (in dollars):$5,684 $5,901 $6,051 
Usage per customer (in kilowatt hours):70,046
 69,839
 70,987
Usage per customer (in kilowatt hours):61,837 66,481 68,096 
Revenue per kilowatt hour (in cents):
8.77¢ 
8.83¢ 
8.81¢Revenue per kilowatt hour (in cents):9.19 ¢8.88 ¢8.89 ¢
Industrial     Industrial
Revenue per customer (in dollars):$792,466
 $804,953
 $876,866
Revenue per customer (in dollars):$921,540 $847,079 $776,245 
Usage per customer (in kilowatt hours):16,041,461
 16,146,371
 17,485,281
Usage per customer (in kilowatt hours):18,472,161 17,827,115 16,207,263 
Revenue per kilowatt hour (in cents):
4.94¢ 
4.99¢ 
5.01¢Revenue per kilowatt hour (in cents):4.99 ¢4.75 ¢4.79 ¢

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’saddition to standard cost of service and are determined through general rate case proceedings and various tariff filings with the OPUC. Additionally,pricing, 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, increasedseason. Increased use of air conditioning in PGE’s service territory has caused the summer peaks to increase.increase in recent years, while the historical winter peak has not increased in over 20 years. In recentthe past few years, summer peaks have exceeded winter peaks and long-term load forecasts expect that trend to continue. Economic conditions can also affect residential demand; strongdemand as job growth and population growth in PGE’s service territory have led to increasingincreased 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 arecustomer demand is somewhat less susceptible to weather conditions than the residential customer although weather does affect commercial demand to some extent.demand. 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,
9
Ta 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.bleofContents


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 onunder 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, largely through bi-lateral agreements, within the region to serve retail demand, depending upon the relative price and availability of power, hydro and wind conditions, and daily and seasonal retail demand. PGE also participates in the California Independent System Operator’s western Energy Imbalance Market (western EIM), which allows for load balancing with other western EIM participants in five-minute intervals. Wholesale revenues represented 5%8% of total revenues in each of the past three years.2020, 2019, and 2018.

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 contactattachment rentals, and other electric services provided to customers. Other operating revenues have represented 2% of total revenues in each of the past three years.2020, and 3% in 2019 and 2018.


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 indetermined by taking the difference between the average daily temperature fromand a baseline of 65 degrees, provide cumulative variances 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.cooling. 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
20203,836600
20194,165564
20183,702692
15-year average4,145538
 
Heating
Degree-Days
 
Cooling
Degree-Days
20174,558 700
20163,552 548
20153,461 785
15-year average4,233 471
    
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, andJune through 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 experiencedcontinues to experience its highest annual peak loads during the summer in each of the past three years: months:

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 Winter Loads Summer Loads
 Average Peak Month Average Peak Month
20172,698 3,727 January 2,380 3,976 August
20162,537 3,716 December 2,246 3,726 August
20152,509 3,255 December 2,390 3,914 July
Winter LoadsSummer Loads
AveragePeakMonthAveragePeakMonth
20202,5663,367December2,2893,771July
20192,6093,422February2,2633,765June
20182,5193,399February2,3013,816August


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 (GRC) 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 uponutilizes its generating resources, as well as wholesale power purchases from third parties to meet the needs of its customers’ energy requirements.retail customers. 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 and sale 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 promotesencourages energy efficiency measures to help meet its energy requirements.requirements and promotes the use of various demand side management products to reduce load during peak time usage.


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PGE’s generating resources consist of seven thermal plants (natural gas-resource and coal-fired), two wind farms, and seven hydroelectric facilities. contracted capacity (in MW) was as follows:

 As of December 31,
 20202019
 Capacity%Capacity%
Generation:
Thermal (1):
Natural gas1,831 34 %1,830 35 %
Coal296 6 814 15 
Total thermal2,127 40 2,644 50 
Wind (2)
817 16 717 14 
Hydro (3)
495 9 495 9 
Total generation3,439 65 3,856 73 
Purchased power:
Long-term contracts:
Hydro (3)
512 10 462 9 
PURPA qualifying facilities (4)
279 5 133 3 
Dispatchable standby generation123 2 125 2 
Capacity100 2 100 2 
Wind (2)
300 6 100 2 
Solar7 — 7 — 
Biomass10 — 10 — 
Total long-term contracts1,331 25 937 18 
Short-term contracts538 10 471 9 
Total purchased power1,869 35 1,408 27 
Total resource capacity5,308 100 %5,264 100 %
(1)Capacity of the thermal plants represents the MW the plant isplants are capable of generating under normal operating conditions, which is affected by ambient temperatures, net of electricity used in the operation of the plant. PGE’s Boardman coal-fired generating plant (Boardman) ceased coal-fired operations during the fourth quarter of 2020.
(2)Capacity of both hydrorepresents nameplate and wind generating resources represent the nameplate MW,differs from expected energy to be generated, which varies from actual energyis expected to have a capacity factor range from 30 to 40%, dependent upon wind conditions.
(3)Capacity represents net capacity and differs from expected energy to be received as these types of generating resources are highlygenerated, which is expected to have a capacity factor range from 40 to 50%, dependent upon river flows and wind conditions, respectively. Availabilityflows.
(4)Capacity represents contracted capacity under the percentagePublic Utility Regulatory Policies Act 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.”1978 (PURPA).


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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 gas1,831
 39% 1,805
 38% 1,371
 30%
Coal814
 17
 814
 17
 814
 17
Total thermal2,645
 56
 2,619
 55
 2,185
 47
Wind (1)
717
 15
 717
 15
 717
 16
Hydro (2)
495
 10
 495
 11
 495
 11
Total generation3,857
 81
 3,831
 81
 3,397
 74
Purchased power:           
Long-term contracts:           
Capacity/exchange100
 2
 250
 5
 250
 5
Hydro531
 12
 534
 12
 592
 13
Wind39
 1
 39
 1
 39
 1
Solar13
 —
 13
 —
 13
 —
Other18
 —
 18
 —
 118
 3
Total long-term contracts701
 15
 854
 18
 1,012
 22
Short-term contracts185
 4
 45
 1
 200
 4
Total purchased power886
 19
 899
 19
 1,212
 26
Total resource capacity4,743
 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, 2016,2020 and 2015,2019, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


Generation


PGE’s generating resources consist of six thermal plants (natural gas- and coal-fired), three wind farms, and seven hydroelectric facilities. 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. For a complete listing of these facilities, see “Generating Facilities” in Item 2.—“Properties.”

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.


Thermal    The Company operates,has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and hasCarty Generating Station (Carty).
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The Company operated, and continues to have a 90% ownership interest in, Boardman, andwhich ceased coal-fired operations during the fourth quarter of 2020. The Company has begun the initial steps toward decommissioning the facility. The Company also has a 20% ownership interest in the 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 scheduledPursuant to cease coal-fired operations at the end of 2020, and pursuant to Oregon Senate BillSB 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 BillSB 1547, see “Legal, Regulatory,

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Carbon Legislation and Environmental Matters”Administrative Actions” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The thermal plants provide reliable powerWind     PGE owns and capacity reserves foroperates 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 customers. These resources havelargest renewable energy resource consisting of 217 turbines with a combinedtotal nameplate capacity of 2,645 MW, representing approximately69%450 MW. Tucannon River, located in southeastern Washington, consists of 116 turbines with a total nameplate capacity of 267 MW. During 2020, the wind component of the netWheatridge Renewable Energy Facility (Wheatridge), located in Morrow County, Oregon, was placed into service. Although PGE does not operate Wheatridge, it now owns 40 turbines with a total nameplate capacity of PGE’s generating portfolio. Thermal plant availability, excluding Colstrip, was 88% in 2017, 92% in 2016,100 MW and 89% in 2015, while Colstrip availability was 86% in 2017, compared with 85% in 2016 and 93% in 2015.

WindPGE 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%purchases the output of the remaining turbines, with a capacity of 200 MWs through power purchase agreements. For additional information on Wheatridge, see “The Resource Planning Process” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Hydro    The Company’s total retail load requirement in 2017FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), 10% in 2016,four plants on the Clackamas River, and 9% in 2015. Availability for these resources was96% in 2017, compared with 95% in 2016 and 97% in 2015. The expected energy from wind resources differs fromone on 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.Willamette River.

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 both2016 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)(CTWS). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The Tribes haveCTWS has an option to purchase an additional undivided16.66% interest in Pelton/Round Butte at itstheir discretion on December 31, 2021. The Tribes haveCTWS has 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’CTWS’s 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 135MW 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 GasPhysical 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.

Natural GasPhysical supplies of natural gas are generally purchased up to twelve months in advance of delivery and based on anticipated operation of the plants. PGE manages 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-BeaverKB Pipeline, which directly connects PW1, PW2, and Beaver to the 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-BeaverKB 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 on the Northwest Pipeline to serve the three plants.


PGE also has contractual access to 4.1 billion cubic feet of 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.
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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 119,500120,000 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.

CoalPGE 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.

Coal     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 forfacility and is the sole source of coal supply extends through2019for the plant. The coal supply contract with the owner of the mine is scheduled to expire at the end of 2025. The terms of contracts and the Colstrip co-owners continue negotiationsquality of coal are expected to extend the contract.be in alignment with required emissions limits.


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 2017,2020, 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:following agreements:


Mid-Columbia hydro•Public Utility Districts—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of threetwo 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.
time:


◦one contract, with Grant County PUD, representing 165 MW of capacity that expires in 2052;
Confederated Tribes
◦one contract, with Douglas County PUD, representing 148 MW of capacity that expires in 2028; and

◦another contract with Douglas County PUD that is a five-year agreement starting January 1, 2021 to supply the Company with additional capacity between 100 and 160 MW, which is not reflected in the table above.

•CTWS—PGE has a long-term agreement under which the Company purchases, at index prices, the Tribes’CTWS’ 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 TribesCTWS under which the Tribes haveCTWS has agreed to sell, on modified payment terms, theirits share of the energy generated from the Pelton/Round Butte hydroelectric project exclusively to the Company through 2024.


Wind•Other—PGE has threetwo additional contracts that provide for the purchase of power generated from hydroelectric projects in Oregon with capacity of 37 MW in total. One contract for 36 MW expires in 2032 while the second has no expiration date.

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PURPA qualifying facilities—PGE is required to purchase power from PURPA qualifying facilities (QFs), as mandated by federal law. QFs are generating facilities that fall within the following two categories: i) qualifying generation facilities with a capacity of 80 MW or less and whose primary energy source is renewable wind-generated(hydro, wind, solar, biomass, waste, or geothermal); or ii) qualifying cogeneration facilities that sequentially produce electricity and another form of useful thermal energy (e.g., heat, steam) in a way that is more efficient than the separate production of each form of energy. As of December 31, 2020, PGE had contracts with 60 on-line PURPA qualifying facilities, providing a total of 279 MW of capacity. As of December 31, 2020, PGE has 36 contracts with PURPA QFs representing 164 MW of capacity that are not yet operational, of which 34 of the QF power purchase agreements (PPAs) are in default because the QF has failed to complete construction and become operational by the date required by the PPA. The PPAs provide that the QF has one year to cure its default. If the QF has failed to cure, PGE is permitted to immediately terminate the QF PPA upon expiration of the cure period. The term of a QF PPA generally ranges from 15 to 23 years, measured from the date of execution.

The expense and volume of purchases from QFs for the years ended December 31, 2020 and 2019 were as follows:
20202019
PURPA contract expense (in millions)$43 $6 
MWh purchased under PURPA contracts (in thousands)498 152 
Average cost per MWh from PURPA contracts$85.31 $38.69 

Expenses incurred related to PURPA contracts are included in PGE’s AUT.

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, 2020, there were 53 customer-owned sites with a total DSG capacity of 123 MW. PGE continues to pursue expansion of the program with the goal of having an additional 3 MW of customer-owned DSG projects online by the end of 2022.

Capacity—PGE’s capacity contracts are primarily comprised of the following agreements to help meet peak loads:

•Seasonal peaking capacity up to 100 MW during the summer and winter peak periods obtained from a natural gas-fired resource, which expires in 2024; and

•Starting in January 2021, an additional 200 MW of annual capacity will be added, with a five-year term, primarily obtained from hydroelectric resources.

Wind—PGE has three contracts representing 300 MW of capacity to purchase power generated from renewable wind resources that extend to various dates between 2028, 2035, and 2035.2050. The expected energy from these wind contracts differsresources will vary from the nameplate capacity and is expecteddue to approximate 39 MWa, dependent uponvarying wind conditions.


Solar—PGE has three agreements that expire during 2036 and 2037contracts representing 7 MW of capacity to purchase power generated from photovoltaic solar projects which have a combined generating capacity of 7 MW. In addition, the Company operates,that extend to 2036 and purchases power from three solar projects with an aggregate of approximately 6 MW of capacity.2037. The expected energy from these solar resources will vary from the nameplate capacity due to varying solar conditions.


OtherBiomass—These primarily consist of long-term contractsPGE has one contract to purchase power from various counterparties, including other Pacific Northwest utilities, over terms extending into 2031.biomass energy that is set to expire in 2021.


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.
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As of 2017, PGE became a market participant in the western EIM, which allows certain of the Company’s generating plants to receive automated dispatch signals from the California Independent System Operator (CAISO) for load balancing with other western EIM participants in five-minute intervals.

For additional information regarding PGE’s power purchase contracts, see Note 15,16, 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 IRPIntegrated Resource Plan (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“The Resource Plan”Planning Process” 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 2017,2020, PGE delivered approximately 2325 million MWhmegawatt hours (MWh) in its balancing authority area through 1,2501,269 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:customers, including:


•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
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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 (GHG) emissions, (GHGs).among other things. 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 toas stringent as 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 EPAUnited States Environmental Protection Agency (EPA) released a rule,the Clean Power Plan (CPP), under 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.

basis. In February 2016, the United States Supreme Court granted a stay, haltinghalted implementation and enforcement of the CPP.

In 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, to repeal and replace the CPP pendingand, in 2019, finalized the resolutionACE rule, which established guidelines for states to develop plans to address GHG emissions from existing coal-fired plants, such as Colstrip in the case of legal challenges toPGE. With the rule. On March 28, 2017, the Presidentfinalization of the United States issued an Executive Order that directed various agencies to review existing regulations that potentially burdenACE rule, the development of the nation’s energy resources. The Department of Justice (DOJ) filed requests withCPP was repealed. However, on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit (DC Circuit Court) to suspend and hold in abeyancevacated the current litigation over the CPP in light of the Executive Order while EPA reviews theACE rule and determines its next steps. The DC Circuit Court grantedremanded it, in full, back to 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 which casts uncertainty on the stay, the ultimate outcomestatus of the legal challenges andCPP, as the regulatory processcourt did not say whether it viewed its decision on the ACE rule as reinstatement of the CPP.

The EPA or whether Oregonhas now been directed to review all climate and environmental rules promulgated over the past four years, including the ACE rule. The Company 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 reportchallenges to the DEQrecent ACE rule decision, and how the amount of GHG emissions produced along withEPA will replace the total amount of energy produced or purchased by PGEACE rule, and potentially the CPP, for consumption in Oregon.impacts on Colstrip and its existing natural gas fleet.

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 were incurred 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 StatePGE’s carbon-emitting facilities provided 62% 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. Company’s net generating capacity at December 31, 2020.

For more information regarding the OCEP,GHGs and its impact on PGE,related environmental regulation, see the “Legal, Regulatory,Carbon Legislation and Environmental Matters”Administrative Actions” in theOverview 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 currently 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 17,19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”



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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.Northwest. 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 planAvian 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 similaradditional 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).Act. 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 includedesignate 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 17,19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


UnderPGE is subject to regulation by the United States Department of Energy (USDOE), which, 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 NRC approved the transfer of spent nuclear fuel from a spent fuel pool to the ISFSI where it 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 2034.2059. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 7,8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


Human Capital Management

PGE’s talent and culture are vital to its ability to execute its business strategy and realize continued success. Accordingly, the Company seeks to attract and retain a talented, motivated, and diverse workforce and maintain a culture that reflects PGE’s core values, drive for performance, and commitment to acting with the highest levels of honesty, integrity, and compliance.

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Employees and Collective Bargaining Agreements—PGE had 3,639 members in its workforce (769 of which are contingent workers) as of December 31, 2020, with721 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (IBEW). The agreements cover660 and61 employees and expire March 2022 and August 2022, respectively. The partnership with IBEW is key to a holistic labor relations approach.

Competitive Pay and Benefits—PGE is committed to ensuring pay equity among its employees and offers a wide range of market-competitive benefits, including comprehensive health and welfare benefits and a 401(k) retirement plan, designed to support the physical, mental, and financial well-being of its employees.

Talent development—PGE provides a variety of training and development programs for employees, as well as tuition reimbursement for job-related coursework. TheBoard oversees executive talent development with the assistance of the Governance Committee and the Compensation Committee in an effort to maximize the pool of internal candidates. In addition, the Compensation Committee regularly conducts more in-depth reviews of development plans for promising management talent for promotion and advancement.

Health and safety—PGE is committed to providing a safe and healthy place of business for employees, customers, and the public. Management has established an Executive Safety Council that has oversight of the Company’s efforts to create a safe workplace. In addition, PGE provides various safety resources to its employees, such as safety manuals, trainings, and incident reporting tools that are all designed to incorporate safe practices into all daily activities and promote in all employees a sense of personal commitment, responsibility, and obligation regarding safety.

Diversity, Equity and Inclusion —PGE promotes an inclusive workforce through pay equity practices, racial equity training, and development opportunities for women and people of color to advance into management. Black, Indigenous, and People of Color comprise over 22% of its employees and nearly 19% of management. Nearly one third of its employees and over 31% of its management, including its CEO, are female. PGE also promotes diversity and economic development through its suppliers. The Company’s supplier diversity program ensures opportunity in all competitive bid events for qualified minority-owned, women-owned, disabled veteran-owned, and emerging small business suppliers.

COVID-19— In response to the COVID-19 pandemic, PGE took immediate steps to protect employees by making changes to work schedules, work locations, cleaning practices, work protocols, and information services—including encouraging employees to take advantage of its comprehensive health, wellness, family, and leave programs.


Information about Our ExecutiveOfficers

The following are PGE’s current executive officers:
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NameAgeCurrent Position and Previous ExperienceYear Appointed Officer
James A. Ajello67Senior Vice President, Finance, Chief Financial Officer and Treasurer (January 2021 to present), Senior Advisor (November 2020 to December 2020), Executive Vice President and Chief Financial Officer at Hawaiian Electric Industries (January 2009 to April 2017 - retired), Senior Vice President, Business Development at Reliant Energy (January 2000 to January 2009), Managing Director, UBS Securities (January 1984 to August 1998).2021
Larry N. Bekkedahl59Vice President, Grid Architecture, Integration and Systems Operations (January 2019 to present), Vice President Transmission and Distribution (August 2014 to January 2019). Senior Vice President of Transmission Services at BPA (June 2012 to August 2014), Vice President of Engineering and Technical Services at BPA (2008 to June 2012).2014
Bradley Y. Jenkins57Vice President, Utility Operations (January 2019 to present), Vice President, Generation and Power Operations (October 2017 to January 2019), Vice President, Power Supply Generation (September 2015 to October 2017), General Manager, Diversified Plant Operations, (November 2013 to August 2015), Plant General Manager, Boardman (September 2012 to November 2013), Operations Manager, Boardman (March 2012 to September 2012).2015
Lisa A. Kaner60Vice President, General Counsel and Corporate Compliance Officer (July 2017 to present), trial attorney and shareholder at Markowitz Herbold PC (1994 to June 2017).2017
John T. Kochavatr47Vice President, Information Technology and Chief Information Officer (February 2018 to present). Senior Vice President and Chief Information Officer at SUEZ Water Technologies & Solutions (formerly General Electric Water and Process Technologies) (October 2017 to January 2018), Chief Information Officer and Chief Digital Officer at General Electric Water and Process Technologies (November 2012 to September 2017).2018
John C. McFarland40Vice President, Chief Customer Officer (April 2019 to present). Director, Global Digital Experience at General Motors (February 2016 to March 2019), Chief Marketing Officer at OnStar (a subsidiary of General Motors, October 2012 to January 2016), Senior Manager of Strategy at General Motors (September 2010 to September 2012), Brand Management and Finance at Procter & Gamble (August 2002 to August 2010).2019
Anne F. Mersereau58Vice President, Human Resources, Diversity, Equity and Inclusion (January 2016 to present), Employee Services Manager (January 2014 to January 2016), Change Management Consultant (January 2012 to January 2014), Human Resources Business Partner (July 2009 to December 2011).2016
Maria M. Pope55President (October 2017 to present) and Chief Executive Officer (January 2018 to present), Senior Vice President, Power Supply, Operations and Resource Strategy (March 2013 to December 2017), Senior Vice President, Finance, Chief Financial Officer and Treasurer (January 2009 to February 2013). Board director (January 2006 to December 2008). Vice President and Chief Financial Officer for Mentor Graphics Corporation (July 2007 to December 2008).2009
W. David Robertson53Vice President, Public Affairs (August 2009 to present), Director of Government Affairs (June 2004 to August 2009).2009
Brett M. Sims52Vice President, Strategy, Regulation and Energy Supply (October 2020 to present), Senior Director of Strategy, Commercial and Regulatory Affairs (September 2017 to October 2020), Director of Origination, Structuring & Resource Strategy (May 2001 to September 2017).2020
Kristin A. Stathis57Vice President, Operations Services (May 2019 to present), Vice President, Customer Solutions (January 2019 to May 2019), Vice President, Customer Service Operations (June 2011 to December 2018), General Manager of Revenue Operations (August 2009 to May 2011), Assistant Treasurer and Manager of Corporate Finance (October 2005 to July 2009), General Manager of Power Supply Risk Management (August 2003 to September 2005).2011
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ITEM 1A.     RISK FACTORS.


Certain risks and uncertainties that could have a significantmaterial 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.


REGULATORY, LEGAL, AND COMPLIANCE RISKS

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.

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 electricityPGE is subject to various legal and impairregulatory proceedings, the financial stabilityoutcome of some ofwhich is uncertain, and resolution unfavorable to PGE’s customers, could affect the Company’s results of operations.

Unfavorable economic conditions in Oregon may result in reduced demand for electricity. Such reductions in demand could adversely affect PGE’sthe Company’s results of operations, andfinancial condition, or cash flows. Economic conditions

In the normal course of its business, PGE is subject to various regulatory proceedings, lawsuits, claims, and other matters, which 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 existingadverse judgments, settlements, fines, penalties, injunctions, or future contracts.


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Market prices for power and natural gasother relief. These matters are subject to forcesmany uncertainties, the ultimate outcome of which management cannot predict. The final resolution of certain matters in which PGE is involved could require that are often not predictablethe Company incur expenditures over an extended period of time 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 ultimatelya range of amounts that could have an adverse effect on the Company’s liquidityits cash flows and results of operations.

As part Similarly, the terms of resolution could require the Company to change its normal business operations, PGE purchases powerpractices 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,procedures, 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 marketalso have an adverse effect on its cash flows, financial position, 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 revenuesThere are certain pending legal and costs, impacting the Company’sregulatory proceedings that may have an adverse effect on results of operations. Variations in temperatures can affect customer demandoperations and cash flows 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 deliveryfuture reporting periods. For additional information, see Item 3.—“Legal Proceedings” 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 resultNote 19, Contingencies, in the sale of excess energy at depressed market prices.Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


Forced outages at PGE’s generating plants can increase the cost of power required
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Legislative or regulatory efforts 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 plantsreduce GHG emissions could result in powerlead to increased capital and operating costs greater than those included in customer prices. As indicated above, application of the Company’s PCAM could help mitigateand have an 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.



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.

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TableThe cost to comply with potential GHG emissions reduction requirements is subject to significant uncertainties, including those related to: i) the timing of Contentsthe 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.



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 system load 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.

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.


ECONOMIC, FINANCIAL, AND MARKET RISKS

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

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

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 thermalgenerating 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 Company’s results of operations.

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


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


Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under PGE’s defined benefit pension plan.and other postretirement plans. 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.plans. Additionally, changes in interest rates affect PGE’s liabilities under the pension plan.plans. 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.


DevelopmentMarket prices for power and natural gas are subject to forces that are often not predictable and that 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 alternative technologiesoperations.

As part of its normal business operations, PGE purchases and sells power and natural gas in the open market under short- and long-term contracts, which may negatively impactspecify 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 valueadequacy of PGE’s generation facilities.

A basic premisegenerating capacity, scheduled and unscheduled outages 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 thermalhydroelectric and wind generation facilities. Suchlevels, 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 development could limitdeterioration 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 future growth opportunitiesexisting purchased power and limit growth in demand for PGE’s electric service.

Failure of PGE’s wholesale suppliersnatural gas agreements, PGE may be required to perform their contractual obligationsprovide increased collateral, which could adversely affect the Company’s abilityliquidity. 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 deliver electricityrecover 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.

BUSINESS AND OPERATIONAL RISKS

The spread of COVID-19 could have a material adverse effect on PGE’s business.

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide. Measures to control the spread of COVID-19 have affected the demand for the products and services of many businesses in PGE’s service territory and disrupted supply chains around the world. Due to COVID-19, PGE has observed an increase in past due accounts and late customer payments resulting in incremental bad debt expense of $8 million in 2020 that has been deferred pursuant to the OPUC’s COVID-19 deferral. PGE has also observed a change in the trend of customer demand with an increase in residential usage as customers stay at home and a decrease in commercial usage due to COVID-19 related closures and economic conditions. Although these trends have not had a material impact on the Company to date, management believes that these trends will continue and the full scope and extent of the impacts of COVID-19 on the Company’s costs.operations remains uncertain and depends on multiple variables. PGE continues to monitor the impacts of the COVID-19 pandemic on its workforce, liquidity, capital markets, reliability, cybersecurity, customers, and suppliers, along with overall macroeconomic conditions. Although the Company cannot predict with certainty the full extent of the COVID-19 pandemic’s impact on its business, a protracted slowdown of broad sectors of the economy, changes in demand for commodities, or significant changes in legislation or regulatory policy to address the COVID-19 pandemic could ultimately result in a significant reduction in demand for electricity in PGE’s service territory, increased late customer payments or uncollectible

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accounts, and the inability of the Company’s contractors, suppliers, and other business partners to fulfill their contractual obligations, any of which could have, or continue to have, a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Changes in tax laws may have an adverse impact on the Company’s financial position, results of operations, and cash flows.

PGE reliesmakes 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 suppliersthe Company’s financial condition and results of operations.
PGE owns and operates wind generating facilities, which generate federal production tax credits (PTCs) that PGE uses to deliver natural gas, coal,reduce its federal tax obligations. The amount of PTCs earned depends on the level of electricity output generated and electricity, in accordance with short-the applicable tax credit rate. A variety of operating and long-term contracts. Failure of suppliers to comply with such contractseconomic parameters, including adverse weather conditions and equipment reliability, could significantly reduce the PTCs generated by the Company’s wind facilities resulting in a timely manner could disruptmaterial 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.
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 ability to deliverresults 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 require PGE to incur additional expensesdamage the Company’s transmission and distribution system.

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

Reduced river flows can adversely affect generation from hydroelectric resources and unfavorable wind conditions can similarly affect wind generating resources. 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 complyreplace energy expected from these sources with both existing and new environmental laws related to fish and wildlifehigher cost power from other facilities or with wholesale market purchases, which could adversely affect PGE’shave an adverse effect on results of operations.


APGE derives a significant portion of PGE’s totalits 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 snowpack levels affect river flows and the resulting amount of energy requirementgenerated 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 supplied withdependent upon wind conditions. Unfavorable wind conditions could require increased reliance on power generated from the Company’s thermalgenerating resources or power purchases in the wholesale market, both of which could have an adverse effect on results of operations.

Although the application of the PCAM could help mitigate adverse financial effects from any decrease in power provided by hydroelectric and wind generating resources. Operationresources, full recovery of these facilitiesany increase in power costs is subjectnot
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assured. Inability 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 resultedfully recover such costs in significant operational changes to these projects. Salmon recovery plansfuture prices 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 couldhave a negative 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 meeton the Company’s energy requirements.

PGE could be vulnerable to cyber security attacks, data security breaches, actsresults 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,a reduction in renewable energy credits and operates systems that directly impact the availabilityloss 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 vulnerablePTCs related 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 bewind generating resources.

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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, earthquakes, wildfires, 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 could be vulnerable to cybersecurity 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 cybersecurity attacks, data security breaches, acts of terrorism, or other similar events that could disrupt operations or result in the release of sensitive or confidential information. Such events could cause a shutdown of service or expose PGE to liability. In addition, the Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches. PGE maintains insurance coverage against some, but not all, potential losses resulting from these risks. However, insurance may not be adequate to protect the Company against liability in all cases. In addition, PGE is subject to extensive regulationthe risk that affectsinsurers will dispute or be unable to perform their obligations to the Company.

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 operationscost 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.

Development of alternative technologies may negatively impact the value of PGE’s generation facilities.
A basic premise of PGE’s business is the ability to produce electricity at competitive prices due to economies of scale. Many companies and costs.organizations conduct research and development activities to seek improvements in alternative technologies and distributed generation. It is possible that advances in such technologies, or other current technologies, will reduce the cost of alternative methods of electricity production to a level that is equal to or below that of existing generation facilities. Such a development could limit the Company’s future growth opportunities and limit growth in demand for PGE’s electric service.


The inability to attract and retain a qualified workforce, including senior management talent, and to maintain satisfactory collective bargaining agreements without prolonged labor disruptions, may adversely affect PGE’s results of operations.

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PGE’s workforce includes a diverse mix of skilled professional, managerial and technical employees, including employees represented under collective bargaining agreements. Workforce management risks include the risk of turnover due to demographic challenges as employees approach retirement age. PGE also faces competition from other employers for key skills and experience within the industry or local geography. The Company also faces the risk of labor disruption due to the outcomes of labor negotiations or the possibility that employees not currently subject to collective bargaining agreements may organize.

PGE is subjectbusiness activities are concentrated in one region and future performance may be affected by events and factors unique to Oregon.

The Company’s industry and geographic concentrations may increase exposure to risks arising from regional regulation or legislation, such as legislative action related to carbon emissions. These concentrations may also increase exposure to credit and operational risks due to counterparties, suppliers, and customers being similarly affected 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.changing conditions.

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, 20172020 (in MW):
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FacilityLocation
Net
Capacity (1)
Wholly-owned:
Natural Gas/Gas or Oil:
BeaverClatskanie, Oregon509508 
MW
CartyBoardman, Oregon437438 
Port Westward Unit 1 (PW1)Clatskanie, Oregon411
Coyote SpringsBoardman, Oregon249
Port Westward Unit 2 (PW2)Clatskanie, Oregon225
Wind:
Biglow CanyonSherman County, Oregon450
Tucannon RiverColumbia County, Washington267
Hydro:WheatridgeMorrow County, Oregon100 
North ForkHydro:Clackamas River58
FaradayNorth ForkClackamas River4658 
Oak GroveFaradayClackamas River4546 
River MillOak GroveClackamas River2545 
River MillClackamas River25 
T.W. SullivanWillamette River18
Jointly-owned (2):
Coal:
Boardman Colstrip (3)
Boardman, OregonColstrip, Montana518296 
Hydro:
Colstrip Round Butte (4)
Colstrip, MontanaDeschutes River296230 
Hydro:
Round Butte (5)Pelton (4)
Deschutes River23073 
Pelton (5)
Deschutes River73
Net capacity3,8573,439 
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.

(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)Net capacity reflects PGE’s ownership share.
(3)PGE has a 20% ownership interest in the facility, which is operated by Talen Montana, LLC. The Company operated, and continues to have a 90% ownership interest in, Boardman, which ceased coal-fired operations during the fourth quarter of 2020.
(4)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 an2020, PGE-owned electric transmission system consistingconsisted of 1,2501,269 circuit miles as follows: 287 circuit miles of 500 kV line; 402414 circuit miles of 230 kV line; and 561568 miles of 115 kV line. The Company also has 27,45727,939 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
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•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•4,045 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 17,19, 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.
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)NYSE under the ticker symbol “POR”. As of February 2, 2018,10, 2021, there were 752653 holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $41.40per 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.
stock.
  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 PGEthe Company 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 readFor information with respect to securities authorized for issuance under equity compensation plans, see Note 14, Stock-Based Compensation in conjunction with Item 7.—“Management’s Discussion and Analysis ofthe Notes to Consolidated Financial Condition and Results of Operations” andStatements in Item 8.—“Financial Statements and Supplementary Data.”

Share repurchase program

On February 17, 2021, the Company’s Board of Directors authorized a share repurchase program, under which the Company is authorized to repurchase up to $17.5 million of its outstanding common stock through 2022. The share repurchase program may be limited or terminated at any time without prior notice. Under the share repurchase program, the Company may repurchase shares of common stock from time to time in open market transactions or in privately negotiated transactions as permitted under applicable rules and regulations. The extent to which the Company repurchases its shares of common stock and the timing of such purchases will depend upon market conditions and other considerations as may be determined in the Company’s sole discretion. Repurchases may also be made pursuant to a trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, which would permit shares to be repurchased when the Company might otherwise be precluded from doing so because of self-imposed trading blackout periods or other regulatory restrictions. The Company intends to finance any repurchases under the share repurchase program using cash on hand.

 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 operations376
 333
 309
 293
 206
Net income187
 193
 172
 174
 104
Net income attributable to Portland General Electric Company187
 193
 172
 175
 105
Earnings per share—basic2.10
 2.17
 2.05
 2.24
 1.36
Earnings per share—diluted2.10
 2.16
 2.04
 2.18
 1.35
Dividends declared per common share1.340
 1.260
 1.180
 1.115
 1.095
Statement of Cash Flows Data:         
Capital expenditures514
 584
 598
 1,007
 656
ITEM 6.     [REMOVED AND RESERVED]
29
 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 debt2,426
 2,350
 2,193
 2,489
 1,905
Total capital lease obligations51
 54
 —
 —
 —
Total Portland General Electric Company shareholders’ equity2,416
 2,344
 2,258
 1,911
 1,819
Common equity ratio49.4% 49.4% 50.7% 43.4% 48.9%
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ITEM 7.
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 such forward-looking statements include:
•governmental policies, legislative action, 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;
•changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered ESSs or community choice aggregators;
•the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 17,19, 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
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•complications arising from PGE’s jointly-owned generating facilities, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs;
•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 whichthat could require PGE to post additional collateral or 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, andor industrial customer growth, and inor 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•cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, and transmission, or distribution 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;the ability to recruit and retain appropriate talent;
•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;results;
•political and economic conditions;
•natural disasters and other risks, such as pandemic, earthquake, flood, drought, lightning, wind, and fire;
•the impact of widespread health developments, including the global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social, and other activities), which could materially and adversely affect, among other things, demand for electric services, customers’ ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;
•changes in financial or regulatory accounting principles or policies imposed by governing bodies; and
•acts of war or terrorism.terrorism; and

•the impact of the recommendations on the Company and its operations based on the review conducted by the Special Committee relating to energy trading losses, the time and expense incurred in implementing the recommendations of the Special Committee, and any reputational damage to the Company relating to the matters underlying the Special Committee’s review.

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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.


OverviewOVERVIEW


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 2018would 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 engagesengaged in the generation, transmission, distribution, and retail sale of electricity to retail customers within in its approved service territory in the Statestate of Oregon. In addition, the Company purchases and sells electricity inOregon, as well as 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 outputpurchase and sale of renewable resources. PGE also purchases wholesaleelectricity and natural gas in order to meet the United States and Canada to fuelneeds of its generating portfolio and sells excess

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gas back into the wholesale market.retail customers. 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 causecustomers in its service territory. In addition, 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 conditioningCompany participates 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 *
 
Residential762,211
 7,880
 752,365
 7,348
 7.2 %
          
Commercial (PGE sales only)107,364
 6,932
 106,460
 6,932
 — %
     Direct Access491
 623
 313
 525
 18.7 %
Total Commercial107,855
 7,555
 106,773
 7,457
 1.3 %
          
Industrial (PGE sales only)199
 2,943
 195
 2,968
 (0.8)%
     Direct Access68
 1,340
 63
 1,198
 11.9 %
Total Industrial267
 4,283
 258
 4,166
 2.8 %
          
Total (PGE sales only)869,774
 17,755
 859,020
 17,248
 2.9 %
     Total Direct Access559
 1,963
 376
 1,723
 13.9 %
Total870,333
 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,by purchasing and current wholesale prices, the Company continuously makes economic dispatch decisionsselling electricity and natural gas 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

Energy Trading

PGE is exposed to meet the Company’s retail load requirement can vary from period to period.

Plant availabilitycommodity price risk as its primary business 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 levelselectricity to its retail customers. The Company expects to manage commodity price volatility within net variable power costs by engaging in energy trading activities. The Company does not intend to engage in trading activities for non-retail purposes.

PGE personnel entered into a number of annual maintenance, which is generally performedenergy trades during 2020, with increasing volume accumulating late in the second quarter and into the third quarter, resulting in significant exposure to the Company. In August 2020, a portion 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%energy trading positions in 2016 and 65% in 2015.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projectsPGE’s energy portfolio experienced significant losses as wholesale electricity prices increased 8% in 2017 compared to 2016,substantially at various market hubs due to more favorable hydroextreme weather conditions, constraints to regional transmission facilities, and changes 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 includedpower supply in the Company’s AUT in 2016,West. During this time period, the CAISO declared a Stage 3 Electrical Emergency and fell short of projections by 7% in 2015. Such projections, which are finalized withordered 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 projectedfirst rolling blackouts in the AUT generally displaces power from higher cost sources. See “Purchased power and fuel” in the 2017 Compared to 2016 sectionstate of Results of Operations in this Item 7, for further detail on regional hydro results.California since 2001.


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 creditsconvergence of these conditions, the Company’s energy portfolio experienced realized losses of $127 million on these positions in 2020. PGE determined the energy trading positions that led to the losses were outside the Company’s acceptable risk tolerances, and the Company will not pursue regulatory recovery of the associated losses. PGE will also exclude the impacts of the realized losses from its regulatory earnings tests. The increase in net variable power costs due to this trading activity has been recognized in PGE’s results of operations. PGE no longer has net market exposure from the energy trading positions that led to these losses.

PGE and its external consultants have not materializedperformed a full operational review of the Company’s energy supply risk management policies, procedures and personnel. In addition, the PGE Board of Directors formed a Special Committee comprising five independent Board members to review the energy trading that led to the losses and the Company’s procedures and controls related to the trading, and to make recommendations to the Board for appropriate action. The Special Committee retained independent legal advisors. On December 18, 2020, PGE announced that the Special Committee concluded its independent review of the energy trading activity that led to the losses incurred in the third quarter of 2020. The Special Committee concluded that the trades were ill-conceived and revealed opportunities for improving the Company’s energy trading policies and practices. Additionally, the Board of Directors concluded that the actions the Company began taking in August to enhance oversight of energy trading and associated risk management reporting, policies, and practices were consistent with the Special Committee’s recommendations and will be monitored by the Board of Directors through enhanced reporting. These actions are expected to strengthen the Company and include:
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•Added expertise: PGE brought in additional experienced risk management personnel and replaced the Power Operations general manager with a new leader;
•Strengthened trading policies: Power Operations personnel are operating under revised policies designed to prevent positions of the type that led to the losses. The improved policies place controls on the ability of personnel to enter into wholesale energy transactions to the extent contemplated in the Company’s prices.that PGE does not have physical or financial delivery capability;

•Enhanced risk reporting: Energy trading activity reporting has been improved to ensure greater visibility into portfolio risk;
Pursuant•Changed reporting structures: Energy Trading Risk Management now reports through a Risk and Compliance team that reports 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,Chief Executive Officer. Effective January 1, 2021, Power Operations reports to the extent such difference is outsideVice President of a pre-determined “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. ToStrategy, Regulation and Energy Supply; and
•Changed personnel: The individuals who previously were placed on leave are no longer with 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 toCompany.


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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 agreementregarding legal proceedings associated 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 liabilitiesmatter, see “Shareholder Lawsuits” 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 17,19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


Clean Power Plan—COVID-19 Impacts

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions. In August 2015, the EPA releasedstate of Oregon, the Governor issued an executive order on March 23, 2020 directing Oregon residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact was difficult or impossible to avoid. This order was rescinded May 14, 2020 in a new executive order announcing a phased approach for reopening Oregon’s economy. The subsequent phased reopening approach has not allowed all businesses to reopen, or has allowed reopening only at reduced capacity to meet requirements for social distancing. The continued loosening of restrictions is contingent upon the successful reduction of cases.

Retail loads—The slowdown in certain sectors of the economy due to COVID-19 and the initial stay-at-home order and subsequent phased reopening plans has resulted in changes in retail load patterns. See “Customers and Demand” and “Decoupling” in this Overview section and “Revenues” of the Results of Operations section for more information related to COVID-19 impacts on retail loads and Revenues, net.

Bad debt expense—The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. PGE’s bad debt expense was $15 million for the full-year 2020, compared to an original $6 million forecast, subject to deferral. See “Administrative and other” of the Results of Operations section for more information related to COVID-19 impacts on bad debt expense, and see “Legislative and regulatory developments” within this Overview section for more information regarding regulatory deferrals of incremental costs associated with the COVID-19 pandemic.

Financial condition and liquidity—Global capital markets have experienced significant volatility in response to COVID-19 and PGE continues to assess the impact of this volatility on its liquidity position and capital investment plans. The Company believes the combination of its revolver capacity, proceeds of a $150 million, 364-day term loan, issued in April 2020, and proceeds from $200 million and $230 million FMB issuances, in April and November 2020, respectively, will continue to provide adequate liquidity for the Company’s operational needs. The Company continues to evaluate its five-year capital plan. A detailed discussion of capital market and capital investment responses is included in the Liquidity and Capital Resources section of this Item 7.

The COVID-19 pandemic did not have a material impact on PGE’s financial condition and cash flows in 2020 and the Company continues to have sufficient liquidity to meet the Company’s anticipated capital and operating
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requirements going forward. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital.

Supply chain—The global nature of the COVID-19 pandemic has resulted in supply chain disruptions and in some instances construction interruptions, although PGE has not experienced significant supply chain disruptions or construction interruptions to date. The Company’s business continuity plans have included an assessment of critical operational supply chain linkages and an assessment of potential interruptions to its capital project execution. The Company will continue to monitor supply chain issues, including possible force majeure notices, for any material impacts to its operations.

Business continuity plans—In February 2020, as more information about the potential impacts of COVID-19 became available, the Company activated its business continuity plans. These plans are designed to ensure the safety of the public and employees while the Company continues to provide critical service to its customers. In addition to directing employees to work from home when appropriate, the Company has implemented safeguards for employees who play critical roles to ensure operational reliability and established protocols for employees who interact directly with the public. The Company has enacted extra physical security and cybersecurity measures to safeguard systems to serve operational needs, including those of its remote workforce, and to ensure uninterrupted service to customers. The Company will continue to evolve its business continuity plans to follow guidance from the Centers for Disease Control and the Oregon Health Authority. Although PGE has plans in place to address workforce availability, including sequestration of key employees if necessary, the Company has not experienced workforce availability issues to date. Implementation of PGE’s business continuity plans have not had a material impact on PGE’s results of operation.

Legislative and regulatory developments—The Company has analyzed available relief for the economic effects of COVID-19 under the following:
•FERC Waiver—On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative allowance for funds used during construction (AFDC) calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction. PGE adopted the waiver in the second quarter of 2020 and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC. The Company continues to monitor for potential extensions of the waiver beyond the original 12-month period.
•Coronavirus Aid, Relief, and Economic Security (CARES) Act—On March 27, 2020, the U.S. Government enacted the CARES Act, which provides economic relief and stimulus to support the national economy during the COVID-19 pandemic and includes support for individuals, large corporations, small business, and health care entities, among other affected groups. The Company has not experienced direct material benefits from the CARES Act.
•COVID-19 Deferral—PGE filed an application for deferral of certain incremental costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral, but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted OPUC Staff’s motion to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final rule, which it callsstipulations for the Clean Power Plan (CPP). UnderTerm Sheet approved on November 3, 2020. As of December 31, 2020, PGE has deferred $8 million related to bad debt expense, and $2 million for other incremental costs associated with COVID-19 under the Term Sheet. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable.
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Amortization of any deferred costs will remain subject to OPUC review prior to amortization and inclusion in customer prices. Although PGE expects its 2020 regulated ROE, after adjusting for certain energy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final rule, each statedetermination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s 2020 deferral being disallowed for recovery. Such disallowance would havebe recognized as a charge to earnings.

Company Strategy

PGE is committed to continuing to achieve steady growth and returns as the Company transforms to meet the challenges of climate change and an ever-evolving energy grid. Customers, policy makers, and other stakeholders expect PGE to reduce GHG emissions, keep the carbon intensitypower grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company’s strategy strives to balance these interests. PGE plans to:
•Reduce GHG emissions associated with the power served to customers by 80% by 2030 (2010 baseline year), and setting an aspirational goal for zero GHG emissions associated with the power served to customers by 2040;
•Electrify sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and
•Perform as a business, driving improvements to work efficiency, safety of our coworkers, and reliability of our systems and equipment all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on average.

Decarbonize the power supply—PGE partners with customers and local and state governments to advance a clean energy future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help the state meet its GHG emission reduction goals. In addition to state greenhouse gas reduction goals, PGE announced in 2020 a new company wide goal of achieving net zero GHG emissions by 2040. PGE also announced a new goal to meet customer expectations for clean energy, pledging to reduce GHG emissions associated with the power sectorserved to customers by 80% by 2030 (2010 baseline year).

To reach these goals, PGE will focus on the following areas:

Customer Choice Programs—PGE’s customers continue to express a state-wide basiscommitment to purchasing clean energy, as over 230,000 customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by an amount specifiedparticipation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area continue to consider similar goals.

In response, the Company has implemented a new customer product option, the Green Future Impact program, which allows for 100 MW of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the EPA. The rule established state-specificOPUC in the first quarter 2019, the program will provide business customers access to bundled renewable attributes from those resources. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system.

Pursuant to the OPUC order approving the Green Future Impact tariff, program subscribers remain cost of service customers, and pay both the cost of service tariff price and the price under the renewable energy option tariff. This structure 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 theavoid stranded costs and benefits associated with coal-fired generation in theircost shifting.

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Carbon Legislation and Administrative Actions—In 2016, SB 1547 set a benchmark for how much electricity must come from renewable sources like wind and solar and requires the elimination of coal from Oregon retail rates afterutility customers’ energy supply no later than 2030 (subject to an exception that extendsallows extension of this date until 2035 for PGE’s output from the Colstrip facility)Colstrip). 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

Other provisions of the Colstrip facility from 2042 to 2030, as required under the legislation.

Future effects under the new law include:
an•An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
a•A limitation on the life of renewable energy certificatesRenewable Energy Credits (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 lineonline before December 31, 2022; and
an•An allowance for energy storage costs in itsrelated to 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”energy in the Regulation sectionCompany’s RAC filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery 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 driversPGE’s investment in the electricity sector might impactColstrip facility from 2042 to 2030. In January 2020, the existing regulatory systemowners of Colstrip Units 1 and incentives.2 permanently retired those two units. Although PGE has no direct ownership interest in Units 1 and 2, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2.

Although PGE is actively working on this initiative, both internallycurrently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in conjunctiontheir respective jurisdictions. In its most recent depreciation study filed with the OPUC in January 2021, PGE proposed to accelerate depreciation on Colstrip generation assets through 2027. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of earlier closure of these facilities.

Any reduction in generation from Colstrip has the potential to provide guidance and support developmentcapacity on the Colstrip transmission facilities, which stretches from eastern Montana to near the western end of the report. The OPUC recently openedstate to serve markets in the Pacific Northwest and beyond. PGE has a proceeding to collect input15% ownership interest in, and capacity on, possible changes to the regulatory modelColstrip Transmission facilities. Renewable energy development in the state of Montana could benefit from stakeholders including regulated utilities such as PGE.any excess transmission capacity that may become available.


SenateAs previously planned, in October 2020, PGE ceased coal-fired operation at Boardman and has begun decommissioning activities.

During the 2019 Oregon legislative session, House Bill 1070—The State of Oregon legislators(HB) 2020 was introduced, which would 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 throughauthorized a statewidecomprehensive cap and trade program. This will be discussedpackage in Oregon and would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted in 2019, an amended version was reintroduced in the 35-day legislative session, thatwhich began in February. February 2020. This new proposal, SB 1530, was also a cap and trade package that included changes made to address concerns raised by various parties. Prior to the legislative session, the OPUC stated that it would continue to collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority was limited to that of an economic regulator.

The short 2020 legislative session adjourned without action on SB 1530 and, as a result, in March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions. Many of the direct agency actions are on an aggressive timeline with due dates in 2020 and 2021. As the Governor is limited by current statutory authority, the executive order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in the 2019 and 2020 legislative sessions.

Among other things, the executive order:
•Modified the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050;
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•Directed state agencies to integrate climate change and the State’s GHG emissions reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law;
•Directed the OPUC to—
◦determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon’s reduction goals;
◦encourage electric companies to support transportation electrification infrastructure that supports GHG emission reductions and zero emission vehicle goals; and
◦prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy;
•Directed the Oregon Department of Environmental Quality to adopt a program would setto cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas; and
•More than doubled the reduction goals of the state’s Clean Fuels Program and extended the program, from the previous rule that required a statewide cap on greenhouse gas emissions10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

The Resource Planning Process—PGE’s planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. This process includes consideration of customer expectations and legislative mandates to move away from fossil fuel generation and toward renewable sources of energy.

In May 2018, the Company issued a request for proposals seeking to procure approximately 100 MWa of qualifying renewable resources. The prevailing bid was Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage.

PGE now owns 100 MW of the wind resource, which was placed into service in the fourth quarter of 2020 at a cost of $149 millionand qualified for PTCs at the 100 percent level. Subsidiaries of NextEra Energy Resources, LLC own the balance of the 300 MW wind resource, along with the solar and battery components, and will sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to increase its ownership to include the entire facility in 2032.

Construction of the solar and battery components is reduced over timeplanned for 2021 and would require about 100 companies, includingis also expected to qualify for federal investment tax credits. PGE did not experience any supply chain disruptions due to acquire permits for the greenhouse gas emissions they produce.COVID-19 pandemic related to the construction of Wheatridge, and the solar and battery portions of the project are proceeding as planned. PGE continues to work closely with the contractor to actively monitor for supply chain issues. See “COVID-19 Impacts” within this Overview section for further information on COVID-19.

On May 6, 2020, the statusOPUC issued an order that acknowledged the Company’s 2019 IRP and the following Action Plan for PGE to undertake over the next four years to acquire the resources identified:
•Customer actions—
◦Seek to acquire all cost-effective energy efficiency; and
◦Seek to acquire all cost-effective and reasonable distributed flexibility.
•Renewable actions—Conduct a Renewables Request for Proposals (RFP) seeking up to approximately 150 MWa of this proposed legislation.new RPS-eligible resources that contribute to meeting PGE’s capacity needs by the end of 2024,with the following conditions, among others:

◦Resources must qualify for PTCor the federal Investment Tax Credit;
Recovery
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◦Resources must pass the cost-containment screen; and
◦The value of Utility License Fees—In May 2011,RECs generated prior to 2030 must be returned to customers.
•Capacity actions—Pursue dispatchable capacity through the cityfollowing concurrent processes:
◦Pursue cost-competitive, bilateral contract agreements for existing capacity in the region; and
◦Conduct an RFP for non-emitting dispatchable resources that contribute to meeting PGE’s capacity needs.

The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of Gresham, Oregon (Gresham), which is within PGE’s service territory, adoptedcapacity contribution by 2025 from a resolutioncombination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage. As PGE implements the Action Plan, the Company will continue to increase utility license fees from 5%evaluate present and ongoing resource needs and timing of any related RFP in light of the economic disruption related to 7%, effective July 1, 2011. The Company believed that these utility license fees met the definition of privilege taxes within the Oregon statutesCOVID-19. PGE expects to issue an RFP for both renewable energy 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 capacity resources.

PGE and Douglas County Public Utility District entered an agreement during 2020 to supply the Company ceased collectingadditional capacity from Gresham customersfacilities including the incremental 2% tax. Gresham appealedWells Hydroelectric Project, located on the MultnomahColumbia River in central Washington. The agreement also provides Douglas County Circuit Court decision toPUD with PGE load management and wholesale market sales services. With a start date of January 1, 2021, 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, whichagreement is expected to begincontribute between 100 and 160 MWs toward a capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company’s stated goal of providing customers with a clean energy future.

PGE filed an IRP Update with the OPUC in January 2021 seeking acknowledgement so that it may incorporate the updated resource cost and value information in PURPA QF avoided cost pricing. No changes were proposed to the 2019 IRP Action Plan in the firstIRP Update. However, based on the updated capacity need forecast reflecting the addition of the agreement with the Douglas County PUD and more sophisticated modeling, the updated capacity need in 2025 is 511 MW.

Renewable Recovery Framework—As previously authorized by the OPUC, the RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. Although no significant filings were made under the RAC during 2020, the Company did submit a RAC filing for Wheatridge in the fourth quarter of 2018.2019. On September 29, 2020, the OPUC issued an order in response to PGE’s RAC filing that stated PGE’s decision to proceed with Wheatridge was prudent and authorized cost recovery of, and return on, the facility in customer prices once service to PGE's customers began, in the fourth quarter 2020.


Other Regulatory MattersElectrify other sectors of the economy—PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:
•The use of electricity in more applications such as electric vehicles and heat pumps;
•The integration of new, geographically-diverse energy markets;
•The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation;
•The development of connected neighborhood microgrids and smart communities; and
•The use of data and analytics to better predict demand and support energy saving customer programs.

In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support
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functions. As of December 31, 2020, the Company has recorded $109 million, including AFDC, in construction work-in-progress related to the IOC.

The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044, which establishes Oregon's zero emissions vehicle goals in statute at 250 thousand vehicle sales by 2025 and 90% of all vehicle sales by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State’s carbon reduction goals.

In 2018, PGE filed an energy storage proposal that called for 39 MW of storage to be developed over the next several years at various locations across the grid. In August 2018, the OPUC issued an order that outlined an agreed approach to the development of five energy storage projects by PGE with an expected capital cost of approximately $45 million.

Perform as a business—PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion highlightsprovides detail on several such material matters.

Wildfire—In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE’s wildfire mitigation planning includes regular risk assessment. On September 7, 2020 PGE proactively initiated a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as the region at highest risk of wildfire. In addition to the PSPS region, PGE cut power to eight different high-risk fire areas. These actions were coordinated with emergency responders and helped clear the path for them to fight wildfires. During this time, PGE also established a community resource center within the PSPS zone to help support the residents affected. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment. PGE will incur costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs. As of December 31, 2020, PGE deferred$15 million in costs related to wildfire response. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. Although PGE expects its 2020 regulated ROE, after adjusting for certain regulatory items that have impactedenergy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s revenues, resultsprudently incurred costs were in response to the unique and unprecedented nature of operations,the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or cash flowsall, of PGE’s 2020 deferral being disallowed for 2017 compared with 2016, or have affected retail customer prices,recovery. Such disallowance would be recognized 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.a charge to earnings.


Power Costs—Pursuant to the AUT process, PGE annually 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 wasAs approved by the OPUC, with an expected reductionthe 2020 AUT included a final increase in annual revenues of $31 million. This amount was includedpower costs for 2020, and a corresponding increase 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 $10of $27 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 includedfrom 2019 levels, which were reflected in customer prices effective January 1, 2020. See “Power Operations” within this Overview section of Item 7 for more information regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor Superfund site. As of December 31, 2020, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, projected the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. However, the Company does not currently have sufficient information to
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reasonably estimate the amount, or range, of its potential costs for 2017, and a corresponding reduction in annual revenue requirement,investigation or remediation 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 partPortland Harbor, although such costs could be material to PGE’s financial position. The impact of its 2018 GRC, PGE included an initial projected reduction in powersuch costs of $29 million that was included in the overall request submitted to the OPUC.Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, in December 2017, the 2018 GRC included a final projected reduction in power costs for 2018Company’s environmental recovery mechanism allows the Company to defer and a corresponding reduction in annual revenue requirement, of $40 million from 2017 levels.

Renewable Resource Costs—Pursuantrecover incurred environmental expenditures related to the RAC mechanism, PGE can recover inPortland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and customer prices, prudentlyas necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. Under the PHERA mechanism in 2020, PGE incurred and deferred $6 million related to defense costs, net an estimated refund of renewable resources thatless than $1 million as a result of the regulated earnings test. PGE’s results of operations may be impacted to the extent such expenditures are expected to be placeddeemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in serviceNote 19, Contingencies in the current year.Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

City of Portland Audit—In 2019, the city of Portland (the “City”), which is the largest city within PGE’s service territory, completed its audit of PGE’s and the City’s mutual License Fees agreement for the 2012 through 2015 periods. The preliminary claim by the City is that PGE improperly excluded certain items from the calculation of gross revenues, which resulted in underpayment of franchise taxes of $7 million, including interest and penalties. PGE disagreed with the preliminary findings as they were not consistent with previous audit conclusions, which found that the Company may submithad appropriately calculated gross revenues in determining franchise fees. In December 2020, PGE and the City reached a filingsettlement for less than $1 million that covered the audit periods from 2012 to 2018.

Capital Project Deferral—In the second quarter of 2018, PGE placed into service a new customer information system at a total cost of $152 million. In accordance with agreements reached with stakeholders in the Company’s 2019 GRC, the Company’s capital cost of the asset was included in rate base and customer prices as of January 1, 2019.

Consistent with past regulatory precedent, in May 2018, the Company submitted an application to the OPUC by April 1 each year,to defer the revenue requirement associated with prices expectedthis new customer information system from the time the system went into service through the end of 2018. As a result, PGE began deferring its incurred expenses, primarily related to become effective January 1depreciation and amortization, of the following year. As partnew customer information system once it was placed in service.

In 2017, the OPUC had opened docket UM 1909 to conduct an investigation of the RAC, the OPUC has authorizedscope of its authority under Oregon law to allow the deferral of eligible costs not yet includedrelated to capital investments for later inclusion in customer prices untilprices. In October 2018, the January 1 effective date. No significant filings have been submittedOPUC issued Order 18-423 (1909 Order) concluding that the OPUC lacked authority under Oregon law to allow deferrals of any costs related to capital investments. In the RAC during 2017, 2016, or 2015.1909 Order, the OPUC acknowledged that this decision was contrary to its past limited practice of allowing deferrals related to capital investments and would require adjustments to its regulatory practices. The OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of this decision, and to propose recommendations needed to implement this decision consistent with the OPUC’s legal authority and the public interest.


During 2018, PGE deferred a total of $12 million of expenses related to the customer information system. However, the 1909 Order impacted the probability of recovery of deferred expenses and, as such, the Company recorded a reserve for the full amount of the costs related to the customer information system. The reserve was established with an offsetting charge to the results of operations in 2018.

In response to the 1909 Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the 1909 Order with the Oregon Court of Appeals, although the Court has indicated that the case would be dismissed given the lack of recent action in the case.

On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility’s capital projects, including both depreciation expense and the cost of financing capital projects. PGE
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believes that the costs incurred to date associated with the customer information system were prudently incurred; however, PGE intends to file to close the deferral proceeding related to the customer information system without further action at the OPUC.

Decoupling Mechanism—The decoupling mechanism, whichauthorized by the OPUC has authorized through 2019,2022, 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 refund of $15 million and a collection of $13$9 million duringfrom residential and commercial customers, respectively for the year ended December 31, 2017,2020, which resulted from variances between actual weather-adjusted use per customer and that projected in the 20162019 GRC. The Company continues to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2020, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2022. The Company reached its 2020 annual cap for collection from commercial customers during the third quarter of 2020. No cap exists for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which for 2017 stood at $18 million.have largely offset the revenue increases that have resulted from higher residential demand. Any collection from customers for the 20172020 year is expected to occur over a one-year period, which would begin January 1, 2019.2022.


The CompanyAt December 31, 2019, PGE had recorded an estimateda total collection of $3$14 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, 2016that will occurbe collected over a one-year period, which began January 1, 2018.2021.


Corporate Activity Tax—In 2019, the state of Oregon enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million and applies to tax years beginning on or after January 1, 2020. The $9tax applies to commercial activities sourced in Oregon, less a deduction for 35% of the greater of “cost inputs” or “labor costs.” The resulting amount is taxed at 0.57%.

In January 2020, at PGE’s request, the OPUC issued an order approving a tariff and related deferral and balancing account to provide for an estimated recovery of $7 million in customer prices in 2020. The Company will revisit the expected tax consequences annually and revise the annual tariff accordingly. Pursuant to the order, PGE started collections in customer prices February 1, 2020. For the year ended December 31, 2020, PGE incurred $8 million under the tax.

Non-utility Asset Retirement Obligation (ARO)—PGE’s Non-utility ARO represents the liability that has been recognized for portions of unregulated properties that are currently or previously leased to third parties and located adjacent to PGE’s T.W. Sullivan hydro generating facility. In 2020, PGE performed a decommissioning study to update its ARO liability which resulted in a $21 million increase to non-utility property AROs. Additions in non-utility AROs related to assets that are no longer in service are charged directly to Depreciation and amortization on the consolidated statements of income in the period in which the revisions are probable and reasonably estimable. As a part of this study, the Company also established an additional ARO liability of $3 million related to utility properties that was charged to Depreciation and amortization expense. PGE plans to pursue regulatory recovery for the utility portion of the ARO update, however, as of December 31, 2020, no amounts have been deferred as a regulatory asset. For further information regarding the Company’s AROs, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Deferral of Boardman Revenue Requirement—In October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with Boardman currently
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included in customer prices as established in the Company’s last general rate case. The application states a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. PGE estimates this amount could be up to $14 million for the period ended December 31, 2020. As of December 31, 2020, PGE has not recorded a regulatory liability pursuant to this deferral application as the Company believes its current prices are just and reasonable in 2015light of PGE’s continued substantial investments in utility plant. The costs of these investments, which are not currently reflected in customer prices, more than offsets the revenue requirement for Boardman. If the OPUC authorizes the deferral, PGE would record a regulatory liability with a corresponding charge to earnings.

2021 Storm— Beginning on February 11, 2021, an historic set of storms involving heavy snow, winds, and ice impacted the United States, including PGE’s service territory. Significant damage across the State of Oregon led Oregon’s Governor to call a state of emergency on February 13, 2021. PGE’s restoration efforts in response to this historic set of storms are ongoing and the total costs of the storm cannot be reasonably estimated, although such costs could be material to its results of operations in 2021. Given the magnitude of the impacts to PGE’s transmission and distribution system, on February 15, 2021 PGE filed a deferral application with the OPUC for potential recovery of restoration costs, however, there is no assurance that resultedsuch recovery would be granted by the OPUC.
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Operating Activities

In combination with electricity provided by its own generation portfolio, to meet its retail load requirements and balance its energy supply with customer demand, PGE purchases and sells electricity in the wholesale market. PGE also participates in the CAISO western EIM, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.

The Company generates revenues and cash flows primarily from variances between actualthe sale and distribution of electricity to its retail customers. The impact of seasonal weather adjusted useconditions 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 experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. See “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” for further information regarding seasonal fluctuations. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—The following tables present total energy deliveries and the average number of retail customers by customer type for 2020 and 2019.
Energy deliveries (MWh in thousands)20202019% Increase/
(Decrease)
Retail:
     Residential7,756 7,471 3.8 %
     Commercial (PGE sales only)6,222 6,653 (6.5)
          Direct Access633 665 (4.8)
     Total Commercial6,855 7,318 (6.3)
     Industrial (PGE sales only)3,446 3,181 8.3 
          Direct Access1,486 1,490 (0.3)
     Total Industrial4,932 4,671 5.6 
     Total (PGE sales only)17,424 17,305 0.7 
          Total Direct Access2,119 2,155 (1.7)
     Total retail energy deliveries19,543 19,460 0.4 %
Wholesale energy deliveries5,794 4,669 24.1 
     Total energy deliveries25,337 24,129 5.0 %

Average number of retail customers20202019% Increase
Residential791,119 88 %779,673 88 %1.5 %
Commercial110,290 12 109,521 12 0.7 
Industrial194 — 193 — 0.5 
Direct access634 — 632 — 0.3 
Total902,237 100 %890,019 100 %1.4 %

In 2020, retail energy deliveries increased 0.4% from 2019. While results for the first quarter largely reflected conditions prior to the COVID-19 pandemic, the remainder of the year was influenced by customer behavioral response to the pandemic.
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On March 23, 2020, the Governor of Oregon issued an order directing residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact would be difficult or impossible to avoid. The Company saw a shift in retail demand in response, beginning with the second quarter of 2020. In particular, residential loads increased as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in an attempt to maintain social distancing or have closed as a result of the lack of business as residents followed directives from state and federal authorities. Although the industrial class as a whole experienced an increase in energy deliveries for 2020, this was due primarily to continued growth in the high-tech and digital services sectors, which saw lesser impacts from noted closures than other sectors.

Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 3.8% higher in 2020 than 2019, due to a 2.3% increase in average usage per customer and that projecteda 1.5% increase in the 2015 GRC, occurred during 2017. Similarly, a refundaverage number of customers. Residential deliveries, down 6% in the first quarter driven by mild temperatures, were up 9% in the second quarter of 2020 due largely to the impact of the $5 million recordedCOVID-19 pandemic and have remained strong through the balance of the year.

Commercial energy deliveries declined 6.3% overall with widespread decreases across PGE’s customer base led by several sectors most impacted by COVID-19 related closures and economic conditions, including: government and education; offices, finance, insurance, and real estate; and restaurants and lodging.

The 5.6% increase during 2014 occurred2020 in industrial energy deliveries is due to continued strength in the high-tech manufacturing sector as well as a full-year of demand from a large paper facility that reopened during 2016.2019, after having closed in late 2017.


Storm Restoration Costs—BeginningIn 2020, the Company’s service territory experienced warmer temperatures during the heating season than in 2011,2019, indicating lower demand for heating, the OPUC authorizedeffect of which was partially offset by having slightly warmer temperatures during the Companysummer cooling season and increased demand for cooling.

Total heating degree-days, an indication of electricity use for heating, in 2020 were 7% below the 15-year average and down 8% from total heating degree-days in 2019. Total cooling degree-days, a similar indication of the extent to collect $2 million annuallywhich customers are likely to have used electricity for cooling, in 2020, exceeded the 15-year average by 12% and were 6% above the 2019 total. The following table presents the number of heating and cooling degree-days in 2020 and 2019, along with the current 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries:

 Heating Degree-DaysCooling Degree-Days   
 2020201915-Year Average2020201915-Year Average
1st quarter1,761 1,992 1,848 — — — 
2nd quarter554 467 636 99 102 89 
3rd quarter47 83 78 492 462 447 
4th quarter1,474 1,623 1,583 9 — 2 
Total3,836 4,165 4,145 600 564 538 
Increase (decrease) from the 15-year average(7)%— %12 %5 %

On a weather-adjusted basis, total retail deliveries increased 1.5% from 2019. The increase was driven by 6.3% growth in residential deliveries and 5.6% growth in industrial energy deliveries, which were somewhat offset by a decrease in commercial energy deliveries of 6.0%. Retail energy deliveries for 2021 will continue to be impacted by COVID-19 related behavioral changes. PGE projects that retail energy deliveries for 2021 will be approximately
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1.0% - 1.5% above 2020 weather-adjusted levels, reflecting strength in industrial deliveries, and impacts associated with COVID-19 early in the year, and unwinding of such impacts later in the year.

ESSs supplied Direct Access customers with energy representing 11% of the Company’s total retail energy deliveries during 2020 and 2019. 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 2020, and 2019. With the adoption of the New Large Load Direct Access program in 2020, as much as 19% of the Company’s energy deliveries could have been supplied by ESSs.

Energy efficiency and conservation efforts by retail customers to cover incremental expenses related to major storm damages,influence demand, although the financial effects of such efforts by residential and to defer

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any amount not utilized in the current year. The 2018 GRC, as approvedcertain commercial customers are mitigated by the OPUC, increases the annual collection amountdecoupling mechanism, which is intended to $3 million, beginning in 2018.

Asprovide for recovery of margin lost as a result of a series of storm eventsreduction in electricity sales attributable to energy efficiency and conservation efforts. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than the projected baseline set in the first halfCompany’s most recent approved general rate case. See “Decoupling” in this Overview section of 2017,Item 7, for further information on the decoupling mechanism.

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 exhaustedcontinuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the $2 million storm collection authorized for 2017. Consequently, PGE was exposedUnited States and Canada to fuel its generating portfolio and sells excess gas back into the incremental costs related to such major storms events, which totaled $11 million during 2017, lesswholesale market. As a result, the amount collectedof power generated and purchased in 2017. During 2015the wholesale market to meet the Company’s retail load requirement can vary from period to period and 2016,impacts NVPC and income from operations.

The following table provides information regarding the performance of the Company’s generation portfolio.
 
Plant availability (1)
Actual energy provided compared to projected levels (2)
Actual energy provided as a percentage of total retail load
 202020192020201920202019
Thermal:
Natural gas92 %92 %74 %86 %43 %45 %
Coal (3)
99 87 83 104 17 24 
Wind94 96 117 90 11 9 
Hydro86 93 71 81 7 8 
(1)Plant availability represents the percentage of the year plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability excludes Colstrip, which PGE fully used the reserve balancedoes not operate. Colstrip availability was 74% in 2020, compared with 85% in 2019. Boardman ceased coal-fired generation on October 15, 2020.

Energy received from PGE-owned and jointly-owned thermal plants decreased12% in 2020 compared to 2019, primarily as a result of restorationa 27% reduction in generation from coal-fired generation, which produced only 13% of the Company’s total system load in 2020. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs associated with storm damage occurringto run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during those years.the second quarter of the year.


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Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 12% in 2020 compared to 2019. While energy received from mid-Columbia hydroelectric projects increased 46% in 2020, the energy generated by the Company-owned facilities decreased 14%. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See “Purchased power and fuel” in the Results of Operations section in this Item 7, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 28% in 2020 compared to 2019, due to more favorable wind conditions in 2020 and the addition of Wheatridge during the fourth quarter 2020. Energy expected to be received from Biglow Canyon and Tucannon River is projected annually in the AUT based on historical generation. 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 additional costs incurred, duringgeneration increase, a larger amount of PTCs were produced in 2020 than in 2019 and exceeded what was contemplated in the first quarter of 2017, PGE filed an applicationCompany’s prices.

For Wheatridge, wind generation studies were used to develop NVPC cost forecasts, which were included in the RAC filing for the facility, and included in customer prices when the facility went into service. The RAC tariff included NVPC in 2020 along with the OPUC requesting authorization to defer incremental storm restoration costs from the dateall other aspects of the application throughrevenue requirement. Beginning January 1, 2021, the end of 2017. NetNVPCs were included in the Company’s AUT, although the other aspects 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 OPUCRAC tariff will ultimately rule on this application. Asremain in effect until they are included in customer prices as a result of a future general rate case.

Under the PCAM, PGE may share with customers a portion of cost variances 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, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no deferral has beenless than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2020, and 2019:

•For 2020, actual NVPC, excluding certain trading losses totaling $127 million, was below baseline NVPC by $13 million, which was within the established deadband range, so no estimated refund to customers was recorded as of December 31, 2017.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—In July 2016,2020. A final determination regarding the Company filed an application with2020 PCAM results will be made by 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,public filing 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 withreview in 2021. If actual NVPC for 2020 included the U.S. Tax Cuts and Jobs Act—On December 29, 2017, PGE filed withcertain trading losses, it would have been $114 million above 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” ofbaseline. See “Energy Trading” in the Overview section of this Item 7. for further information regarding certain trading losses.

•For 2019, actual NVPC was above baseline NVPC by $5 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2019. A final determination regarding the 2019 PCAM results was made by the OPUC through a public filing and review in 2020, which confirmed no refund to customers pursuant to the PCAM for 2019.

The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $27 million increase was expected in 2020 over 2019. The 2021 AUT anticipates a $79 million increase in NVPCs that will be recovered in customer prices beginning January 1, 2021.

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, netTotal revenues 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
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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):

 Years Ended December 31,% Increase (Decrease)
 20202019
 AmountAmount
Total revenues (1)
$2,145 $2,123 1 %
Purchased power and fuel (1)
708 614 15 
Gross margin1,437 1,509 (5)
Other operating expenses:
Generation, transmission and distribution293 323 (9)
Administrative and other283 290 (2)
Depreciation and amortization454 409 11 
Taxes other than income taxes138 134 3 
Total other operating expenses1,168 1,156 1 
Income from operations269 353 (24)
Interest expense, net (2)
136 128 6 
Other income:
Allowance for equity funds used during construction16 10 60 
Miscellaneous income, net6 6 — 
Other income, net22 16 38 
Income before income taxes155 241 (36)
Income tax (benefit) expense— 27 (100)
Net income$155 $214 (28)%
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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 margin1,417
 70
 1,306
 68
 1,237
 65
Other operating expenses:           
Generation, transmission and distribution309
 16
 286
 15
 266
 14
Administrative and other264
 13
 247
 13
 241
 13
Depreciation and amortization345
 17
 321
 16
 305
 16
Taxes other than income taxes123
 6
 119
 6
 116
 6
Total other operating expenses1,041
 52
 973
 50
 928
 49
Income from operations376
 18
 333
 18
 309
 16
Interest expense, net (2)
120
 6
 112
 6
 114
 6
Other income:           
Allowance for equity funds used during construction12
 1
 21
 1
 21
 1
Miscellaneous income, net5
 —
 1
 —
 1
 —
Other income, net17
 1
 22
 1
 22
 1
Income before income taxes273
 13
 243
 13
 217
 11
Income tax expense86
 4
 50
 3
 45
 2
Net income$187
 9% $193
 10% $172
 9%
            
(1) AsGross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Consolidated Statements of IncomeIncome.
(2) Includes an allowance for borrowed funds used during construction of $6$8 million in 2017, $112020 and $5 million in 2016, and $13 million in 2015.2019.





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2020 Compared to 2019

Net income - The following items contributed to the change in Net income for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions):

Year ended December 31, 2019$214 
Purchased power and fuel expense related to certain trading losses*(127)
Purchased power and fuel expense, excluding certain trading losses*43 
Other operating revenues primarily from the resale of excess natural gas used for fuel in 2019 that did not recur in 2020(17)
Average retail price predominately due to increase under the AUT for NVPC37 
Retail deliveries, net of decoupling deferral(11)
Wholesale revenues driven by lower average sale prices(8)
Late fee revenue due largely to COVID-19 related curtailments(6)
Generation, transmission and distribution expenses driven by lower plant maintenance30 
Administrative and general expenses due largely to lower wages and benefits9 
Non-utility ARO due to revised estimates(21)
Depreciation and amortization resulting largely from capital additions(11)
Income taxes resulting primarily from lower pre-tax income27 
Other(4)
Year ended December 31, 2020155 
Change in Net income$(59)
*See “Energy Trading” in the Overview section of Contentsthis Item 7.—”Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding certain trading losses.



Revenues, energy deliveries (presented in MWh), and average number of retail customersTotal revenues consist of the following for the years presented:presented (in millions):
20202019% Increase (Decrease)
Retail: (1)
Residential$1,030 $981 5 %
Commercial616 636 (3)
Industrial218 196 11 
Direct Access46 44 5 
Subtotal1,910 1,857 3 
Alternative revenue programs, net of amortization(6)2 (400)
Other accrued revenues, net (2)
28 22 27 
Total retail revenues1,932 1,881 3 
Wholesale revenues162 170 (5)
Other operating revenues51 72 (29)
Total revenues$2,145 $2,123 1 %
 Years Ended December 31,
 2017 2016 2015
Revenues(1) (dollars in millions):
           
Retail:           
Residential$969
 48% $907
 47% $895
 47 %
Commercial669
 33
 665
 35
 662
 35
Industrial212
 11
 208
 11
 228
 12
Subtotal1,850
 92
 1,780
 93
 1,785
 94
Other accrued (deferred) revenues, net10
 1
 3
 —
 (10) (1)
Total retail revenues1,860
 93
 1,783
 93
 1,775
 93
Wholesale revenues105
 5
 103
 5
 88
 5
Other operating revenues44
 2
 37
 2
 35
 2
Total revenues$2,009
 100% $1,923
 100% $1,898
 100 %
            
Energy deliveries(2) (MWh in thousands):
           
Retail:           
Residential7,880
 34% 7,348
 33% 7,325
 33 %
Commercial7,555
 33
 7,457
 33
 7,511
 34
Industrial4,283
 19
 4,166
 19
 4,546
 21
Total retail energy deliveries19,718
 86
 18,971
 85
 19,382
 88
Wholesale energy deliveries3,193
 14
 3,352
 15
 2,560
 12
Total energy deliveries22,911
 100% 22,323
 100% 21,942
 100 %
            
Average number of retail customers:           
Residential762,211
 88% 752,365
 88% 742,467
 88 %
Commercial107,855
 12
 106,773
 12
 105,802
 12
Industrial267
 —
 258
 —
 255
 —
Total870,333
 100% 859,396
 100% 848,524
 100 %
            

(1)
(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$18 million for 2017, 2016,2020 and 2015, respectively.2019. Industrial revenues from ESS customers were $20 million, $15$28 million and $16$26 million for 2017, 2016,2020 and 2015,2019, respectively.
(2)
Includes both energy soldAmounts for the years ended December 31, 2020 and 2019 are primarily comprised of $24 million and $23 million of amortization, respectively, including interest, related to retail customers and energy deliveriesthe net tax benefits due to those commercial and industrial customers that purchase their energy from ESSs. Commercial deliveries to ESS customers,the change 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: 1,340in 2017;1,198 in 2016; and 1,177 in 2015.
corporate tax rate under the TCJA.

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PGE’s sources of energy, total system load, andTotal retail load requirement forrevenues—The following items contributed to the years presented are as follows:
 Years Ended December 31,
 2017 2016 2015
Sources of energy (MWh in thousands):           
Generation:           
Thermal:           
Natural gas6,228
 28% 5,811
 27% 4,783
 22%
Coal3,344
 15
 3,492
 16
 4,128
 19
Total thermal9,572
 43
 9,303
 43
 8,911
 41
Hydro1,774
 8
 1,629
 8
 1,453
 7
Wind1,641
 8
 1,912
 9
 1,788
 8
Total generation12,987
 59
 12,844
 60
 12,152
 56
Purchased power:           
Term7,192
 33
 6,961
 32
 7,364
 35
Hydro1,648
 7
 1,541
 7
 1,572
 7
Wind264
 1
 301
 1
 303
 2
Total purchased power9,104
 41
 8,803
 40
 9,239
 44
Total system load22,091
 100% 21,647
 100% 21,391
 100%
Less: wholesale sales(3,193)   (3,352)   (2,560)  
Retail load requirement18,898
   18,295
   18,831
  
            

Net income increase in Total retail revenues for the year ended December 31, 2017 was $187 million, or $2.10 per diluted share,2020 compared with $193 million, or $2.16 per diluted share, forto the year ended December 31, 2016. The $6 million, or 3%, decrease2019 (dollars in net income resulted primarily from the net impact of the following three items: i) Gross margin increased due to higher energy demand, primarily due to weather and strength in the industrial sector; ii) Operating expense increased due to higher depreciation expense as a result of asset base growth, several storms in 2017 that increased restoration expenses, higher administrative and general expenses due to increases in employee count, and additional litigation and interest expense related to Carty; and iii) Income tax expense increased due to higher pre-tax income, the impacts of the TCJA, and lower PTCs.millions):


Net income for the year ended December 31, 2016 was $193 million, or $2.16 per diluted share, compared with $172 million, or $2.04 per diluted share, for the year ended December 31, 2015. The $21 million, or 12%, increase resulted in part from lower net variable power costs than what was reflected in revenues in the Company’s 2016 AUT. Purchased power and fuel costs decreased as the region experienced better hydro conditions in 2016 than in 2015, as well as improved wind generation, which also produced more PTCs. Average variable power cost per MWh declined 8% from 2015 and a 31% increase in the volume of wholesale energy sales also helped to reduce net variable power costs. Retail revenues increased only slightly as continued expansion in the average number of customers served and price changes authorized in the 2016 GRC were largely offset by the influences of weather and energy efficiency measures. Incremental depreciation expense related to the higher than planned construction cost of Carty, which were not covered in customer prices, as well as legal expenses related to litigation associated with the termination of the Carty Construction Agreement, along with higher storm and service restoration costs in 2016 somewhat countered the other improvements in net income.
Year ended December 31, 2019$1,881 
Retail energy deliveries driven by higher industrial demand, the impact of COVID-19 resulting in higher residential demand, and the negative effects of weather8 
Average price of energy deliveries due primarily to the AUT and the variation in usage among customer classes resulting from COVID-1927 
Combination of various supplemental tariffs and adjustments, the largest of which were $11 million that pertains to the demand response pilot programs, $8 million related to Boardman decommissioning, and $7 million for the Oregon Commercial Activities Tax24 
Alternative revenue programs related to the decoupling mechanism deferrals due to increased residential use per customer resulting from COVID-19(19)
     Amortization of prior year decoupling deferrals into customer prices11 
Year ended December 31, 20201,932 
Change in Total retail revenues$51 



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2017 Compared to 2016

Revenues increased $86 million, or 4.5%, in 2017 compared with 2016 as a result of the items discussed below.

Total retail revenues increased $77 million, or 4.3%, in 2017 compared with 2016, primarily due to the net effect of:
A $71 million increase due to a 3.9% increase in retail energy deliveries consisting of a 7.2% increase in residential deliveries, a 2.8%increase in industrial deliveries, and a 1.3% increase in commercial deliveries. Considerably cooler temperatures in the first half of 2017 than experienced in 2016 combined with warmer temperatures in the summer cooling season in 2017, both drove deliveries higher in 2017 than in 2016. For further information on customer demand, see “Customers and Demand” in the Overview section of this Item 7;
A $10 million increase resulting from the Decoupling mechanism, as an estimated $13 million collection was recorded in 2017; and
A $5 million increase, directly offset in Depreciation and amortization expense, related to the accelerated cost recovery of Colstrip, partially offset by
A $5 million reduction as a result of overall price changes, which includes a $55 million reduction in revenues attributable to lower NVPC, as filed in the 2017 AUT; and
A $3 million decrease due to higher customer credits related to the USDOE settlement in connection with operation of the ISFSI at the former Trojan nuclear power plant site. Such credits are directly offset in Depreciation and amortization expense.

Total heating degree-days in 2017 were above the 15-year average and considerably greater than total heating degree-days in 2016. Total cooling degree-days in 2017 exceeded the 15-year average by 49% and were considerably higher than 2016. The following table presents the number of heating and cooling degree-days in 2017 and 2016, along with the 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries:
 Heating Degree-Days Cooling Degree-Days   
 2017 2016 15-Year Average 2017 2016 15-Year Average
1st quarter2,171
 1,585
 1,867
 —
 —
 —
2nd quarter686
 403
 689
 129
 154
 70
3rd quarter78
 78
 78
 571
 394
 399
4th quarter1,623
 1,486
 1,599
 —
 —
 2
Total4,558
 3,552
 4,233
 700
 548
 471
Increase (decrease) from the 15-year average8% (16)%   49% 16%  
            

On a weather-adjusted basis, total retail energy deliveries in 2017 were 0.6% below 2016 levels. PGE projects that retail energy deliveries for 2018 will be nearly comparable to slightly lower than 2017 weather-adjusted levels, reflecting the closure of a large paper customer in late 2017 as well as continued energy efficiency and conservation efforts.

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


In 20172020, an $8 million, or 5%, the $2 million, or 2%, increasedecrease from 2019 in wholesale revenues resulted from 2016 consisted of a $7$49 million increase that resulted asdecrease from a 7% increase23% decrease in average prices was received when the Company sold power into the wholesale market, partially offset by a $5$41 million decreaseincrease related to 5% lessa 24% increase in wholesale sales volume.

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Other operating revenues increased $7decreased $21 million,, or 19%29%, in 20172020 from 2016,2019, primarily as a result of a $17 million decrease predominately resulting from market conditions that provided less revenue from the saleresale of excess natural gas not used to fuelback into the wholesale market in excess of amounts needed for the Company’s generating facilities accounted forgeneration portfolio. Natural gas prices were considerably higher in the majorityfirst quarter of 2019 as a result of a supply pipeline disruption in the region. Milder than average winter temperatures in North America in 2020 resulted in an oversupply of natural gas and lower prices. In addition, a $6 million decrease occurred due to the curtailment of late fees as a result of the increase.COVID-19 pandemic.



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Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. In 2017,

The following items contributed to the increase in Purchased power and fuel expense decreased $25 million, or 4%, from 2016, which was driven by a $38 million, or 6%, decline relatedfor the year ended December 31, 2020 compared to the decreaseyear ended December 31, 2019 (dollars in themillions, except for average variable power cost per MWh to $26.80 in 2017 from $28.50 in 2016, partially offset by a $13MWh):

Year ended December 31, 2019$614 
Average variable power cost per MWh62 
Total system load32 
Year ended December 31, 2020$708 
Change in Purchased power and fuel$94 
Average variable power cost per MWh:
Year ended December 31, 2019$26.62 
Year ended December 31, 2020$29.14 
Total system load (MWh in thousands):
Year ended December 31, 201923,085
Year ended December 31, 202024,286

For the year ended December 31, 2020, the $62 million increase resulting from a 2% increase in total system load.

The decrease related to the change in average variable power cost per MWh, was primarily driven primarily by: i) a 7% reductionby an 8% increase in the average variable power cost per MWh for purchased power, as the Company, on average, purchased power at lower market prices; and ii) a 13% reduction in the average variable power cost per MWh related to energy received from the Company’s natural gas-fired resources due to lower natural gas prices. This was partially offset by a 14% decrease on the purchase of replacement power due to 14% less energy received fromaverage cost for the Company’s wind generating resources.

own generation. The net increase in the cost of purchased power was driven by realized losses of $127 million related to a portion of energy trading positions in PGE’s energy portfolio. See “Energy Trading” in the Overview section of this Item 7., for more details. The $32 million increase related to total system load was driven primarily by higher customer demand as a result of the impacts of weather. Energy obtained from the Company’s natural gas-fired resources increased 7% due largely to Carty being in service the full year and energy obtained from the Company’s hydro resources increased 9% due to more favorable hydro conditions. Energy obtained from purchased power increased 3% in response to higher system load, as well as the purchase of replacement energy due to a reduction35% increase in energy received from the Company’s wind generating resources.

In 2017, energy received from Biglow Canyonpurchased power, driven by economic dispatch decisions based on lower gas prices and Tucannon River decreased14% from 2016 due to less favorable wind conditions, and provided 9% of the Company’s retail load requirement in 2017 compared with 10% in 2016. As a result of improvedsurplus hydro conditions in the region for 2017,region.

PGE’s sources of energy, received from PGE-owned hydroelectric projects in combination with mid-Columbia projects was 8% above 2016 levels,total system load, and represented 18% of the Company’s retail load requirement for 2017 compared with 17% for 2016.the years presented are as follows:

 Years Ended December 31,
 20202019
Sources of energy (MWh in thousands):
Generation:
Thermal:
Natural gas8,029 33 %8,342 36 %
Coal3,232 13 4,416 19 
Total thermal11,261 46 12,758 55 
Hydro1,204 5 1,407 6 
Wind2,111 9 1,706 8 
Total generation14,576 60 15,871 69 
Purchased power:
Term contracts7,741 32 5,882 25 
Hydro1,535 6 1,048 5 
Wind434 2 284 1 
Total purchased power9,710 40 7,214 31 
Total system load24,286 100 %23,085 100 %
Less: wholesale sales(5,794)(4,669)
Retail load requirement18,492 18,416 
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The following table presents the actual April-to-September 20172020 and 20162019 runoff at particular points of major rivers relevant to PGE’s hydro resources:
Runoff as a Percent of 30-year Average
Location2020
Actual		2019
Actual
Columbia River at The Dalles, Oregon104 %94 %
Mid-Columbia River at Grand Coulee, Washington109 87 
Clackamas River at Estacada, Oregon75 114 
Deschutes River at Moody, Oregon86 111 

 Runoff as a Percent of 30-year Average
Location
2017
Actual
 
2016
Actual
Columbia River at The Dalles, Oregon98% 89%
Mid-Columbia River at Grand Coulee, Washington98
 91
Clackamas River at Estacada, Oregon97
 71
Deschutes River at Moody, Oregon98
 91

Actual NVPC, whichconsists of Purchased power and fuel expense net of Wholesale revenues, decreased $27increased $102 million in 20172020 compared with 2016.2019. The decreaseincrease attributable to changes in Purchased power and fuel expense was the result of a6% decline9% increase in the average variable power cost per MWh offset slightly byand a 2%5% increase in total

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system load. The decrease in actual NVPC was also driven by a 7% increase inIn addition, wholesale energy deliveries decreased $8 million from the net of 23% lower average price per MWh of wholesale power sales,sold, partially offset slightly by a 5% decrease24% increase in the volume of wholesale energy deliveries as a greater portion of its system load was used to meet retail load requirements, largely duedeliveries.

The following items contributed to the effects of weather.increase in Actual NVPC for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions):


For 2017, actual NVPC, as calculated for regulatory purposes under the PCAM, was $15 million above the 2017 baseline NVPC. In 2016, NVPC was $10 million below the anticipated baseline.
Year ended December 31, 2019$444 
Purchased power and fuel expense94 
Wholesale revenues8 
Year ended December 31, 2020546 
Change in NVPC$102 

For further information regarding NVPC in relation to the PCAM, see “Power Operations” in the Overview section of this Item 7.


Generation, transmission, and distribution expense increased $23

The following items contributed to the $30 million or 8%,9% decrease in 2017Generation, transmission and distribution for the year ended December 31, 2020 compared with 2016. The increase was driven by the combination of $10 million in higher costs due to the additionyear ended December 31, 2019 (in millions):

Year ended December 31, 2019$323 
Decrease primarily due to lower maintenance expense as the result of reduced run hours and lower long-term service agreement costs at some of the Company’s generation facilities(20)
Lower utilization of contract labor and higher capitalization rates(8)
Miscellaneous expenses(2)
Year ended December 31, 2020293 
Change in Generation, transmission and distribution$(30)

For the year ended December 31, 2020, PGE deferred $15 million of Carty,incremental costs related to wildfires in PGE’s service territory. See “Wildfires” within“Perform as a business” under “Company Strategy” in the Overview section of this Item 7., for more information.


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Administrative and other

The following items contributed to the $7 million or 2% decrease in Administrative and other for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions):

Year ended December 31, 2019$290 
Wage and benefits expenses(12)
    Bad debt expense5 
Year ended December 31, 2020283 
Change in Administrative and other$(7)

As of December 31, 2020, PGE has deferred $8 million higher service restoration and storm costs, $3 million higher plant maintenance expenses, and $2 million higher information technology expenses.of bad debt related to incremental expense incurred related to COVID-19 as part of the OPUC’s Energy Term Sheet. See the “Overview” section of this Item 7., for more information.


Administrative and other expense increased $17 million, or7%, in 2017 compared with 2016, primarily due to $12 million higher overall labor and employee benefit expenses and $3 million higher legal costs attributable to Carty.

Depreciation and amortization expense in 2017 increased $24

The following items contributed to the $45 million or 7%11%, compared with 2016. The increase was primarily driven by $26 million higher expense resulting from capital additions, offset by a $3 million reduction in expense due to higherDepreciation and amortization credits in 2017 of the regulatory liability for the ISFSI spent fuel settlement. The overall impact resulting fromyear ended December 31, 2020 compared to year ended December 31, 2019 (in millions):

Year ended December 31, 2019$409 
ARO revisions24 
Activity related to regulatory programs (offset in revenues)13 
Capital additions8 
Year ended December 31, 2020454 
Change in Depreciation and amortization$45 

See “Non-utility Asset Retirement Obligation Overview” within “Perform as a business” under “Company Strategy” in the amortizationOverview section of the regulatory assets and liabilities is directly offset by corresponding reductions in retail revenues.this Item 7., for more information regarding revisions made to non-utility AROs.


Taxes other than income taxes expense increased $4 million, or 3%, in 20172020 compared with 2016, driven by $2 million2019, primarily due to higher Oregon property taxes and $2 million higher payroll taxes.


Interest expense increased $8 million, or 7%6%, in 20172020 compared with 20162019 due to a $4 million decrease in the credits for the allowance for borrowed funds used during construction (primarily due to the Carty plant being placed in service in 2016) andhigher average balances of outstanding debt as well as increased expense of $3 million resulting from a 5% increase in the average balance of debt outstanding.interest on finance leases.


Other income, net was $17increased $6 million, or 38%, in 20172020 compared to $22 million in 2016,2019, with the decreasedifference due to higher AFDC equity driven by higher construction work-in-progress balances in 2020.

Income tax expense decreased $27 million, or 100%, in 2020 compared to 2019 primarily due to lower allowance for equity funds used during construction, which resulted from Carty being placed in service during 2016.

Income tax expense increased $36 million, or 72%, in 2017 compared to 2016. The change relates to a $13 million increase due to higher pre-tax income and $7 million due to lower productionin 2020, partially offset by higher expense from the Oregon Corporate Activity tax credits. Additionally, Income tax expense increased $17 million due to the remeasurement of deferred taxes pursuant to the change in corporate tax rates in the TCJA. For more information regarding the Company’s proposed deferral application, see the “Legal, Regulatory, and Environmental Matters” Section of this Item 7.which took effect on January 1, 2020.


20162019 Compared to 20152018


Revenues increased $25 million, or 1.3%, in 2016 compared with 2015 asFor a result of the items discussed below.

Total retail revenues increased $8 million, or 0.5%, in 2016 compared with 2015, primarily due to the net effect of:
A $49 million increase resulting from price changes, as authorized by the OPUC, including Carty going into service and into customer prices in mid-2016, as a resultcomparison of the Company’s 2016 GRC;
A $10 million increase resulting fromresults of operations for the Decoupling mechanism, as an estimated $3 million collection was recorded in 2016 compared to a refund in 2015;
A $5 million increase due to a lower amount of customer credits related to tax credits in connection with operation of the ISFSI at the former Trojan nuclear power plant site. Such credits are directly offset in depreciation and amortization expense; and
A $5 million overall increase due to various other largely offsetting tariff changes and adjustments; partially offset by
A $38 million decrease in revenues related to a 2.1% decrease in retail energy deliveries, consisting of 8.4% and 0.7% decreases in industrial and commercial deliveries, respectively, partially offset by a 0.3% increase in residential deliveries. See “Customers and Demand” in the Overview section of this Item 7. for further information on customer demand; and
A $23 million decrease relatedfiscal year ended December 31, 2019 to the collection from customers during 2015year ended December 31, 2018, see Item 7.—” Management’s Discussion and Analysis of costs associated with previous capital project deferrals, with no comparable collection in 2016. This decrease in revenues is largely offset by a comparable decrease in depreciationFinancial Condition and amortization expense.

Total heating degree-days in 2016 were lower than the 15-year average although somewhat greater than total heating degree-days in 2015. Total cooling degree-days in 2016 exceeded the 15-year average although were considerably less than the 2015 total. The following table presents the numberResults of heating and cooling degree-days in 2016 and 2015, along with the 15-year averages:

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 Heating Degree-Days Cooling Degree-Days
 2016 2015 15-Year Average 2016 2015 15-Year Average
1st quarter1,585
 1,481
 1,866
 —
 —
 —
2nd quarter403
 513
 689
 154
 207
 70
3rd quarter78
 76
 78
 394
 573
 399
4th quarter1,486
 1,391
 1,600
 —
 5
 2
Total3,552
 3,461
 4,233
 548
 785
 471
Increase (decrease) from the 15-year average(16)% (18)% 

 16% 67% 


On a weather-adjusted basis, retail energy deliveries in 2016 were 1.4% below 2015 although one large paper customer ceased operations in late 2015. On a comparable year over year basis, with the removal of the one large paper customer load from the 2015 year, the Company experienced weather-adjusted load growth of 0.9%.

Wholesale revenues in 2016 increased $15 million, or 17%, from 2015, with such increase consisting of $27 million related to 31% greater wholesale sales volume partially offset by a $12 million decrease related to 11% lower average wholesale market prices.

Other operating revenues increased $2 million, or 6%, in 2016 from 2015, primarily due to a $2 million increase in resale of unneeded natural gas in combination with several smaller, rather offsetting items including revenues from broadband fiber deployment and steam sales.

Purchased power and fuel expense in 2016 decreased $44 million, or 7%, from 2015, driven by a $51 million, or 8%, decline related to the decrease in the average variable power cost per MWh to $28.50 in 2016 from $30.91 in 2015, partially offset by a $7 million increase resulting from a 1% increase in total system load.

The decrease related to average variable power cost per MWh was driven primarily by a reduction in purchased power prices. The net increase in total system load was comprised of a $38 million, or 22%, increase due to energy generated from the Company’s natural gas-fired resources, offset by the combination of a $13 million, or 15%, decrease in energy generated from Company-owned coal-fired resources and an $18 million, or 5%, reduction in energy received from purchased power. The increase in natural gas-fired generation was due primarily to the replacement of energy received from higher cost resources and reflects the addition of Carty in July 2016.

In 2016, energy received from Biglow Canyon and Tucannon River increased 7% from 2015 due to more favorable wind conditions, and represented 10% of the Company’s retail load requirement in 2016 compared with 9% in 2015. As a result of improved hydro conditions in the region, energy received from PGE-owned hydroelectric projects and from mid-Columbia projects combined for 2016 was 5% above 2015 levels, and represented 17% of the Company’s retail load requirement for 2016 and 16% for 2015.

The following table presents the actual of the April-to-September runoff for 2016 and 2015:
 Runoff as a Percent of 30-year Average
Location
2016
Actual
 
2015
Actual
Columbia River at The Dalles, Oregon89% 69%
Mid-Columbia River at Grand Coulee, Washington91
 77
Clackamas River at Estacada, Oregon71
 53
Deschutes River at Moody, Oregon91
 85

Actual NVPC decreased $59 million for 2016 compared with 2015. The decrease attributable to changes in Purchased power and fuel expense was the result of an 8% decline in the average variable power cost per MWh, offset slightly by a 1% increase in total system load. The decrease in actual NVPC was also driven by a 31% increase in the volume of wholesale energy deliveries as the Company’s retail load requirement decreased in 2016, largely due to the effects of weather, which resulted in a greater portion of its system load being sold into the wholesale market. The increase was partially offset by an 11% decrease in the average price per MWh of wholesale power sales. The 2016 GRC had anticipated a decrease of approximately $31 million in NVPC from the 2015 baseline, with customer prices set accordingly. For 2016, actual NVPC, as calculated for regulatory purposes under the PCAM, was $10 million below the 2016 baseline NVPC, compared with $3 million below for 2015.

Generation, transmission, and distribution expense increased $20 million, or 8%, in 2016 compared with 2015. The increase was driven by the combination of $7 million in higher costs due to the addition of Carty, $5 million higher service restoration and storm costs, $4 million higher information technology expenses, $4 million higher inspection and testing costs for the distribution system, $2 million higher plant maintenance expenses, and $2 million higher labor expense. Partially offsetting the increases was a reduction in expenses of $6 million due to the repair and maintenance work during the annual planned outage and economic displacement of Boardman in 2015.

Administrative and other expense increased $6 million, or 2%, in 2016 compared with 2015, primarily due to $5 million higher legal costs attributable to Carty. The Company experienced slightly higher overall labor and employee benefit expenses although a $3 million reduction in pension expenses and a $2 million reduction in injuries and damages expense offset a large portion of those increases.

Depreciation and amortization expense in 2016 increased $16 million, or 5%, compared with 2015. The increase was primarily driven by $20 million higher expense resulting from capital additions, a $7 million expense increase resulting from the amortization credits in 2015 from gains recorded on the sale of assets, and a $5 million expense increase from lower amortization credits in 2016 of the regulatory liability for the ISFSI tax credits, offset by a $19 million expense decrease that resulted from the completion at the end of 2015 of the amortization of the regulatory asset related to the four capital projects deferral as authorizedOperations” in the Company’s 2011 GRC. The overall impact resulting fromAnnual report on Form 10-K for the amortization ofyear ended December 31, 2019, filed with the regulatory assets and liabilities is directly offset by corresponding reductions in retail revenues.SEC on February 14, 2020.


Taxes other than income taxes expense increased $3 million, or 3%, in 2016 compared with 2015, as higher property valuations in the State of Oregon increased taxes by $4 million, which was partially offset by lower property tax rates in both Oregon and Washington.

Interest expense decreased $2 million, or 2%, in 2016 compared with 2015 as $4 million lower expense resulted from a 3% decrease in the average balance of debt outstanding, partially offset by $2 million less allowance for borrowed funds used during construction credits.



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Other income, net was $22 million in both 2016 and 2015 and was comprised primarily of $21 million in the allowance for equity funds used during construction each year, driven by the construction of Carty.

Income tax expense increased $5 million, or 11%, in 2016 compared with 2015. Higher pre-tax income accounted for a $10 million increase, which was partially offset by a $3 million increase in production tax credits and a combination of state credits and tax deductions that reduced expense by $2 million.
Liquidity and Capital Resources


Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “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.” in Item 1A.—“Risk Factors,” for further information.


Capital Requirements


The following table presents actual capital expenditures and debt maturities for 20172020 and projected capital expenditures and future debt maturities for 20182021 through 20222025 (in millions, excluding AFDC):
 Years Ending December 31,
 2017 2018 2019 2020 2021 2022
Ongoing capital expenditures(1)
$462
 $535
 $444
 $451
 $440
 $450
Customer information system(2)
49
 16
 —
 —
 —
 —
Total capital expenditures$511
(3) 
$551
 $444
 $451
 $440
 $450
            
Long-term debt maturities$150
 $—
 $300
 $—
 $160
 $—
 Years Ending December 31,
 202020212022202320242025
Ongoing capital expenditures*
$568 $555 $550 $550 $550 $550 
Integrated Operations Center77 100 — — — — 
Wheatridge Renewable Energy Facility129 — — — — — 
Total capital expenditures$774 $655 $550 $550 $550 $550 
Long-term debt maturities$— $160 $— $— $80 $— 

(1)Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects.
(2)
Total capital expenditures for the customer information system through December 31, 2017 were $114million, excluding AFDC.
(3)Includes preliminary engineering and removal costs, which are included in other net operating activities in the consolidated statements of cash flows.

* Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects. Includes preliminary engineering and removal costs.

During 2020, PGE funded its capital expenditures through a combination of cash from operations in the amount of $567 million, net proceeds from the issuance of PCRBs and FMBs in the total amount of $451 million, and net short-term debt issuances in the amount of $150 million. Capital expenditures in 2021 are expected to be $655 million. PGE plans to fund the 2021 capital expenditures and long-term debt maturities with cash from operations during 2021, which is expected to range from $600 million to $650 million, the issuance of debt securities of up to $300 million, and the issuance of commercial paper, as needed. The actual timing and amount of any other issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.


Liquidity


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




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The following summarizes PGE’s cash flows for the periods presented (in millions):
 
 Years Ended December 31,
 20202019
Cash and cash equivalents, beginning of year$30 $119 
Net cash provided by (used in):
Operating activities567 546 
Investing activities(787)(604)
Financing activities447 (31)
Net change in cash and cash equivalents227 (89)
Cash and cash equivalents, end of year$257 $30 

 Years Ended December 31,
 2017 2016 2015
Cash and cash equivalents, beginning of year$6
 $4
 $127
Net cash provided by (used in):     
Operating activities597
 553
 520
Investing activities(514) (585) (522)
Financing activities(50) 34
 (121)
Net change in cash and cash equivalents33
 2
 (123)
Cash and cash equivalents, end of year$39
 $6
 $4
      

20172020 Compared to2016 2019


Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The $44$21 million increase in cash flows from operating activities in 20172020 compared to 2016 reflects that while2019 is due to:

•$59 million reduction in Net income was nearly comparable, adjustments to Net income to reconcile to net cash provided included increases of $33in 2020;
•$63 million for Deferred income taxes ($17 million of whichincrease related to Tax reform), $22additional contributions to the pension and other postretirement benefit plans in 2019 that did not recur in 2020;
•$45 million for Other non-cash income and expenses, and $24 million forincrease in Depreciation and amortization expense. Somewhat offsetting those increases were decreases of $28 million from Margin deposits outstandingprimarily due to changeshigher average plant balances and revision to non-utility AROs in prices2020. See the Overview section of powerthis Item 7., for more information regarding revisions made to non-utility AROs;
•$42 million increase for Accounts payable and other accrued liabilities primarily due to the timing of payments to vendors;
•$29 million increase in Other working capital, net primarily due to the use of materials and supplies and fuel underlying contracts with counterparties and $16inventory in the course of business; partially offset by
•$54 million decrease as a result of the Decoupling mechanism, which reflects both the current year deferralchanges in Accounts receivable and the refund to customersUnbilled revenue;
•$29 million decrease related to prior years.Deferred income taxes;

•$9 million decrease related to cash settlements for ARO liabilities; and
•$7 million decrease related to other miscellaneous items.

For additional information regarding changes in Net income, see the Results of Operations section in this Item 7.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 20182021 will range from $370$410 million to $380$430 million. Combined with all other sources, cash provided by operations in 20182021 is estimated to range from $575$600 million to $625$650 million.


As a result of the tax law changes made under the TCJA, PGE’s operating cash flows are generally expected to decrease in the future as customer prices will reflect lower income tax expense recoveries going forward, as well as refunds of the net benefits of changes in tax law under the TCJA, offset partially by the impacts of higher rate base over time. PGE expects that customer prices will be adjusted for the impacts of the TCJA as a part of the Company’s 2019 GRC. Currently, the Company does not believe this decrease in future operating cash flows will have a material impact on its future liquidity or credit ratings. 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.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. The $71$183 million decreaseincrease in net cash used in investing activities in 20172020 compared to 2016 waswith 2019 is primarily due to a decrease in Capital expenditures as Carty was placed into service in July 2016.theconstruction of Wheatridge and the IOC.
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The Company plans for approximately $551$655 million of capital expenditures in 20182021 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. PGE plans to fund the 20182021 capital expenditures with cash from operations during 2018,2021, as discussed above, as well as with the issuance of short- and long-term debt securities. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.


Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2017, cash used in financing activities consisted primarily of

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the issuance of $225 million of long-term debt, less the repayment $150 million of term loans and payment of dividends in the amount of $118 million. During 2016,2020, cash provided by financing activities consisted primarily of the issuance of $290 million of long-term debt less the repayment of $133$430 million of FMBs and $119 million of PCRBs, less the paymentremarketing of $98 million of PCRBs. In addition, the Company issued a $150 million short-term loan and paid dividends in the amount of $110$140 million.



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20162019 Compared to 20152018


Cash Flows from Operating Activities—The $33 million increase inFor a comparison of liquidity and capital resources and the Company’s cash flows from operatingflow activities in 2016 compared to 2015 was largely due to increases in net incomefor the fiscal year ended December 31, 2019 and depreciation expense, partly offset by the impact2018, see Item 7.—“Management’s Discussion and Analysis of changes in other non-cash incomeFinancial Condition and expense items including amounts recorded under the decoupling mechanism, and a decrease in margin deposits. The remaining non-cash income and expenses and other componentsResults of working capital were fairly consistent year over year.

Cash Flows from Investing Activities—The $63 million increase in net cash used in investing activities in 2016 compared to 2015 was primarily due to a distribution of $50 million from the Nuclear decommissioning trust and $23 million the Company received from a sales tax refund related to Tucannon River, both in 2015. Capital expenditures decreased $14 million as Carty was placed into service in July 2016. For additional information regarding the distribution from the Nuclear decommissioning trust, see Note 3, Balance Sheet Components, and Note 7, Asset Retirement Obligations,Operations” in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Cash Flows from Financing Activities—During 2016, cash provided by financing activities consisted ofCompany’s Annual Report on Form 10-K for the issuance of $290 million of long-term debt lessyear ended December 31, 2019, which was filed with the repayment $133 million of FMBs and dividends of $110 million. During 2015, cash used in financing activities consisted of repayments of long-term debt of $442 million and the payment of dividends of $97 million.

DividendsSEC on Common Stock

The following table presents common stock dividends declared in 2017:
Declaration Date  Record Date  Payment Date  
Declared Per
Common Share
February 15, 2017 March 27, 2017 April 17, 2017 $0.32
April 26, 2017 June 26, 2017 July 17, 2017 0.34
July 26, 2017 September 25, 2017 October 16, 2017 0.34
October 25, 2017 December 26, 2017 January 16, 2018 0.34
While the Company 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. On February 14, 2018, a common stock dividend of $0.34 per share was declared, payable April 16, 2018 to shareholders of record on March 26, 2018. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.2020.



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Credit Ratings and Debt Covenants


PGE’s secured and unsecured debt is rated investment grade by Moody’s and S&P, with current credit ratings and outlook as follows:
Moody’sS&P
First Mortgage BondsA1A-A
Senior unsecured debtA3BBBBBB+
Commercial paperP-2A-2
OutlookStablePositiveStable


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


As of December 31, 2017,2020, PGE had posted $42$20 million of collateral with these counterparties, consisting of $11$8 million in cash and $31$12 million in bank letters of credit, $11 million of which is related to master netting agreements.credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2017,2020, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $84$32 million and decreases to $14 millionzero by December 31, 2018 and $5 million by December 31, 2019.2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $175$122 million and decreases to $88$79 million by December 31, 20182021 and $64$72 million by December 31, 2019.2022.


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


The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs.
The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of
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Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2017,2020, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $1.1 billion$695 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.


PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65%65.0% of total capitalization (debt to total capital ratio). As of December 31, 2017,2020, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 51.8%56.4%.


Debt and Equity Financings


PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors.factors, such as the significant volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facilities,facility, the expected

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ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.


For 2018, PGE expects to fund estimated capital requirements with cash from operations, the issuance of debt securities of up to $100 million,and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures.

Short-term Debt—Pursuant to an order issued by the FERC on January 16, 2020, PGE has approval from the FERCauthorization to issue short-term debt up to a total of $900 million through February 6, 2020. 2022. The following table shows available liquidity as of December 31, 2020 (in millions):

December 31, 2020
CapacityOutstandingAvailable
Revolving credit facility (1)
$500 $— $500 
Letters of credit (2)
220 60 160 
Total credit$720 $60 $660 
Cash and cash equivalents257 
Total liquidity$917 
(1)Scheduled to expire November 2023.
(2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.

As of December 31, 2017,2020, PGE had a $500 million revolving credit facility scheduled to expire inNovember 2021.2023. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and for general corporate purposes. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility.


The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2020, PGE hadnocommercial paper outstanding.


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PGE typically classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets.


Under the revolving credit facility, as of December 31, 2017,2020, PGE hadno borrowings or commercial paper outstanding, and no commercial paper or letters of credit issued. As a result, as of December 31, 2017,2020, the aggregate unused available credit capacity under the revolving credit facility was $500 million.$500 million.


In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for ahas total capacity of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $67$60 million were outstanding as of December 31, 2017.2020.


On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bears interest for the relevant interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement is classified as Short-term debt on the Company’s consolidated balance sheets and expires on April 8, 2021, with any outstanding balance due and payable on such date.

Long-term Debt—During 2017,2020, PGE issued a total of $225$430 million of FMBs.

On April 27, 2020, PGE issued $200 million of 3.15% Series FMBs due in 2030.

On December 10, 2020, the Company issued to certain institutional buyers in the private placement market $230 million aggregate principal amount of the Company's FMBs that consisted of:

•a series, due in 2027, in the amount of $160 million that will bear interest from its issuance date at an annual rate of 1.84%; and

•a series, due in 2032, in the amount of $70 million that will bear interest from its issuance date at an annual rate of 2.32%.

Pollution Control Revenue Bonds—On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that bear an interest rate of 3.98%. PGE drew $752.125%, and $21 million aggregate principal of PCRBs that bear an interest rate of 2.375%, both due in August 2017 with2033. At the time of remarketing, the Company chose a maturity datenew interest rate period that was fixed term. The new interest rate was based on market conditions at the time of 2048 and drewremarketing. The PCRBs are backed by the remaining $150 million in November 2017 with a maturityCompany’s Indenture of 2047.Mortgage by way of FMBs. Interest is payable semi-annually on the PCRBs.


In 2017, PGE repaid three separate term loans drawn on an unsecured credit agreement under which it had borrowed $150 million from certain financial institutions. PGE repaid the loan as follows:
$50 million on August 21, 2017;

$25 million on October 30, 2017; and

$75 million on November 27, 2017.

As of December 31, 2017,2020, total long-term debt outstanding, net of $10$13 million of unamortized debt expense, was $2,426$3,046 million, of which none$160 million is scheduled to mature in 2018.2021.


Capital Structure—PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities)maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 49.4%45.0% and 49.9% as of December 31, 20172020 and 2016.2019, respectively.




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Contractual Obligations and Commercial Commitments


The following table presents PGE’s contractual obligations as of December 31, 20172020 (in millions):
 2018 2019 2020 2021 2022 
There-
after
 Total
Long-term debt$—
 $300
 $—
 $160
 $—
 $1,976
 $2,436
Interest on long-term debt (1)
123
 110
 104
 100
 99
 1,574
 2,110
Capital and other purchase commitments191
 2
 10
 2
 2
 58
 265
Purchased power and fuel:             
Electricity purchases156
 156
 201
 200
 187
 1,733
 2,633
Capacity contracts6
 5
 4
 4
 4
 8
 31
Public Utility Districts9
 17
 16
 16
 15
 85
 158
Natural gas51
 35
 28
 25
 24
 140
 303
Coal and transportation15
 5
 —
 —
 —
 —
 20
Pension Plan Contributions (2)
21
 17
 17
 18
 24
 —
 97
Capital leases7
 6
 6
 6
 5
 72
 102
Build-to-suit lease—
 15
 15
 14
 14
 260
 318
Operating leases9
 8
 6
 6
 8
 165
 202
Total$588
 $676
 $407
 $551
 $382
 $6,071
 $8,675
20212022202320242025There-
after		Total
Long-term debt$160 $— $— $80 $— $2,819 $3,059 
Interest on long-term debt (1)
126 124 124 124 121 1,806 2,425 
Capital and other purchase commitments237 33 20 1 1 55 347 
Purchased power and fuel:
Electricity purchases250 257 284 278 249 2,886 4,204 
Capacity contracts9 9 9 9 9 — 45 
Public Utility Districts21 19 18 17 17 39 131 
Natural gas57 42 37 43 43 578 800 
Coal and transportation27 27 27 27 27 — 135 
Pension Plan Contributions (2)
— — 16 23 23 — 62 
Finance and operating lease obligations24 24 22 21 14 267 372 
Total$911 $535 $557 $623 $504 $8,450 $11,580 
`
(1) Future interest on long-term debt is calculated based on the assumption that all debt remains outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect as of December 31, 2017.2020.
(2) Contributions beyond 20222025 are not estimated due to significant uncertainty in financial market and demographic outcomes.


Other Financial Obligations


PGE has entered into long-term power purchase agreements in place with certain public utility districts in the state of Washington under which itWashington.

The Company has acquired a percentage of the output of the Priest Rapids and Wanapum and Wells hydroelectric projects. The Company is requiredHydroelectric Projects under an agreement that requires PGE to pay its proportionate share of the operating and debt service costs of the projects, whether or not they are operable. The agreements further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro ratapro-rata share of both the output and the operating and debt service costs of the defaulting purchaser. For

Under an agreement for output of Douglas County PUD’s Wells Hydroelectric Project, PGE receives a share of the Wells project,production in return for a fixed payment. If any other purchaser of output were to default, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage of the output through August 2018, after which PGE would be responsible forreceive a pro-rata portion of the defaulting purchaser’s share of the project output and associated costs, with no limitation, regardless of the reason for anythe default. ForThe share of the Priest Rapids and Wanapum projects, PGE would be allocated upproject output is expected to a cumulative maximum that would not adversely affect the tax exempt status of any ofdecline over time as the public utility district’s outstanding debt for the portion of the projectdistrict load grows and output is needed to serve that benefits tax exempt purchasers. growth.

For additional information on these long-term power purchase agreements, see “Public utility districts” in Note 15,16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


Off-Balance Sheet Arrangements


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


resources:
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•PGE hasfour letter of credit facilities that provide capacity up to a total of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, $60 million has been issued as of December 31, 2020; and
•As a co-owner of Colstrip, PGE has provided surety bonds of $30 million as of December 31, 2020 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC.

Critical Accounting Policies and Estimates


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


Regulatory Accounting


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


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


Asset Retirement Obligations


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


Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions
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to ARO liabilities in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Accretion of the ARO liability is classified as an operatingDepreciation and amortization expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets.

Revenue Recognition

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

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Contingencies


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


Pension Plan

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

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

Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets, or reduction in the discount rate, would have the effect of increasing the 2017 net periodic pension expense by approximately$2 million.

Fair Value Measurements

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


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


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



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Energy Risk Management Committee


During 2020, PGE hashad a Risk Management Committee (RMC), which is responsible forwhose responsibilities included providing oversight of the adequacy and effectiveness of corporate policies, guidelines, and procedures for market and credit risk management related to the Company’s energy portfolio management activities. The RMC consistsconsisted of officers and Company representatives with responsibility for risk management, finance and accounting, information technology, utility operations, legal, and rates and regulatory affairs, power operations, generation operations, and business development.affairs. The RMC reviewsreviewed and approvesapproved adoption of policies and procedures, and monitorsmonitored compliance with policies, procedures, and limits on a regular basis through reports and meetings. The RMC also reviewsreviewed and recommendsrecommended risk limits that arewere subject to approval by PGE’s Board of Directors.


In response to the energy trading losses realized in the third quarter of 2020 (for more information see “Energy Trading” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”) the Company began taking actions to enhance oversight of energy trading and associated risk management reporting, policies, and practices. As a result, effective February 1, 2021, the RMC has been subsumed by the Executive Risk Committee (ERC) whose primary purpose is to oversee, guide, and support the prudent management of the Company’s risks. In addition to assuming the responsibilities previously held by the RMC, the ERC’s responsibilities have been enhanced to include improved risk reporting to ensure greater visibility into portfolio risk and manage alignment with the Company’s Board-approved risk strategy and tolerances.

Commodity Price Risk


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


TheA portion of PGE’s energy portfolio subject to commodity price risk experienced significant losses during the third quarter of 2020. In August 2020, wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. As a result of the convergence of these conditions, the Company’s energy portfolio experienced realized losses of $127 million in the third quarter of 2020. PGE no longer has net market exposure related to these positions and will not pursue regulatory recovery of the related losses. For additional information see “Energy Trading” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Assuming no changes in market prices and interest rates, the following table presents energy commoditythe years in which the net unrealized (gains)/losses recorded as of December 31, 2020 related to PGE’s derivative fair valuesactivities would become realized as a net liability asresult of December 31, 2017 that are expected to settle in each respective yearthe settlement of the underlying derivative instrument (in millions):
 20212022202320242025ThereafterTotal
Commodity contracts:
Electricity$9 $4 $8 $8 $9 $100 $138 
Natural gas(27)(5)— — — — (32)
       Net unrealized (gain)/loss$(18)$(1)$8 $8 $9 $100 $106 
 2018 2019 2020 2021 2022 Thereafter Total
Commodity contracts:             
Electricity$10
 $8
 $8
 $8
 $7
 $91
 $132
Natural gas43
 20
 7
 2
 —
 —
 72
 $53
 $28
 $15
 $10
 $7
 $91
 $204


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


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


Foreign Currency Exchange Rate Risk


PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars in its energy portfolio.dollars. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the

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value of that foreign currency in relation to the U.S. dollar. PGE monitorsmitigates its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy.


As of December 31, 2017,2020, a 10% change in the value of the Canadian dollar would result in an immaterial change in exposure for transactions that will settle over the next twelve months.



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Interest Rate Risk


To meet short-term cash requirements, PGE has the ability to issue commercial paper for terms of up to 270 days and has a revolving credit facility that permits same day borrowings. Although any borrowings under the commercial paper program or the revolving credit facility carry a fixed rate during their respective terms, the short-term nature of such borrowings subjects the Company to fluctuations in interest rates that result from changes in market conditions. As of December 31, 2017,2020, PGE had no borrowings outstanding under its revolving credit facility and no commercial paper or other short-term debt outstanding.


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


As of December 31, 2017,2020, the total fair value and carrying amounts, excluding unamortized debt expense, by maturity date of PGE’s long-term debt are as follows (in millions): 
 Total
Fair
Value		Carrying Amounts by Maturity Date
 Total2021202220232024There-
after
First Mortgage Bonds$3,683 $2,940 $160 $— $— $80 $2,700 
Pollution Control Revenue Bonds125 119 — — — — 119 
Total$3,808 $3,059 $160 $— $— $80 $2,819 
 
Total
Fair
Value
 Carrying Amounts by Maturity Date
 Total 2018 2019 2020 2021 
There-
after
First Mortgage Bonds$2,698
 $2,315
 $—
 $300
 $—
 $160
 $1,855
Pollution Control Revenue Bonds131
 121
 —
 —
 —
 —
 121
Total$2,829
 $2,436
 $—
 $300
 $—
 $160
 $1,976


As of December 31, 2017,2020, PGE had no long-term debt instruments subject to interest rate risk exposures.


Credit Risk


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


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


As of December 31, 2017,2020, PGE’s credit risk exposure is $9$48 million for commodity activities, of which $46 million is with externally-rated investment grade counterparties. The underlying transactions that make up the exposure will mature during 2019.from 2021 to 2024. The exposure is included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.


Investment grade counterparties include those with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody’s) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. The credit exposure includes activity for electricity and natural

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gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit, and may represent prepayment or credit exposure assurance.


Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington. These contracts currently provide PGE with a percentage share of hydro
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facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2052. For additional information, see “Public utility districts” in Note 15,16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Management believes that circumstances that could result in the nonperformance by these counterparties are remote.



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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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


6463
66
67
68
70
71
73



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the shareholders and the Board of Directors of Portland General Electric Company


Opinions on the Financial Statements and Internal Control over Financial Reporting


We have audited the accompanying consolidated balance sheets of Portland General Electric Company and subsidiaries (the “Company”) as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control — Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).


In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control — Integrated Framework(2013) issued by COSO.


Basis for Opinions


The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our
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responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.


Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.


Definition and Limitations of Internal Control over Financial Reporting


A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,

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accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinionon the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting - Refer to Notes 2 and 7 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Public Utility Commission of Oregon (the OPUC), which has jurisdiction with respect to the rates for retail electricity in the state of Oregon. Management has determined it meets
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the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as electric utility plant; regulatory assets and liabilities; operating revenues; operation and maintenance expense; income taxes; and depreciation expense.
The Company’s rates for retail customers are determined and approved in regulatory proceedings based on an analysis of the Company’s cost of providing service to retail customers. 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.
We identified the impact of rate regulation as a critical audit matter due to its pervasive impact on the Company’s financial statements and the significant judgments made by management to support its assertions about impacted account balances and disclosures. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the OPUC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the OPUC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a refund or future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the OPUC for the Company, regulatory statutes, and other publicly available information to assess the likelihood of recovery in future rates or of a refund or future reduction in rates.
•For selected regulatory assets and liabilities, we evaluated whether management had determined such amounts in accordance with the regulatory orders.



/s/ Deloitte & Touche LLP


Portland, Oregon
February 15, 201818, 2021


We have served as the Company’s auditor since 2004.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in millions, except per share amounts)







Years Ended December 31,
Years Ended December 31,202020192018
2017 2016 2015
Revenues:Revenues:
Revenues, net$2,009
 $1,923
 $1,898
 Revenues, net$2,151 $2,121 $1,988 
Alternative revenue programs, net of amortization Alternative revenue programs, net of amortization(6)2 3 
Total Revenues Total Revenues2,145 2,123 1,991 
Operating expenses:     Operating expenses:
Purchased power and fuel592
 617
 661
Purchased power and fuel708 614 571 
Generation, transmission and distribution309
 286
 266
Generation, transmission and distribution293 323 292 
Administrative and other264
 247
 241
Administrative and other283 290 271 
Depreciation and amortization345
 321
 305
Depreciation and amortization454 409 382 
Taxes other than income taxes123
 119
 116
Taxes other than income taxes138 134 129 
Total operating expenses1,633
 1,590
 1,589
Total operating expenses1,876 1,770 1,645 
Income from operations376
 333
 309
Income from operations269 353 346 
Interest expense, net120
 112
 114
Interest expense, net136 128 124 
Other income:     Other income:
Allowance for equity funds used during construction12
 21
 21
Allowance for equity funds used during construction16 10 11 
Miscellaneous income, net5
 1
 1
Miscellaneous income (expense), netMiscellaneous income (expense), net6 6 (4)
Other income, net17
 22
 22
Other income, net22 16 7 
Income before income taxes273
 243
 217
Income before income taxes155 241 229 
Income tax expense86
 50
 45
Income tax expense0 27 17 
Net income$187
 $193
 $172
Net income$155 $214 $212 
     
Weighted-average shares outstanding (in thousands):     Weighted-average shares outstanding (in thousands):
Basic89,056
 88,896
 84,180
Basic89,485 89,353 89,215 
Diluted89,176
 89,054
 84,341
Diluted89,645 89,559 89,347 
     
Earnings per share:     Earnings per share:
Basic$2.10
 $2.17
 $2.05
Basic$1.73 $2.39 $2.38 
Diluted$2.10
 $2.16
 $2.04
Diluted$1.72 $2.39 $2.37 
     
See accompanying notes to consolidated financial statements.



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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)





Years Ended December 31,Years Ended December 31,
2017 2016 2015202020192018
Net income$187
 $193
 $172
Net income$155 $214 $212 
Other comprehensive (loss) income—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2017, 2016, and 2015(1) 1
 (1)
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of $1 million in 2020 and immaterial amounts in 2019 and 2018Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of $1 million in 2020 and immaterial amounts in 2019 and 2018(1)(1)1 
Comprehensive income$186
 $194
 $171
Comprehensive income$154 $213 $213 
     
See accompanying notes to consolidated financial statements.



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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)



As of December 31,As of December 31,
2017 201620202019
ASSETS   ASSETS
Current assets:   Current assets:
Cash and cash equivalents$39
 $6
Cash and cash equivalents$257 $30 
Accounts receivable, net168
 155
Accounts receivable, net271 253 
Unbilled revenues106
 107
Inventories, at average cost:   Inventories, at average cost:
Materials and supplies52
 50
Materials and supplies49 56 
Fuel26
 32
Fuel23 40 
Regulatory assets—current62
 36
Regulatory assets—current23 17 
Other current assets73
 77
Other current assets98 104 
Total current assets526
 463
Total current assets721 500 
Electric utility plant:   Electric utility plant:
Generation4,667
 4,597
Transmission547
 521
Distribution3,543
 3,343
General550
 501
Intangible607
 572
In serviceIn service10,974 10,928 
Accumulated depreciation and amortizationAccumulated depreciation and amortization(3,864)(4,095)
In service, netIn service, net7,110 6,833 
Construction work-in-progress391
 213
Construction work-in-progress429 328 
Total electric utility plant10,305
 9,747
Accumulated depreciation and amortization(3,564) (3,313)
Electric utility plant, net6,741
 6,434
Electric utility plant, net7,539 7,161 
Regulatory assets—noncurrent438
 498
Regulatory assets—noncurrent569 483 
Nuclear decommissioning trust42
 41
Nuclear decommissioning trust45 46 
Non-qualified benefit plan trust37
 34
Non-qualified benefit plan trust42 38 
Other noncurrent assets54
 57
Other noncurrent assets153 166 
Total assets$7,838
 $7,527
Total assets$9,069 $8,394 
   
See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, continued
(In millions, except share amounts)







As of December 31,
As of December 31,20202019
2017 2016
LIABILITIES AND EQUITY   
LIABILITIES AND SHAREHOLDERS’ EQUITYLIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:   Current liabilities:
Accounts payable$132
 $129
Accounts payable$153 $165 
Liabilities from price risk management activities—current59
 44
Liabilities from price risk management activities—current14 23 
Short-term debtShort-term debt150 0 
Current portion of long-term debt—
 150
Current portion of long-term debt160 0 
Current portion of finance lease obligationsCurrent portion of finance lease obligations16 16 
Accrued expenses and other current liabilities241
 254
Accrued expenses and other current liabilities322 315 
Total current liabilities432
 577
Total current liabilities815 519 
Long-term debt, net of current portion2,426
 2,200
Long-term debt, net of current portion2,886 2,597 
Regulatory liabilities—noncurrent1,288
 958
Regulatory liabilities—noncurrent1,369 1,377 
Deferred income taxes376
 669
Deferred income taxes374 378 
Unfunded status of pension and postretirement plans284
 281
Unfunded status of pension and postretirement plans299 247 
Liabilities from price risk management activities—noncurrent151
 125
Liabilities from price risk management activities—noncurrent136 108 
Asset retirement obligations167
 161
Asset retirement obligations270 263 
Non-qualified benefit plan liabilities106
 105
Non-qualified benefit plan liabilities101 103 
Finance lease obligations, net of current portionFinance lease obligations, net of current portion129 135 
Other noncurrent liabilities192
 107
Other noncurrent liabilities77 76 
Total liabilities5,422
 5,183
Total liabilities6,456 5,803 
Commitments and contingencies (see notes)

 
Commitments and contingencies (see notes)00
Equity:   
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding—
 —
Common stock, no par value, 160,000,000 shares authorized; 89,114,265 and 88,946,704 shares issued and outstanding as of December 31, 2017 and 2016, respectively1,207
 1,201
Shareholders’ equity:Shareholders’ equity:
Preferred stock, 0 par value, 30,000,000 shares authorized; NaN issued and outstandingPreferred stock, 0 par value, 30,000,000 shares authorized; NaN issued and outstanding0 0 
Common stock, 0 par value, 160,000,000 shares authorized; 89,537,331 and 89,387,124 shares issued and outstanding as of December 31, 2020 and 2019, respectivelyCommon stock, 0 par value, 160,000,000 shares authorized; 89,537,331 and 89,387,124 shares issued and outstanding as of December 31, 2020 and 2019, respectively1,231 1,220 
Accumulated other comprehensive loss(8) (7)Accumulated other comprehensive loss(11)(10)
Retained earnings1,217
 1,150
Retained earnings1,393 1,381 
Total equity2,416
 2,344
Total liabilities and equity$7,838
 $7,527
   
Total shareholders’ equityTotal shareholders’ equity2,613 2,591 
Total liabilities and shareholders’ equityTotal liabilities and shareholders’ equity$9,069 $8,394 
See accompanying notes to consolidated financial statements.



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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In millions, except share and per share amounts)







Common StockAccumulated
Other
Comprehensive
Loss		Retained
Earnings		Total
Common Stock 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 Total SharesAmount
Balance as of December 31, 2017Balance as of December 31, 201789,114,265 $1,207 $(8)$1,217 $2,416 
Shares Amount 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 Total
Balance as of December 31, 201478,228,339
 $918
 
Issuances of common stock, net of issuance costs of $1210,400,000
 271
 —
 —
 271
Shares issued pursuant to equity-based plansShares issued pursuant to equity-based plans153,694 1 — — 1 
Stock-based compensationStock-based compensation— 4 0 0 4 
Dividends declared ($1.4275 per share)Dividends declared ($1.4275 per share)— 0 0 (128)(128)
Net incomeNet income— 0 0 212 212 
Other comprehensive incomeOther comprehensive income— 0 1 0 1 
Balance as of December 31, 2018Balance as of December 31, 201889,267,959 1,212 (7)1,301 2,506 
Shares issued pursuant to equity-based plans164,412
 1
 —
 —
 1
Shares issued pursuant to equity-based plans119,165 1 — — 1 
Stock-based compensation—
 6
 —
 —
 6
Stock-based compensation— 7 0 0 7 
Dividends declared ($1.18 per share)—
 —
 —
 (102) (102)
Dividends declared ($1.5175 per share)Dividends declared ($1.5175 per share)— 0 0 (136)(136)
Net incomeNet income— 0 0 214 214 
Reclassification of stranded tax effects due to Tax ReformReclassification of stranded tax effects due to Tax Reform— — (2)2 — 
Other comprehensive (loss)Other comprehensive (loss)— 0 (1)0 (1)
Balance as of December 31, 2019Balance as of December 31, 201989,387,124 1,220 (10)1,381 2,591 
Shares issued pursuant to equity-based plansShares issued pursuant to equity-based plans150,207 2 — — 2 
Stock-based compensationStock-based compensation— 9 0 0 9 
Dividends declared ($1.5850 per share)Dividends declared ($1.5850 per share)— 0 0 (143)(143)
Net income—
 —
 —
 172
 172
Net income— 0 0 155 155 
Other comprehensive (loss)—
 —
 (1) —
 (1)Other comprehensive (loss)— 0 (1)0 (1)
Balance as of December 31, 201588,792,751
 1,196
 (8) 1,070
 2,258
Shares issued pursuant to equity-based plans153,953
 1
 —
 —
 1
Stock-based compensation—
 4
 —
 —
 4
Dividends declared ($1.26 per share)—
 —
 —
 (113) (113)
Net income—
 —
 —
 193
 193
Other comprehensive income—
 —
 1
 —
 1
Balance as of December 31, 201688,946,704
 1,201
 (7) 1,150
 2,344
Shares issued pursuant to equity-based plans167,561
 2
 —
 —
 2
Stock-based compensation—
 4
 —
 —
 4
Dividends declared ($1.34 per share)—
 —
 —
 (120) (120)
Net income—
 —
 —
 187
 187
Other comprehensive (loss)—
 —
 (1) —
 (1)
Balance as of December 31, 201789,114,265
 $1,207
 $(8) $1,217
 $2,416
Balance as of December 31, 2020Balance as of December 31, 202089,537,331 $1,231 $(11)$1,393 $2,613 
         
See accompanying notes to consolidated financial statements.



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CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)






Years Ended December 31,
202020192018
Cash flows from operating activities:
Net income$155 $214 $212 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization454 409 382 
Deferred income taxes(23)6 (17)
Allowance for equity funds used during construction(16)(10)(11)
Pension and other postretirement benefits22 21 30 
Decoupling mechanism deferrals, net of amortization6 (2)(2)
(Amortization) Deferral of net benefits due to Tax Reform(23)(23)45 
Stock-based compensation11 9 5 
Other non-cash income and expenses, net22 34 16 
Changes in working capital:
(Increase) decrease in receivables and unbilled revenues(24)30 (29)
Decrease (increase) in margin deposits8 0 (5)
Increase (decrease) in payables and accrued liabilities26 (16)51 
Other working capital items, net17 (12)(11)
Contribution to non-qualified employee benefit trust(11)(11)(11)
Contribution to pension and other postretirement plans(2)(65)(12)
Asset retirement obligation settlements(18)(9)(5)
Other, net(37)(29)(8)
Net cash provided by operating activities567 546 630 
Cash flows from investing activities:
Capital expenditures(784)(606)(595)
Purchases of nuclear decommissioning trust securities(6)(8)(12)
Sales of nuclear decommissioning trust securities9 13 15 
Proceeds from Carty Settlement0 0 120 
Other, net(6)(3)1 
Net cash used in investing activities(787)(604)(471)
See accompanying notes to consolidated financial statements.
 Years Ended December 31,
 2017 2016 2015
Cash flows from operating activities:     
Net income$187
 $193
 $172
Adjustments to reconcile net income to net cash provided by operating activities:     
Depreciation and amortization345
 321
 305
Deferred income taxes70
 37
 40
Allowance for equity funds used during construction(12) (21) (21)
Pension and other postretirement benefits24
 28
 34
Unrealized losses on non-qualified benefit plan trust assets2
 5
 6
Decoupling mechanism deferrals, net of amortization(22) (6) 14
Other non-cash income and expenses, net29
 7
 22
Changes in working capital:     
(Increase) in receivables and unbilled revenues(3) (9) (11)
(Increase) decrease in margin deposits(3) 25
 (22)
Increase in payables and accrued liabilities5
 15
 6
Other working capital items, net1
 (4) (4)
Contribution to non-qualified employee benefit trust(8) (10) (9)
Other, net(18) (28) (12)
Net cash provided by operating activities597
 553
 520
Cash flows from investing activities:     
Capital expenditures(514) (584) (598)
Purchases of nuclear decommissioning trust securities(18) (25) (19)
Sales of nuclear decommissioning trust securities21
 27
 22
Distribution from nuclear decommissioning trust—
 —
 50
Sales tax refund received - Tucannon River Wind Farm—
 —
 23
Other, net(3) (3) —
Net cash used in investing activities(514) (585) (522)
      
See accompanying notes to consolidated financial statements.



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CONSOLIDATED STATEMENTS OF CASH FLOWS, continued
(In millions)




Years Ended December 31,
Years Ended December 31,202020192018
2017 2016 2015


Cash flows from financing activities:     Cash flows from financing activities:
Proceeds from issuance of long-term debt$225
 $290
 $145
Proceeds from issuance of long-term debt$549 $470 $75 
Payments on long-term debt(150) (133) (442)Payments on long-term debt(98)(350)(24)
Proceeds from issuances of common stock, net of issuance costs—
 —
 271
(Maturities) issuances of commercial paper, net—
 (6) 6
Debt extinguishment costsDebt extinguishment costs(2)(9)0 
Borrowings on short-term debtBorrowings on short-term debt275 0 0 
Payments on short-term debtPayments on short-term debt(125)0 0 
Dividends paid(118) (110) (97)Dividends paid(140)(134)(125)
Other(7) (7) (4)Other(12)(8)(5)
Net cash (used in) provided by financing activities(50) 34
 (121)
Net cash provided by (used in) financing activitiesNet cash provided by (used in) financing activities447 (31)(79)
Increase (decrease) in cash and cash equivalents33
 2
 (123)Increase (decrease) in cash and cash equivalents227 (89)80 
Cash and cash equivalents, beginning of year6
 4
 127
Cash and cash equivalents, beginning of year30 119 39 
Cash and cash equivalents, end of year$39
 $6
 $4
Cash and cash equivalents, end of year$257 $30 $119 
     
Supplemental disclosures of cash flow information:     Supplemental disclosures of cash flow information:
Cash paid for:     Cash paid for:
Interest, net of amounts capitalized$110
 $104
 $108
Interest, net of amounts capitalized$113 $116 $117 
Income taxes18
 16
 3
Income taxes17 33 25 
Non-cash investing and financing activities:     Non-cash investing and financing activities:
Accrued capital additions53
 50
 32
Accrued capital additions72 76 61 
Accrued dividends payable31
 30
 28
Accrued dividends payable38 36 34 
Assets obtained under leasing arrangements87
 78
 —
Assets obtained under leasing arrangements0 210 24 
See accompanying notes to consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




NOTE 1: BASIS OF PRESENTATION


Nature of Operations


Portland General Electric Company (PGE or the Company) is a single, vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the Statestate of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its approximately4,0004000 square mile, state-approved service area is located entirely within the Statestate of Oregon. PGE’s allocated service area includes 51 incorporated cities, of which Portland and Salem are the largest.cities. As of December 31, 2017,2020, PGE served approximately875,000908 thousand retail customers with a service area population of approximately 1.9 million, comprising approximately 46% of the population of the state.million.


As of December 31, 2017,2020, PGE had2,906 employees,3,639 members in its workforce (769 of which are contingent workers), with 785721 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. SuchThe agreements cover732660 and 5361 employees and expire March 20202022 and August 2022, respectively.


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


Consolidation Principles


The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 16,18, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated.

For entities that are determined to meet the definition of a VIE and in which the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. There were no material VIEs in 2017 or 2016.


Use of Estimates


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


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Reclassifications


To conform with current year presentation, the 2017 presentation, PGECompany has reclassified Cash received to be returned to customers pursuant to the Residential Exchange Program, netAsset retirement obligation settlements of amortization of $6$9 million and $1$5 million in 2016 and 2015, respectively, and Contribution to voluntary employees’ benefit association trust of $2 million and $4 million in 2016 and 2015, respectively, tofrom Other, net withinin the operating activities section of the Consolidated Statementsconsolidated statements of Cash Flows. PGE has also reclassifiedcash flows for the Regulatory deferral of settled derivative instruments of $2 million in both 2016years ended December 31, 2019 and 2015 to Other non-cash income and expense, net within the operating activities section of the Consolidated Statements of Cash Flows.2018, respectively.


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NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


Cash and Cash Equivalents


Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $30$255 million as of December 31, 20172020 and $1$26 million as of December 31, 20162019 included within Cash and cash equivalents in the consolidated balance sheets.


Accounts Receivable


Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 168 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than45 business days after the due date of the final invoice. During 2020, the Company has taken steps to support customers during the COVID-19 pandemic, including suspending disconnections and late fees and developing time payment arrangements.


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


Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no0 material write-offs of accounts receivable related to wholesale sales in 2017, 2016,2020, 2019, or 2015.2018.


Price Risk Management


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


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


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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued


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


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Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral withto certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets and were $11 million and $8 million as of December 31, 20172020 and 2016, respectively.$16 million as of December 31, 2019. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheetsheets and were $31$12 million and $17$15 million as of December 31, 20172020 and 2016,2019, respectively.


Inventories


PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that it isinventories are recorded at the lower of average cost or net realizable value.


Electric Utility Plant


Capitalization Policy


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


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


PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative AFDC calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction in response to COVID-19. PGE adopted the waiver in the second quarter of 2020. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.3%6.9% in 2017, 2016,2020, 7.1% in 2019, and 2015.7.3% in 2018. AFDC from borrowed funds, was $6 million in 2017, $11 million in 2016, and $13 million in 2015 and is reflected as a reduction to Interest expense.expense, net, was $8 million in 2020, $5 million in 2019, and $6 million in 2018. AFDC from equity funds, included in Other income, net, was $12$16 million in 2017,2020, $10 million in 2019, and $21$11 million in 2016 and 2015.2018.


Depreciation and Amortization


Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

service was 3.6% in 2017, 3.5% in 20162020 and 3.6% in 2015.both 2019 and 2018. A component of depreciation expense includes estimated asset retirement removal costs allowed in customer prices.


Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recentIn 2016 PGE completed a depreciation study was completed forbased on2015 data, with an order received from the OPUC in September 2017 authorizing new depreciation rates effective January 1, 2018. This study was incorporated into the Company’s 2018 general rate case filed with the OPUC in 2017.


Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059.2061. Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years):
Generation, excluding thermal:
Hydro95
97
Wind30
31
Transmission57
58
Distribution45
46
General12
13


When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities.


Intangible plant consists primarily of computer software development costs, which are amortized over eitherfive or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $296$388 million and $257$366 million as of December 31, 20172020 and 2016,2019, respectively, with amortization expense of $46 million in 2017, and $44$64 million in 2016 and $382020, $64 million in 2015.2019, and $59 million in 2018. Future estimated amortization expense as of December 31, 20172020 is as follows: $49$57 million in 2018;2021;$4851 million in 2019; $432022; $42 million in 2020; $352023; $37 million in 2021;2024; and $28$25 million in 2022.2025.


Marketable Securities


Nuclear decommissioning trust

Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust (NDT) includes amounts collected from customers, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein.

Non-qualified benefit plan trust

Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans (NQBP) and represents contributions made by the Company, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein.

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


Regulatory Accounting


Regulatory Assets and Liabilities


As a rate-regulated enterprise, PGE applies regulatory accounting, which results in the creation of regulatory assets and regulatory liabilities. Regulatory assets represent: i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process; or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, continued

with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as: i) prices are established by, or subject to, approval by independent third-party regulators; ii) prices are designed to recover the specific enterprise’s cost of service; and iii) in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices.


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


For additional information concerning the Company’s regulatory assets and liabilities, see Note 6,7, Regulatory Assets and Liabilities.


Power Cost Adjustment Mechanism


PGE is subject to a power cost adjustment mechanismPower Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices can be adjusted to reflect a portion of the difference between net variable power costs (NVPC)between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC.NVPC for the year. 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 of which is classified as Purchased power and fuel in the Company’s consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the consolidated statements of income.


The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC.


To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.6%9.5% for 2017, 9.6% for 2016,2020, 2019, and 9.68% for 2015.2018.


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Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For the year ended December 31, 2020, PGE’s actual NVPC was $114 million above baseline NVPC. PGE excluded from actual NVPC and will not be pursuing regulatory recovery for amounts related to trading positions that resulted in realized losses of $127 million during the third quarter of 2020. These losses were the result of a convergence of increased wholesale electricity prices at various market hubs due to extreme weather conditions, constraints to regional transmission facilities and changes in power supply in the West that occurred in August 2020. The Company no longer has net market exposure from these trading positions. After adjusting for the realized losses on the trading positions, PGE’s actual NVPC for 2020 was $13 million below baseline NVPC, which is within the established deadband range resulting in no estimated refund to customers.

A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. The PCAM has resulted in no collection from, or refund to, customers since 2011.


Asset Retirement Obligations


Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheet.sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available.techniques. The present value of estimated future decommissioning costs is capitalized and

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included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual expendituressettlements charged to the ARO as incurred.


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


For additional information concerning the Company’s AROs, see Note 7,8, Asset Retirement Obligations.


The difference between the timing of the recognition of ARO depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. As of December 31, 2020, PGE had a net regulatory liability related to Utility plant AROs in the amount of$52 $37 million asand a net regulatory asset related to Trojan decommissioning ARO activities of $88 million. As of December 31, 20172019, PGE had a net regulatory liability related to Utility plant AROs in the amount of $54 million and $49 million asa net regulatory asset related to Trojan decommissioning ARO activities of December 31, 2016.$91 million. For additional information concerning the Company’s regulatory liabilityassets and liabilities related to AROs, see Note 6,7, Regulatory Assets and Liabilities.


Contingencies


Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental contingencies, are accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

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A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be determined, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons.reasons why the estimate cannot be made.


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


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


For additional information concerning the Company’s contingencies, see Note 19, Contingencies.

Accumulated Other Comprehensive Loss


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


RevenuesRevenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, and include amounts forincluding any services provided. The prices charged, and amount of consideration PGE receives in exchange for its services provided, are regulated by the OPUC or the FERC. PGE recognizes revenue through the following steps: i) identifying the contract with the customer; ii) identifying the performance obligations in the contract; iii) determining the transaction price; iv) allocating the transaction price to the performance obligations; and v) recognizing revenue when or as each performance obligation is satisfied.

Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $43$46 million in 2017, 20162020 and 2015.$45 million in both 2019 and 2018.


Retail revenue is billed monthly based on monthly meter readings taken at various cycle dates throughout the month. Unbilled revenue representsAt the end of each month, PGE estimates the revenue earned from energy deliveries that remained unbilled to customers. The unbilled revenues estimate, which is included in Accounts receivable, net in the time of the last meter read date through the last day of the month, a period that has not

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been billed as of the last day of the month. Unbilled revenueCompany’s consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current retail customer prices.


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


Alternative Revenue Programs

Revenues related to PGE’s decoupling mechanism are considered earned under alternative revenue programs, as this amount represents a contract with the regulator and not with customers. Such revenues are presented separately from revenues from contracts with customers and classified as Alternative revenue programs, net of amortization on the consolidated statements of income. The activity within this line item is comprised of current period deferral
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adjustments, which can either be a collection from or a refund to customers, and is net of any related amortization. When amounts related to alternative revenue programs are ultimately included in prices and customer bills, the amounts are included within Revenues, net, with an equal and offsetting amount of amortization recorded on the Alternative revenue programs, net of amortization line item.

Stock-Based Compensation


The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. For additional information concerning the Company’s Stock-Based Compensation, see Note 13,14, Stock-Based Compensation Expense.


Income Taxes


Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.


Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory liabilities of $277$239 million and net regulatory assets of $86$260 million as of December 31, 2017,2020 and 2016,2019, respectively, and will primarily be included in prices whenamortized using the average rate assumption method to account for the refund to customers as the temporary differences reverse.


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


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

RecentRecently Adopted Accounting Pronouncements


On January 1, 2020, PGE adopted ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. ASU 2018-13 amends Topic 820 to add, remove, and clarify disclosure requirements related to fair value measurement disclosures. As the standard relates only to disclosures, the implementation did not result in an impact to the results of operation, financial position or cash flows.

On January 1, 2020, PGE adopted ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting Standards Update (ASU) 2014-09, Revenue from Contractsfor Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. ASU 2018-15 provides guidance on implementation costs incurred in a cloud computing arrangement that is a service contract and aligns the accounting for such costs with Customers (Topic 606) (ASU 2014-09), createsthe guidance on capitalizing costs associated with developing or obtaining internal-use software. PGE applied the amendments of
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this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position or cash flows.

On January 1, 2020, PGE adopted ASU 2016-13 Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 replaces the incurred loss impairment methodology in previous GAAP with a methodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. PGE applied this ASU using a modified-retrospective approach, and as a result, amounts recorded prior to January 1, 2020 have not been retrospectively restated. Under the new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topicsstandard, PGE estimates current expected credit losses for retail sales based on an assessment of the Codification. ASU 2014-09 provides a five-step analysiscurrent and forecasted probability of transactionscollection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other significant events that may impact the collectability of accounts receivable and unbilled revenues. Provisions for current expected credit losses related to determine whenretail sales, and how revenue is recognized that consists of: i) identifychanges to the contract with the customer; ii) identify the performance obligationsamount of expected credit losses for existing receivables, are charged to Administrative and other expense and are recorded in the contract; iii) determinesame period as the transaction price; iv) allocate the transaction pricerelated revenues, with an offsetting credit to the performance obligations; and v) recognize revenue whenallowance for credit losses. The implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows. To conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the consolidated balance sheets as each performance obligation is satisfied. Companies can transitionof December 31, 2019.

On April 1, 2020, PGE adopted ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.ASU 2020-04 provides optional guidance for a limited period of time to ease the requirementspotential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PGE applied the amendments of this ASU either retrospectively (full retrospective method)prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or ascash flows.

PGE has adopted ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans. ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. As the standard relates only to disclosures, the adoption did not have a cumulative-effect adjustment asmaterial impact on PGE’s results of the effective date (modifiedoperation, financial position, or cash flows.




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NOTE 3: REVENUE RECOGNITION
retrospective method)
Disaggregated Revenue

The following table presents PGE’s revenue, disaggregated by customer type (in millions):

Year Ended December 31,
20202019
Retail:
Residential$1,030 $981 
Commercial616 636 
Industrial218 196 
Direct access customers46 44 
Subtotal1,910 1,857 
Alternative revenue programs, net of amortization(6)2 
Other accrued (deferred) revenues, net(1)
28 22 
Total retail revenues1,932 1,881 
Wholesale revenues(2)
162 170 
Other operating revenues51 72 
Total revenues$2,145 $2,123 

(1) Amounts for the year ended December 31, 2020 and 2019 is primarily comprised of $24 million and $23 million of amortization, respectively, including interest, related to the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA).
(2) Wholesale revenues include $65 million and $50 million related to physical electricity commodity contract derivative settlements for the years ended December 31, 2020 and 2019, respectively. Price risk management derivative activities are included within Total revenues but do not represent revenues from contracts with customers as defined by GAAP, pursuant to Topic 606. For further information, see Note 6, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), whichmanufactured homes, and small farms. Residential demand is January 1, 2018 for calendar year-endsensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public entities. The Company plans to elect the modified retrospective method for implementation. PGE does not anticipate any material changes to its revenue recognition policy for tariff-based revenues, which comprises a majoritystreet and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class.

In accordance with state regulations, PGE’s retail wholesale, and other revenues, as performance obligationscustomer prices are expected to be satisfied in a similar recognition pattern. PGE continues to finalize its evaluation of certain matters of presentation such as alternative revenue programs (including decoupling) and enhanced required disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019. As issued, ASU 2016-02 requires transition under a modified retrospective basis as of the beginning of the earliest comparative period presented, however the Company is monitoring the FASB’s decisions regarding potential transition practical expedients that would allow companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. Early adoption is permitted, but the Company does not plan to early adopt. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842, which amends ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 842. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. PGE plans to elect this practical expedient. The Company is monitoring utility industry implementation issues that may change existing and future lease classification in areas such as purchase power agreements, pipeline laterals, utility pole attachments, and other utility industry-related arrangements. In conjunction with monitoring industry issues that may impact lease classification, the Company is in the process of evaluating whether it will elect to adopt certain other, optional practical expedients included within the standard. Decisions surrounding the election of practical expedients may impact the Company’s lease population that is ultimately recorded. As a result, PGE has not yet quantified the estimated financial statement impact, but overall, the Company does expect an increase in the recognition of right-of-use assets and lease liabilitiesbased on the Company’s consolidated balance sheet.

In March 2017,cost of service and determined through general rate case proceedings and various tariff filings with the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. For ratemaking purposes,OPUC. Additionally, the Company will continue to be allowed to recover this portionoffers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

Retail revenue is billed based on monthly meter readings taken throughout the month. At the end of the non-service costs as a component of rate base, however such amounts will be recorded as Regulatory assets on the Company’s condensed consolidated balance sheets, instead of Utility plant, and amortized in a systematic and rational manner and reflected as expense in a line item outside the subtotal of income from operations on the condensed consolidated statements of income and other comprehensive income.each month, PGE estimates the portion of the non-service components of net periodic pension and postretirement benefit costsrevenue earned from energy deliveries that is eligible for deferral for ratemaking purposes,have not yet been billed to be $3 million for the twelve month period ending December 31, 2018, and

customers. This amount,
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classified as Unbilled revenues, which is deemed to have an immaterial impact onincluded in Accounts receivable, net in the Company’s consolidated financial positionbalance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.

PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.

Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the consolidated resultsstatements of operations.income.


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, solar, and wind conditions, and daily and seasonal retail demand.
PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

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 resale, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

NOTE 3:4: BALANCE SHEET COMPONENTS


Accounts Receivable, Net


Accounts receivable, net includes $97 million and $86 million of unbilled revenues as of December 31, 2020 and 2019, respectively. Accounts receivable is net of an allowance for uncollectible accounts of $6$16 million as of December 31, 20172020 and $5 million as of December 31, 2016.2019. The following is the activity in the allowance for uncollectible accounts (in millions):
 Years Ended December 31,
 202020192018
Balance as of beginning of year$5 $15 $6 
Increase in provision *15 2 14 
Amounts written off, less recoveries(4)(12)(5)
Balance as of end of year$16 $5 $15 
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 Years Ended December 31,
 2017 2016 2015
Balance as of beginning of year$6
 $6
 $6
Increase in provision6
 5
 6
Amounts written off, less recoveries(6) (5) (6)
Balance as of end of year$6
 $6
 $6
      

Trust Accounts

Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust includes amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein. In 2014 and 2013, the Company received $6 million and $44 million, respectively, from the settlement of a legal matter concerning costs associated with the operation of the ISFSI. Those funds were deposited into the Nuclear decommissioning trust. For additional information concerning the legal matter, see Note 7, Asset Retirement Obligations. In anticipation of the refund of the settlement amount to customers over a three-year period that began in 2015, those funds were withdrawn from the Nuclear decommissioning trust during 2015.

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

The trusts are comprised of the following investments as of December 31 (in millions):  
 
Nuclear
    Decommissioning Trust    
 
    Non-Qualified Benefit    
Plan Trust
 2017 2016 2017 2016
Cash equivalents$25
 $21
 $1
 $1
Marketable securities, at fair value:       
Equity securities—
 —
 7
 6
Debt securities17
 20
 1
 1
Insurance contracts, at cash surrender value—
 —
 28
 26
 $42
 $41
 $37
 $34
        

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


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*    As of December 31, 2020, PGE has deferred as a regulatory asset $8 million in bad debt expense pursuant to the OPUC’s COVID-19 deferral order.

Other Current Assets and Accrued Expenses and Other Current Liabilities


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

As of December 31,
20202019
Other current assets:
Prepaid expenses$57 $63 
Margin deposits8 16 
Assets from price risk management activities33 25 
$98 $104 
Accrued expenses and other current liabilities:
Regulatory liabilities—current$23 $44 
Accrued employee compensation and benefits67 74 
Accrued dividends payable38 36 
Accrued interest payable29 25 
Accrued taxes payable36 33 
Other129 103 
$322 $315 

Electric Utility Plant, Net

Electric utility plant, net consist of the following (in millions):
As of December 31,
20202019
Electric utility plant:
Generation$4,436 $4,749 
Transmission970 848 
Distribution4,136 3,917 
General679 656 
Intangible753 758 
Total in service10,974 10,928 
Accumulated depreciation and amortization(3,864)(4,095)
Total in service, net7,110 6,833 
Construction work-in-progress429 328 
Electric utility plant, net$7,539 $7,161 
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 As of December 31,
 2017 2016
Other current assets:   
Prepaid expenses$50
 $48
Margin deposits11
 8
Assets from price risk management activities6
 18
Other6
 3
 $73
 $77
Accrued expenses and other current liabilities:   
Regulatory liabilities—current$31
 $51
Accrued employee compensation and benefits60
 52
Accrued dividends payable31
 30
Accrued interest payable27
 25
Accrued taxes payable31
 25
Other61
 71
 $241
 $254
    
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NOTE 4:5: FAIR VALUE OF FINANCIAL INSTRUMENTS


PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 20172020 and 2016, and2019. The Company then classifies these financial assets and liabilities based on a fair value hierarchy that is usedapplied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are discussed below.


Level 1Quoted prices are available in active markets for identical assets or liabilities as of the measurement date.
Level 1Quoted prices are available in active markets for identical assets or liabilities as of the measurement date.
 
Level 2Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date.

Level 2Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date.
Level 3Pricing inputs include significant inputs which are unobservable for the asset or liability.


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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.


PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no0 significant transfers between levels during the years ended December 31, 20172020 and 2016,2019, except those presented in this note.


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The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): 
 As of December 31, 2017
 Level 1 Level 2 Level 3 
Other(2)
 Total
Assets:         
Nuclear decommissioning trust: (1)
         
Debt securities:         
Domestic government$4
 $7
 $—
 $—
 $11
Corporate credit—
 6
 —
 —
 6
Money market funds measured at NAV (2)
—
 —
 —
 25
 25
Non-qualified benefit plan trust: (3)
         
Money market funds1
 —
 —
 —
 1
Equity securities—domestic7
 —
 —
 —
 7
Debt securities—domestic government1
 —
 —
 —
 1
Investments measured at NAV: (2)
         
Collective trust—domestic equity—
 —
 —
 —
 —
Assets from price risk management activities: (1) (4)
         
Electricity—
 3
 —
 —
 3
Natural gas—
 3
 —
 —
 3
 $13
 $19
 $—
 $25
 $57
Liabilities - Liabilities from price risk management activities: (1) (4)
         
Electricity$—
 $5
 $130
 $—
 $135
Natural gas—
 66
 9
 —
 75
 $—
 $71
 $139
 $—
 $210
          
As of December 31, 2020
Level 1Level 2Level 3
Other(2)
Total
Assets:
Cash equivalents$255 $0 $0 $— $255 
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government9 11 0 — 20 
Corporate credit0 13 0 — 13 
Money market funds measured at NAV (2)
— — — 12 12 
Non-qualified benefit plan trust: (3)
Money market funds1 0 0 — 1 
Equity securities—domestic7 0 0 — 7 
Debt securities—domestic government1 0 0 — 1 
Price risk management activities: (1) (4)
Electricity0 4 4 — 8 
Natural gas0 36 1 — 37 
$273 $64 $5 $12 $354 
Liabilities:
Price risk management activities: (1) (4)
Electricity$0 $5 $141 $— $146 
Natural gas0 4 1 — 5 
$0 $9 $142 $— $151 
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)
Excludes insurance policies of $28 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Price Risk Management.


(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.
(4)For further information regarding price risk management derivatives, see Note 6, Risk Management.
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As of December 31, 2019
Level 1Level 2Level 3
Other(2)
Total
Assets:
Cash equivalents$26 $0 $0 $— $26 
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government8 16 0 — 24 
Corporate credit0 9 0 — 9 
Money market funds measured at NAV (2)
— — — 13 13 
Non-qualified benefit plan trust: (3)
Money market funds1 0 0 — 1 
Equity securities—domestic7 0 0 — 7 
Debt securities—domestic government1 0 0 — 1 
Price risk management activities: (1) (4)
Electricity0 9 7 — 16 
Natural gas0 21 1 — 22 
$43 $55 $8 $13 $119 
Liabilities:
Price risk management activities: (1) (4)
Electricity$0 $14 $105 $— $119 
Natural gas0 12 0 — 12 
$0 $26 $105 $— $131 
 As of December 31, 2016
 Level 1 Level 2 Level 3 
Other(2)
 Total
Assets:         
Nuclear decommissioning trust: (1)
         
Debt securities:         
Domestic government$2
 $10
 $—
 $—
 $12
Corporate credit—
 8
 —
 —
 8
Money market funds measured at NAV (2)
—
 —
 —
 21
 21
Non-qualified benefit plan trust: (3)
         
Money market funds1
 —
 —
 —
 1
Equity securities—domestic4
 —
 —
 —
 4
Debt securities—domestic government1
 —
 —
 —
 1
Investments measured at NAV: (2)
         
Collective trust—domestic equity—
 —
 —
 2
 2
Assets from price risk management activities: (1) (4)
         
Electricity—
 6
 1
 —
 7
Natural gas—
 15
 1
 —
 16
 $8
 $39
 $2
 $23
 $72
Liabilities - Liabilities from price risk management activities: (1) (4)
         
Electricity$—
 $6
 $112
 $—
 $118
Natural gas—
 42
 9
 —
 51
 $—
 $48
 $121
 $—
 $169
          
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)
Excludes insurance policies of $26 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Price Risk Management.

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.
(4)For further information regarding price risk management derivatives, see Note 6, Risk Management.

Cash equivalents arehighly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted-average maturity of securities held by the funds do not exceed 90 days and investors have the ability to redeem shares daily at the net asset value of the respective fund. Cash equivalents are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE).

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


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


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


Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the

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measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE).NYSE.


Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.


The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.


Common and collective trust funds—PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. The funds allow for daily liquidity with appropriate notice. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient. All collective trusts for the NQBP were liquidated during 2017.

Assets and liabilities from price risk management activities, are recorded at fair value in PGE’s consolidated balance sheets, and consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price risk and foreign currency exchange rate risk,rates and reduce volatility in NVPC for the Company’s retail customers.NVPC. For additional information regarding these assets and liabilities, see Note 5, Price6, Risk Management.


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


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



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

SignificantPrice per Unit
Fair ValueValuationUnobservableWeighted
Commodity ContractsAssetsLiabilitiesTechniqueInputLowHighAverage
(in millions)
As of December 31, 2020:
Electricity physical forwards$0 $141 Discounted cash flowElectricity forward price (per MWh)$11.17 $51.18 $29.74 
Natural gas financial swaps1 1 Discounted cash flowNatural gas forward price (per Dth)1.52 4.33 2.29 
Electricity financial futures4 0 Discounted cash flowElectricity forward price (per MWh)8.78 58.42 43.71 
$5 $142 
As of December 31, 2019:
Electricity physical forwards$0 $104 Discounted cash flowElectricity forward price (per MWh)$12.53 $59.00 $36.92 
Natural gas financial swaps1 0 Discounted cash flowNatural gas forward price (per Dth)1.39 3.73 1.90 
Electricity financial futures7 1 Discounted cash flowElectricity forward price (per MWh)10.57 66.32 45.11 
$8 $105 
        Significant Price per Unit
  Fair Value Valuation Unobservable     Weighted
Commodity Contracts Assets Liabilities Technique Input Low High Average
  (in millions)          
As of December 31, 2017:            
Electricity physical forward $—
 $130
 Discounted cash flow Electricity forward price (per MWh) $7.79
 $41.23
 $30.95
Natural gas financial swaps —
 9
 Discounted cash flow Natural gas forward price (per Dth) 1.26
 2.92
 1.90
Electricity financial futures —
 —
 Discounted cash flow Electricity forward price (per MWh) 7.79
 29.74
 21.74
  $—
 $139
          
As of December 31, 2016:            
Electricity physical forward $—
 $112
 Discounted cash flow Electricity forward price (per MWh) $14.25
 $54.73
 $38.18
Natural gas financial swaps 1
 9
 Discounted cash flow Natural gas forward price (per Dth) 1.85
 4.92
 2.64
Electricity financial futures 1
 —
 Discounted cash flow Electricity forward price (per MWh) 8.57
 33.60
 25.10
  $2
 $121
          
               


The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter termshorter-term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer termlonger-term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.


The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable InputPositionChange to InputImpact on Fair Value Measurement
Market priceBuyIncrease (decrease)Gain (loss)
Market priceSellIncrease (decrease)Loss (gain)


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


 Years Ended December 31,
 2017 2016
Net liabilities from price risk management activities as of beginning of year$119
 $119
Net realized and unrealized losses *
35
 11
Net transfers in to Level 3 from Level 2—
 (1)
Net transfers out of Level 3 to Level 2(15) (10)
Net liabilities from price risk management activities as of end of year$139
 $119
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting$41
 $11
    
Years Ended December 31,
20202019
Net liabilities from price risk management activities as of beginning of year$97 $88 
Net realized and unrealized losses/(gains) *
38 10 
Net transfers from Level 3 to Level 22 (1)
Net liabilities from price risk management activities as of end of year$137 $97 
Level 3 net unrealized losses/(gains) that have been fully offset by the effect of regulatory accounting$47 $16 
* Includes $9 million innet realized gains in 2020 and $6 million innet realized losses in 2017 and none in 2016. 2019.


Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the yearyears ended December 31, 2017,2020 and 2019, there were no0 transfers into Level 3 from Level 2, as reflected in the table above. During 2016, there was $1 million transferred into Level 3.2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers ininto and transfers out offrom Level 3 at the end of the reporting period for all of its derivative instruments.

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.


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


As of December 31, 2017,2020, the carrying amount of PGE’s long-term debt was $2,426$3,046 million, net of $10$13 million of unamortized debt expense, and its estimated aggregate fair value was$2,829 million, all of which is classified as Level 2 in the fair value hierarchy.3,808 million. As of December 31, 2016,2019, the carrying amount of PGE’s long-term debt was $2,350$2,597 million, net of $11 million of unamortized debt expense, with an estimated aggregate fair value of $2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.$3,039 million.


For fair value information concerning the Company’s pension plan assets, see Note 10,11, Employee Benefits.


NOTE 5: PRICE6: RISK MANAGEMENT


Price Risk Management

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existingthe Company’s long-term wholesale contracts. Such activitiesWholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions forwith respect to Company-owned generating resources. As a result of this

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ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flow.flows.


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


PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):
 As of December 31, 
 2017 2016 
Current assets:    
Commodity contracts:    
Electricity$3
 $6
 
Natural gas3
 12
 
Total current derivative assets6
(1) 
18
(1) 
Noncurrent assets:    
Commodity contracts:    
Electricity—
 1
 
Natural gas—
 4
 
Total noncurrent derivative assets—
(2) 
5
(2) 
Total derivative assets not designated as hedging instruments$6
 $23
 
Total derivative assets$6
 $23
 
Current liabilities:    
Commodity contracts:    
Electricity$13
 $12
 
Natural gas46
 32
 
Total current derivative liabilities59
 44
 
Noncurrent liabilities:    
Commodity contracts:    
Electricity122
 106
 
Natural gas29
 19
 
Total noncurrent derivative liabilities151
 125
 
Total derivative liabilities not designated as hedging instruments$210
 $169
 
Total derivative liabilities$210
 $169
 
As of December 31,
20202019
Current assets:
Commodity contracts:
Electricity$4 $9 
Natural gas29 16 
Total current derivative assets(1)
33 25 
Noncurrent assets:
Commodity contracts:
Electricity4 7 
Natural gas8 6 
Total noncurrent derivative assets(1)
12 13 
Total derivative assets(2)
$45 $38 
Current liabilities:
Commodity contracts:
Electricity$13 $14 
Natural gas2 9 
Total current derivative liabilities15 23 
Noncurrent liabilities:
Commodity contracts:
Electricity133 105 
Natural gas3 3 
Total noncurrent derivative liabilities136 108 
Total derivative liabilities(2)
$151 $131 
(1)Included in Other current assets on the consolidated balance sheets.
(2)Included in Other noncurrent assets on the consolidated balance sheets.


(1)Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the consolidated balance sheets.
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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
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PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions):
As of December 31,
20202019
Commodity contracts:
Electricity6 MWh6 MWh
Natural gas137 Dth145 Dth
Foreign currency contracts$19 Canadian$23 Canadian
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 As of December 31,
 2017 2016
Commodity contracts:       
Electricity7
 MWh 8
 MWh
Natural gas114
 Dth 107
 Dth
Foreign currency exchange$21
 Canadian $22
 Canadian


PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement.arrangement at gross values on the consolidated balance sheet. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of December 31, 2017 and 2016,2020, gross amounts included as Price risk management liabilities subject to master netting agreements were $136$2 million, and $115 million, respectively, for which PGE has posted collateral of $11 million for 2017 and 2016, which consisted entirely of letters of credit. As0 collateral. Of the gross amounts recognized as of December 31, 2017, of the gross amounts included,$1302020, $1 million was for electricity and $6$1 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized asgas. As of December 31, 2016.2019, PGE had no material gross master netting arrangements.


Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions):
 
Years Ended December 31,
202020192018
Commodity contracts:
Electricity$160 $20 $(34)
Natural Gas(34)(32)21 
Foreign currency contracts(1)(1)1 
 Years Ended December 31,
 2017 2016 2015
Commodity contracts:     
Electricity$41
 $34
 $72
Natural Gas85
 (56) 103
Foreign currency exchange(1) —
 1
Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net amounts recognized in Net income, net losses of $82$12 million,, net gains of $13$2 million,, and net lossesgains of $160$18 million for the years ended December 31, 2017, 2016,2020, 2019 and 2015,2018, respectively, have been offset in Net income.offset.


Assuming no changes in market prices and interest rates, the following table presents the yearyears in which the net unrealized loss(gains)/losses recorded as of December 31, 20172020 related to PGE’s derivative activities would bebecome realized as a result of the settlement of the underlying derivative instrument (in millions):
 2018 2019 2020 2021 2022 Thereafter Total
Commodity contracts:             
Electricity$10
 $8
 $8
 $8
 $7
 $91
 $132
Natural gas43
 20
 7
 2
 —
 —
 72
Net unrealized loss$53
 $28
 $15
 $10
 $7
 $91
 $204
              

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 20212022202320242025ThereafterTotal
Commodity contracts:
Electricity$9 $4 $8 $8 $9 $100 $138 
Natural gas(27)(5)0 0 0 0 (32)
 Net unrealized (gain)/loss$(18)$(1)$8 $8 $9 $100 $106 
PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.


The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 20172020 was $205$148 million,, for which the Company hadhas posted$3113 million in collateral, consisting entirelyof $12 million of letters of credit.credit and $1 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at as of December 31, 2017,2020, the cash requirement to either post as collateral or settle the instruments immediately would have been $202$142 million. As of December 31, 2017,2020, PGE had no$6 million posted cash collateral for derivative instruments with no credit-risk-related contingent features. Cash
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collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s consolidated balance sheet.


Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:
As of December 31,As of December 31,
2017 201620202019
Assets from price risk management activities:   Assets from price risk management activities:
Counterparty A39% 22%Counterparty A12 %35 %
Counterparty B12
 17
Counterparty B17 13 
Counterparty C3
 12
Counterparty C21 11 
Counterparty DCounterparty D16 11 
54% 51%66 %70 %
Liabilities from price risk management activities:   Liabilities from price risk management activities:
Counterparty D62% 66%
62% 66%
Counterparty ECounterparty E93 %79 %
For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 4,5, Fair Value of Financial Instruments.



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NOTE 6:7: REGULATORY ASSETS AND LIABILITIES


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


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


Remaining Amortization PeriodAs of December 31,
20202019
Earning a Return (1)
Not Earning a ReturnTotalTotal
Regulatory assets:
Price risk management2035$0 $124 $124 $95 
Pension plan(2)0 240 240 213 
Debt issuance costs20500 25 25 26 
Trojan decommissioning activities20590 95 95 94 
OtherVarious87 22 109 72 
Total regulatory assets$87 $506 $593 $500 
Regulatory liabilities:
Asset retirement removal costs(3)$1,016 $0 $1,016 $1,021 
Deferred income taxes(4)239 0 239 260 
Asset retirement obligations(3)37 0 37 54 
Tax reform deferral (5)
20200 0 0 23 
Price risk management20210 18 18 2 
OtherVarious46 36 82 61 
Total regulatory liabilities$1,338 $54 $1,392 $1,421 
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Weighted Average Remaining
Life (1)
 As of December 31,
 2017 2016
 Current Noncurrent Current Noncurrent
Regulatory assets:         
Price risk management (2)
6 years $53
 $151
 $26
 $120
Pension and other postretirement plans (2)
(3) 
 —
 218
 —
 235
Deferred income taxes (6)
(4) 
 —
 —
 —
 86
Debt issuance costs (2)
6 years —
 19
 —
 22
Other (5)
Various 9
 50
 10
 35
Total regulatory assets  $62
 $438
 $36
 $498
Regulatory liabilities:         
Asset retirement removal costs (6)
(4) 
 $—
 $933
 $—
��$887
Deferred income taxes (6)
(4) 
 —
 277
 —
 —
Trojan decommissioning activities5 years 3
 —
 18
 —
Asset retirement obligations (6)
(4) 
 —
 52
 —
 49
OtherVarious 28
 26
 33
 22
Total regulatory liabilities  $31
(7) 
$1,288
 $51
(7) 
$958
(1)
As of December 31, 2017.
(2)Does not include a return on investment.
(3)Recovery expected over the average service life of employees.
(4)Recovery or refund expected over the estimated lives of the net balance.
(5)
Of the total other unamortized regulatory asset balances, a return is recorded on $51 million and $44 million as of December 31, 2017 and 2016, respectively.
(6)Included in rate base for ratemaking purposes.
(7)Included in Accrued expenses and other current liabilities on the consolidated balance sheets.

As of December 31, 2017, PGE had regulatory assets of $51 million earning(1)Earning a return includes either interest on investmentthe regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the following rates: i) $14 million earning a return by inclusion in rate base; ii) $25 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 2.38%, depending on the year of approval; iii) $10 million at PGE’s 2017 cost of capital of 7.51%, and iv) $2 million at aallowed rate of return.
(2)Recovery expected over the 5-year Treasuryaverage service life of employees.
(3)Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate plus 100 basis points, which currently equatesbase.
(4)Refund expected primarily through amortization using the average rate assumption method over the average life of the underlying assets and treated as a reduction to 2.87%.rate base.

(5)Refund related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest, over a two-year period that began in 2019.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price6, Risk Management.



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Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic pension and postretirement benefit cost. For further information, see Note 10, Employee Benefits.
Deferred income taxes represents income tax benefits primarily from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. In 2017, the net regulatory liability was increased by $357 million as the Company deferred the impact of re-measuring accumulated deferred income taxes pursuant to the enactment of the Tax Cuts and Jobs Act (the TCJA) on December 22, 2017. PGE has proposed to defer and refund the net benefits of the change in tax law under a deferral application filed with the OPUC on December 29, 2017. Substantially all of the amounts deferred under the proposed deferral application are subject to tax normalization rules that require that the impact to the results of operations of amortizing the excess deferred income tax balance cannot occur more rapidly than would have occurred before the change in tax law. The Company plans to use the average rate assumption method to account for the refund to customers.costs. For further information, see Note 11, Income Taxes.Employee Benefits.

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


Trojan decommissioning activities represents the deferral of ongoing costs associated with monitoring spent nuclear fuel at Trojan, net of amortization of customer collections. In addition, proceeds received from the United States Department of Energy (USDOE) for the reimbursement of costs to monitor the ISFSI is deferred and offsets customer collections.

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


Trojan decommissioning activitiesDeferred income taxes represents proceeds receivedincome tax benefits primarily from property-related timing differences that will be refunded to customers when the temporary differences reverse. Substantially all of the amounts deferred are subject to tax normalization rules that require that the impact to the results of operations of amortizing the excess deferred income tax balance cannot occur more rapidly than over the book life of the related assets. The Company uses the average rate assumption method to account for the settlement of a legal matter concerning the reimbursement from the United States Department of Energy (USDOE) of certain monitoring costs incurred relatedrefund to spent nuclear fuel at Trojan, as well as ongoing costs and collections associated with decommissioning activities.customers. For further information, see Note 12, Income Taxes.


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



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NOTE 7:8: ASSET RETIREMENT OBLIGATIONS


AROs consist of the following (in millions):
 As of December 31,
 20202019
Trojan decommissioning activities$139 $137 
Utility plant118 126 
Non-utility property34 16 
Total asset retirement obligations291 279 
Less: current portion *21 16 
Noncurrent asset retirement obligations$270 $263 
*    Current portion of AROs are classified within Accrued expenses and other current liabilities in the consolidated balance sheets.
 As of December 31,
 2017 2016
Trojan decommissioning activities$45
 $44
Utility plant109
 105
Non-utility property13
 12
Asset retirement obligations$167
 $161
    

Trojan decommissioning activities represents the present value of future decommissioning costs for the plant,PGE’s 67.5% ownership interest in Trojan, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the ISFSI, an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI is to housewill store the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a USDOE facility is complete, which is not expected prior to 2034.2059. The Company recorded accretion of $6 million and a reduction of $4 million due to settled liabilities.


In 2004,Under a settlement agreement reached with the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint againstUSDOE, the Company receives annual reimbursement from the USDOE for failurecertain costs related to acceptmonitoring the ISFSI. Pursuant to this process, the USDOE reimbursed the co-owners $5 million in 2020 for costs incurred in 2019 and $4 million in 2019 for costs incurred in 2018 resulting from USDOE delays in accepting spent nuclear fuelfuel.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, and distribution and transmission assets, the disposal of which is governed by January 31, 1998. PGE, which holds a 67.5% ownership interestenvironmental regulation. During 2020, the Company recorded an overall decrease in Trojan, had contractedutility AROs of$8 million, with the USDOEchange comprised of new liabilities incurred of $5 million, reduction of $4 million due to revisions in estimated cash flows, accretion of $4 million, and a reduction of$13 million due to settled liabilities.

Non-utility property primarily represents AROs that have been recognized for portions of unregulated properties that are currently or previously leased to third parties. Revisions to estimates for non-utility AROs relate to assets that are no longer in service and the offset is charged directly to Depreciation and amortization on the consolidated statements of income in the period in which the revisions are probable and reasonably estimate. Non-utility AROs are not subject to regulatory deferral.

In 2020, PGE performed a decommissioning study to update its ARO liability which resulted in a $21 million increase to non-utility property AROs. As part of this study, the Company also established an ARO liability of $3 million related to utility properties and was charged to expense in the consolidated statement of income. PGE plans to pursue regulatory recovery for the permanent disposalutility portion of the ARO update, however as of December 31, 2020 no amounts have been deferred as a regulatory asset.



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spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs sought reimbursement for damages incurred through 2009.

A trial before the U.S. Court of Federal Claims concluded in 2012, with the Court issuing a judgment awarding certain damages to the Plaintiffs. The settlement agreement also provides for a process to submit claims for allowable costs for the periods subsequent to 2009, including an extension to cover costs through 2019. Pursuant to this process, the USDOE has reimbursed the Plaintiffs $85 million for costs incurred through 2016 resulting from USDOE delays in accepting spent nuclear fuel.

PGE has received proceeds of $53 million related to its share in this legal matter. The settlement amounts received were recorded as a regulatory liability to offset amounts previously collected in relation to Trojan decommissioning activities. In December 2014, the OPUC issued an order on the Company’s 2015 GRC, authorizing the return of $50 million of the proceeds received related to this legal matter to customers over a three-year period beginning January 1, 2015. PGE will return the remaining $3 million to customers in 2018.

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

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets, the disposal of which is governed by environmental regulation. During 2017, the Company recorded an overall increase in AROs, including Trojan, of$6 million, with the change comprised of an increase to revisions in estimated cash flows and incurred liabilities of $2 million, accretion of $7 million, and a reduction of$3 million due to settled liabilities.

In 2015, the Company recorded an increase to the Colstrip ARO in the amount of $17 million, as Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet new EPA regulatory requirements. PGE plans to seek recovery in customer prices of the incremental costs associated with the final EPA rules.

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

The following is a summary of the changes in the Company’s AROs (in millions):
 Years Ended December 31,
 202020192018
Balance as of beginning of year$279 $197 $167 
Liabilities incurred3 0 0 
Liabilities settled(18)(9)(5)
Accretion expense10 9 8 
Revisions in estimated cash flows17 82 27 
Balance as of end of year$291 $279 $197 
 Years Ended December 31,
 2017 2016 2015
Balance as of beginning of year$161
 $151
 $116
Liabilities incurred2
 1
 2
Liabilities settled(3) (3) (4)
Accretion expense7
 7
 7
Revisions in estimated cash flows—
 5
 30
Balance as of end of year$167
 $161
 $151


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



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


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


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NOTE 8:9: CREDIT FACILITIES


As of December 31, 2017,2020, PGE had a $500 million revolving credit facility scheduled to expire inNovember 2021.2023. The Company has the ability to expand the revolving credit facility to $600 million, if needed. The credit facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% approve the extension request.


Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings, and to permit the issuance of standby letters of credit. PGE may borrow for one,, two,, three,, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2017,2020, PGE was in compliance with this covenant with a 51.8%56.4% debt to total capital ratio.


PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets.

Under the revolving credit facility, as of December 31, 2020, PGE had 0 borrowings outstanding and there were 0 commercial paper or letters of credit issued. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

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

PGE classifies anylimit its borrowings under the revolving credit facility and outstandingto cover any potential need to repay commercial paper as Short-term debt inthat may be outstanding at the consolidated balance sheets.

time. As of December 31, 2020, PGE had no borrowings outstanding and there was no commercial paper or letters of credit issued under the revolving credit facility as of December 31, 2017. As a result, as of December 31, 2017, the aggregate unused available credit capacity under the revolving credit facility was $500 million.outstanding.


In addition, PGE hasfour letter of credit facilities that provide capacity up to a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, $67a total of $60 million of letters of credit waswere outstanding as of December 31, 2017.2020. Outstanding letters of credit are not reflected on the Company’s consolidated balance sheets.


On April 9, 2020, PGE obtained a 364-day unsecured term loan from lenders in the aggregate principal of $150 million. The term loan bears interest for the relevant interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement is classified as Short-term debt on the Company’s consolidated balance sheets and expires on April 8, 2021, with any outstanding balance due and payable on such date.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount up to $900$900 million through February 6, 2020.2022.


Short-term borrowings under these credit facilities, and related interest rates, are reflected in the following table (dollars in millions). The Company had no short-term borrowings during 2017.
 Years Ended December 31,
 2017 2016 2015
Average daily amount of short-term debt outstanding$—
 $1
 $—
Weighted daily average interest rate *—% 0.7% 0.6%
Maximum amount outstanding during the year$—
 $23
 $11
 Year Ended December 31,
20202019
Average daily amount of short-term debt outstanding$131 $7 
Weighted daily average interest rate *1.5 %2.6 %
Maximum amount outstanding during the year$225 $46 
*Excludes the effect of commitment fees, facility fees and other financing fees.

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

The Company had 0 short-term borrowings during 2018.

NOTE 9:10: LONG-TERM DEBT
Long-term debt consists of the following (in millions):
As of December 31,
As of December 31, 20202019
First Mortgage Bonds, rates range from 1.84% to 9.31%, with a weighted average rate of 4.14% in 2020 and 4.63% in 2019, due at various dates through 2050
First Mortgage Bonds, rates range from 1.84% to 9.31%, with a weighted average rate of 4.14% in 2020 and 4.63% in 2019, due at various dates through 2050
$2,940 $2,510 
2017 2016
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 5.03% in 2017 and 4.86% in 2016, due at various dates through 2048
$2,315
 $2,090
Unsecured term bank loans, variable rates of approximately 1.87% at 11/27/2017 and 1.37% at 12/31/2016
—
 150
Pollution Control Revenue Bonds, 5% rate, due 2033
142

142
Pollution Control Revenue Bonds owned by PGE(21) (21)
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033
119 119 
Pollution Control Revenue Bonds held by PGEPollution Control Revenue Bonds held by PGE0 (21)
Total long-term debt2,436
 2,361
Total long-term debt3,059 2,608 
Less: Unamortized debt expense(10) (11)Less: Unamortized debt expense(13)(11)
Less: Current portion of long-term debt—
 (150)Less: Current portion of long-term debt(160)0 
Long-term debt, net of current portion$2,426
 $2,200
Long-term debt, net of current portion$2,886 $2,597 
   


First Mortgage Bonds and Unsecured term bank loans—During 2017,On April 27, 2020, PGE issued a total of $225$200 million of 3.15% Series FMBs and repaid long-term debt,due in an2030.

On December 10, 2020, PGE issued $230 million aggregate principal amount of $150 million.the Company's FMBs that consisted of:


In 2017,•a series, due in 2027, in the Company issued a totalamount of $225$160 million that will bear interest from its issuance date at an interestannual rate of 3.98%. PGE drew $751.84%; and

•a series, due in 2032, in the amount of $70 million in August with a maturitythat will bear interest from its issuance date at an annual rate of 2048 and drew the remaining $150 million in November with a maturity of 2047.2.32%.


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


In 2017, PGE repaid an unsecured credit agreement under which it had borrowed $150 million from certain financial institutions. PGE repaid the loan in three separate payments as follows:

$50 million on August 21, 2017;

$25 million on October 30, 2017; and

$75 million on November 27, 2017.

The term loan interest rates were set at the beginning of the interest period for periods of 1-month, 3-months, or 6-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 63 basis points. The final rate was 1.87% as of November 27, 2017, with no other fees.

Pollution Control Revenue Bonds—The Company hasOn March 11, 2020, PGE completed the option to remarket through 2033 the $21remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCBs) held by PGE as(PCRBs), which consist of December 31, 2017.$98 million aggregate principal of PCRBs that bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that bear an interest rate of 2.375%, both due in 2033. At the time of any remarketing, the Company can choosechose a new interest rate period that could be daily, weekly, or awas fixed term. The new interest rate would bewas based on market conditions at the time of remarketing. The PCBsPCRBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on PCBs.the PCRBs.



As of December 31, 2020, the future minimum principal payments on long-term debt are as follows (in millions):
Years ending December 31: 
2021$160 
20220 
20230 
202480 
20250 
Thereafter2,819 
$3,059 
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As of December 31, 2017, the future minimum principal payments on long-term debt are as follows (in millions):
Years ending December 31:  
2018 $—
2019 300
2020 —
2021 160
2022 —
Thereafter 1,976
  $2,436
   

NOTE 10:11: EMPLOYEE BENEFITS


Pension and Other Postretirement Plans


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


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


As expected, PGE contributed $2 million0 additional funds to the pension plan in 2017, and made no contributions2020 after contributing $62 million in 2016 or 2015.2019. PGE expectsdoes not expect to contribute$21 million to the pension plan in 2018.2021.


Other Postretirement Benefits—PGE hasoffers non-contributory postretirement health and life insurance plans, as well asand provides health reimbursement arrangements (HRAs) forto its employees (collectively, “Other Postretirement Benefits” in the following tables). Participants are covered under a Defined Dollar Medical Benefit Plan, which limits PGE’s obligation pursuant to the postretirement health plan is limited by establishing a maximum benefit per employee with employees responsible forany additional cost the additional cost.responsibility of the employee.


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


Non-Qualified Benefit Plan—The NQBP in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also includes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. The assets of such trust are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond,bonds, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the NQBP is December 31. For further information regarding these trust investments, see Note 5, Fair Value of Financial Instruments.


Other NQBP—In addition to the NQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These

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unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a NQBP trust that are intended to be a funding source for these plans.


Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions):
 2017 2016
  NQBP Other NQBP Total NQBP Other NQBP Total
Non-qualified benefit plan trust$17
 $20
 $37
 $16
 $18
 $34
Non-qualified benefit plan liabilities *25
 81
 106
 25
 80
 105
 20202019
  NQBPOther NQBPTotalNQBPOther NQBPTotal
Non-qualified benefit plan trust$19 $23 $42 $17 $21 $38 
Non-qualified benefit plan liabilities *26 75 101 24 79 103 
*
For the NQBP, excludes the current portion of $2 million in 2017 and 2016, respectively, which are classified in Other current liabilities in the consolidated balance sheets.

See “Trust Accounts” in Note 3, Balance Sheet Components, for information on*    For the NQBP, trust.excludes the current portion of $2 million in 2020 and in 2019, which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets.

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Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of certain members of management from the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for the implementation of the asset allocation and oversight of the benefit plan investments. The Company’s investment policystrategy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities, and other alternative investments. Asset classes are regularly rebalanced to ensure asset allocations remain within prescribed parameters.
 

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The asset allocations for the plans, and the target allocation, are as follows: 
 As of December 31,
  2017 2016
 Actual Target * Actual Target *
Defined Benefit Pension Plan:       
Equity securities68% 67% 68% 67%
Debt securities32
 33
 32
 33
Total100% 100% 100% 100%
Other Postretirement Benefit Plans:       
Equity securities63% 62% 60% 62%
Debt securities37
 38
 40
 38
Total100% 100% 100% 100%
Non-Qualified Benefits Plans:       
Equity securities18% 12% 15% 11%
Debt securities6
 12
 7
 11
Insurance contracts76
 76
 78
 78
Total100% 100% 100% 100%
 As of December 31,
  20202019
ActualTarget *ActualTarget *
Defined Benefit Pension Plan:
Equity securities67 %65 %64 %65 %
Debt securities33 35 36 35 
Total100 %100 %100 %100 %
Other Postretirement Benefit Plans:
Equity securities60 %57 %61 %59 %
Debt securities40 43 39 41 
Total100 %100 %100 %100 %
Non-Qualified Benefits Plans:
Equity securities17 %12 %17 %12 %
Debt securities6 11 7 12 
Insurance contracts77 77 76 76 
Total100 %100 %100 %100 %
*The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools.

*    The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools.

The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments across

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The fair values of the capitalization rangesCompany’s pension plan assets and style biases, both domestically and internationally. Fixed income securities include, butother postretirement benefit plan assets by asset category are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.as follows (in millions):

 Level 1Level 2Level 3Other *Total
As of December 31, 2020:
Defined Benefit Pension Plan assets:
Equity securities—Domestic$49 $0 $0 $— $49 
Investments measured at NAV:
Money market funds— — — 6 6 
Collective trust funds— — — 692 692 
Private equity funds— — — 6 6 
$49 $0 $0 $704 $753 
Other Postretirement Benefit Plans assets:
Money market funds$4 $0 $0 $— $4 
Equity securities:
Domestic0 3 0 — 3 
International9 0 0 — 9 
Debt securities—Domestic0 5 0 — 5 
Investments measured at NAV:
Money market funds— — — 5 5 
Collective trust funds— — — 9 9 
$13 $8 $0 $14 $35 
As of December 31, 2019:
Defined Benefit Pension Plan assets:
Equity securities—Domestic$49 $0 $0 $— $49 
Investments measured at NAV:
Money market funds— — — 5 5 
Collective trust funds— — — 632 632 
Private equity funds— — — 9 9 
$49 $0 $0 $646 $695 
Other Postretirement Benefit Plans assets:
Money market funds$4 $0 $0 $— $4 
Equity securities:
Domestic0 3 0 — 3 
International9 0 0 — 9 
Debt securities—Domestic government0 5 0 — 5 
Investments measured at NAV:
Money market funds— — — 5 5 
Collective trust funds— — — 8 8 
$13 $8 $0 $13 $34 
*Assets are measured at fair value using net asset value (NAV)NAV as a practical expedient areand not categorized in the fair value hierarchy.subject to hierarchy level classification disclosure. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.


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The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions):
 Level 1 Level 2 Level 3 Other * Total
As of December 31, 2017:         
Defined Benefit Pension Plan assets:         
Equity securities—Domestic$83
 $—
 $—
 $—
 $83
Investments measured at NAV:         
Money market funds—
 —
 —
 5
 5
Collective trust funds—
 —
 —
 528
 528
Private equity funds—
 —
 —
 13
 13
 $83
 $—
 $—
 $546
 $629
Other Postretirement Benefit Plans assets:         
Money market funds$3
 $—
 $—
 $—
 $3
Equity securities:         
Domestic—
 3
 —
 —
 3
International10
 —
 —
 —
 10
Debt securities—Domestic government—
 5
 —
 —
 5
Investments measured at NAV:         
Money market funds—
 —
 —
 4
 4
Collective trust funds—
 —
 —
 8
 8
 $13
 $8
 $—
 $12
 $33
As of December 31, 2016:         
Defined Benefit Pension Plan assets:         
Equity securities—Domestic$52
 $—
 $—
 $—
 $52
Investments measured at NAV:         
Money market funds—
 —
 —
 6
 6
Collective trust funds—
 —
 —
 483
 483
Private equity funds—
 —
 —
 18
 18
 $52
 $—
 $—
 $507
 $559
Other Postretirement Benefit Plans assets:         
Money market funds$4
 $—
 $—
 $—
 $4
Equity securities:         
Domestic—
 3
 —
 —
 3
International8
 —
 —
 —
 8
Debt securities—Domestic government—
 4
 —
 —
 4
Investments measured at NAV:         
Money market funds—
 —
 —
 4
 4
Collective trust funds$—
 $—
 $—
 $7
 $7
 $12
 $7
 $—
 $11
 $30
          
*Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.


An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 4,5, Fair Value of Financial Instruments. The following discussion provides information regarding the methods used in valuation of the various asset class investments held in the pension and other postretirement benefit plan trusts.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal


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Money market funds—PGE invests in money market funds that seek to maintain a stable NAV. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.


Equity securities—Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace.


Debt Securities—Debt security investment funds are classified as Level 2 securities as pricing for underlying securities are determined by evaluating pricing data, such as broker quotes for similar securities, adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, if applicable.

Collective trust funds—Domestic and international mutual fund assets included in commingled trusts or separately managed accounts are valued at NAV as a practical expedient and not included in the fair value hierarchy.

Debt securities,debt security assets, including municipal debt and corporate credit securities, mortgage-backed securities, and asset-backedasset back securities assets, are included in commingled trusts or separately managed accounts. The Company believes the redemption value of the collective trust funds are likely to be the fair value, which is represent by the net asset value as a practical expedient. The funds are valued at NAV as a practical expedient and are not includedclassified in the fair value hierarchy.


Private equity funds—PGE invests in a combination of primary and secondary fund-of-funds, which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient.

expedient and are not classified in the fair value hierarchy.
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The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and NQBP as of and for the years ended December 31, 20172020 and 2016.2019. Information related to the Other NQBP is not included in the following tables (dollars in millions):


 Defined Benefit Pension PlanOther Postretirement BenefitsNon-Qualified
Benefit Plans
  202020192020201920202019
Benefit obligation:
As of January 1$905 $811 $71 $72 $26 $24 
Service cost17 16 2 2 0 0 
Interest cost31 34 2 3 1 1 
Participants’ contributions0 0 0 2 0 0 
Actuarial loss (gain)104 88 4 8 3 3 
Benefit payments(44)(42)(4)(6)(2)(2)
Administrative expenses(3)(2)0 0 0 0 
Plan amendment— — 1 (9)— — 
Curtailment gain— — 0 (1)— — 
As of December 31$1,010 $905 $76 $71 $28 $26 
Fair value of plan assets:
As of January 1$695 $546 $34 $30 $17 $16 
Actual return on plan assets105 131 2 5 1 1 
Company contributions0 62 3 3 3 2 
Participants’ contributions0 0 0 2 0 0 
Benefit payments(44)(42)(4)(6)(2)(2)
Administrative expenses(3)(2)0 0 0 0 
As of December 31$753 $695 $35 $34 $19 $17 
Unfunded position as of December 31$(257)$(210)$(41)$(37)$(9)$(9)
Accumulated benefit plan obligation as of December 31$907 $813 N/AN/A$24 $26 
Classification in consolidated balance sheet:
Noncurrent asset$0 $0 $0 $0 $19 $17 
Current liability0 0 0 0 (2)(2)
Noncurrent liability(257)(210)(41)(37)(26)(24)
Net liability$(257)$(210)$(41)$(37)$(9)$(9)
Amounts included in comprehensive income:
Net actuarial loss (gain)$43 $(3)$4 $5 $3 $3 
Net prior service credit1 — 0 (9)— — 
Amortization of net actuarial loss(17)(10)0 0 (1)(1)
Amortization of prior service credit0 0 1 0 0 0 
$27 $(13)$5 $(4)$2 $2 
Amounts included in AOCL:*
Net actuarial loss (gain)$239 $213 $5 $1 $15 $13 
Prior service cost1 0 (8)(9)0 0 
$240 $213 $(3)$(8)$15 $13 
103
 Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
  2017 2016 2017  2016  2017 2016
Benefit obligation:             
As of January 1$797
 $758
 $73
  $81
  $27
 $27
Service cost17
 16
 2
  2
  —
 —
Interest cost33
 33
 3
  4
  1
 1
Participants’ contributions—
 —
 2
  2
  —
 —
Actuarial loss (gain)60
 26
 3
  (11)  1
 1
Contractual termination benefits—
 —
 1
  —
  —
 —
Benefit payments(36) (34) (6)  (5)  (2) (2)
Administrative expenses(2) (2) —
  —
  —
 —
As of December 31$869
 $797
 $78
  $73
  $27
 $27
Fair value of plan assets:             
As of January 1$559
 $550
 $30
  $30
  $16
 $15
Actual return on plan assets106
 45
 4
  1
  1
 1
Company contributions2
 —
 3
  2
  2
 2
Participants’ contributions—
 —
 2
  2
  —
 —
Benefit payments(36) (34) (6)  (5)  (2) (2)
Administrative expenses(2) (2) —
  —
  —
 —
As of December 31$629
 $559
 $33
  $30
  $17
 $16
Unfunded position as of December 31$(240) $(238) $(45)  $(43)  $(10) $(11)
Accumulated benefit plan obligation as of December 31$778
 $714
 N/A  N/A  $27
 $27
Classification in consolidated balance sheet:             
Noncurrent asset$—
 $—
 $—
  $—
  $17
 $16
Current liability—
 —
 —
  —
  (2) (2)
Noncurrent liability(240) (238) (45)  (43)  (25) (25)
Net liability$(240) $(238) $(45)  $(43)  $(10) $(11)
Amounts included in comprehensive income:             
Net actuarial loss (gain)$(4) $21
 $—
  $(10)  $1
 $1
Amortization of net actuarial loss(13) (14) —
  —
  (1) (1)
Amortization of prior service cost—
 —
 —
  (1)  —
 —
 $(17) $7
 $—
  $(11)  $—
 $—
Amounts included in AOCL*:             
Net actuarial loss (gain)$218
 $236
 $(1)  $(2)  $13
 $13
Prior service cost—
 —
 —
  1
  —
 —
 $218
 $236
 $(1)  $(1)  $13
 $13
              

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 Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
  2017 2016 2017  2016  2017 2016
Assumptions used:             
Discount rate for benefit obligation3.65% 4.17% 3.42%- 3.75%- 3.65% 4.17%
     3.70%  4.23%     
Discount rate for benefit cost4.17% 4.36% 3.75%- 3.90%- 4.17% 4.36%
     4.23%  4.45%     
Weighted average rate of compensation increase for benefit obligation4.58% 3.65% 4.58%  4.58%  N/A
 N/A
Weighted average rate of compensation increase for benefit cost3.65% 3.65% 4.58%  4.58%  N/A
 N/A
Long-term rate of return on plan assets for benefit obligation7.50% 7.50% 6.26%  6.26%  N/A
 N/A
Long-term rate of return on plan assets for benefit cost7.50% 7.50% 6.26%  6.29%  N/A
 N/A
              
* Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred toclassified as Regulatory assets due to theor liabilities as future recoverability is expected from retail customers. Accordingly, as

Significant actuarial gains (losses) experienced that resulted in changes in projected benefit obligation included the following:
•For the defined benefit pension plan, actuarial losses due to demographic experience, including assumption changes, were losses of $104 million and $88 million, and the changes between actual and expected return on plan assets were gains of $61 million and $94 million for the years ended December 31, 2020 and 2019, respectively.
•For the other postretirement benefits, actuarial losses due to demographic experience, including assumption changes, were losses of $5 million and $2 million, and the changes between actual and expected return on plan assets were gains of $1 million for each of the balance sheet date, such amounts are included in Regulatory assets.years ended December 31, 2020 and 2019, respectively.


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

 Defined Benefit
Pension Plan		Other Postretirement
Benefits		Non-Qualified
Benefit Plans
  202020192018202020192018202020192018
Service cost$17 $16 $19 $2 $2 $2 $0 $0 $0 
Interest cost on benefit obligation31 34 32 2 3 3 1 1 1 
Expected return on plan assets(44)(40)(42)(2)(2)(1)0 0 0 
Amortization of prior service credit0 0 0 (1)0 0 0 0 0 
Amortization of net actuarial loss17 10 17 0 0 0 1 1 1 
Curtailment gain— — — 0 (2)0 — — — 
Net periodic benefit cost$21 $20 $26 $1 $1 $4 $2 $2 $2 
 
Defined Benefit
Pension Plan
 
Other Postretirement
Benefits
 
Non-Qualified
Benefit Plans
  2017 2016 2015 2017 2016 2015 2017 2016 2015
Service cost$17
 $16
 $18
 $2
 $2
 $2
 $—
 $—
 $—
Interest cost on benefit obligation33
 33
 31
 3
 4
 3
 1
 1
 1
Expected return on plan assets(42) (40) (40) (2) (2) (2) —
 —
 —
Amortization of prior service cost—
 —
 —
 —
 1
 1
 —
 —
 —
Amortization of net actuarial loss13
 14
 20
 —
 —
 1
 1
 1
 1
Net periodic benefit cost$21
 $23
 $29
 $3
 $5
 $5
 $2
 $2
 $2
                  
PGE estimates that $18 million will be amortized from AOCL intoThe portion of non-service costs attributable to expense related to the pension and other postretirement benefit plans, is classified as Miscellaneous income (expense), net periodic benefit cost in 2018, consistingwithin Other income on the Company’s consolidated statements of a net actuarial loss of $17 million for pension benefits and $1 million for non-qualified benefits.income. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset.


The following assumptions were used in determining benefit obligations and net period benefit costs:
Defined Benefit Pension PlanOther Postretirement BenefitsNon-Qualified
Benefit Plans
202020192020201920202019
Assumptions used to determine benefit obligations: 
Discount rate2.64 %3.43 %2.22% -3.19% -2.64 %3.43 %
2.92 %3.47 %
Rate of compensation increase3.65 %3.65 %4.58 %4.58 %4.10 %N/A
Assumptions used to determine net periodic benefit cost:
Discount rate3.43 %4.25 %3.19% -3.11% -3.43 %3.43 %
3.47 %4.26 %
Rate of compensation increase3.65 %3.65 %4.58 %4.58 %4.10 %N/A
Long-term rate of return on plan assets7.00 %7.00 %5.02 %5.88 %N/AN/A

As of December 31, 2020, there are no liabilities with sensitivity to health care cost trend rates.
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Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets, or a 0.25% reduction in the discount rate, would have the effect of increasing the 2020 net periodic pension expense by approximately $2 million and$3 million, respectively.

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):
 Payments Due
  202120222023202420252026 - 2030
Defined benefit pension plan$45 $45 $46 $47 $47 $243 
Other postretirement benefits5 5 5 6 5 19 
Non-qualified benefit plans2 2 3 2 2 11 
Total$52 $52 $54 $55 $54 $273 
 Payments Due
  2018 2019 2020 2021 2022 2023 - 2026
Defined benefit pension plan$39
 $41
 $42
 $43
 $44
 $234
Other postretirement benefits5
 5
 5
 4
 5
 22
Non-qualified benefit plans2
 3
 2
 2
 2
 10
Total$46
 $49
 $49
 $49
 $51
 $266


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

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

For 2017, 6.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018, decreasing to 6.0% in 2019, then decreasing 0.25% per year thereafter, reaching5.0% in 2023;

For 2016, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017, decreasing to 6.5% in 2018, then decreasing 0.25% per year thereafter, reaching 5.0% in 2023; and

For 2015, 6.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016, decreasing to 6.0% in 2017, then decreasing 0.25% per year thereafter, reaching 5.0% in 2021.

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


401(k) Retirement Savings Plan


PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions to the 401(k) Plan up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay.


For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.


All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $21 million in 2017, $19$26 million in 2016, and $172020, $25 million in 2015.2019, and $23 million in 2018.


NOTE 11: INCOME TAXES

On December 22, 2017, 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.



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NOTE 12: INCOME TAXES
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 NQBPs. 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.

Based on the Company’s interpretations of the TCJA as of December 31, 2017, PGE believes it has substantially completed its analysis of the tax effects of the TCJA and has reflected such effects in the remeasurement amounts recorded. However, PGE has not yet finalized its federal tax returns for 2017 and also expects regulatory bodies, such as the U.S. Department of the Treasury, Internal Revenue Service, and OPUC to issue additional guidance or orders in 2018 that may result in changes to the Company’s previously finalized analysis of the TCJA. Such changes could result in material changes to the ultimate impact of the TCJA on PGE’s financial condition, results of operations, and cash flows.
Income tax expenseexpense/(benefit) consists of the following (in millions):
 Years Ended December 31,
  202020192018
Current:
Federal$6 $9 $12 
State and local17 12 22 
23 21 34 
Deferred:
Federal(22)(2)(15)
State and local(1)8 (2)
(23)6 (17)
Income tax expense$0 $27 $17 
 Years Ended December 31,
  2017 2016 2015
Current:     
Federal$4
 $10
 $4
State and local12
 3
 1
 16
 13
 5
Deferred:     
Federal61
 23
 26
State and local9
 14
 14
 70
 37
 40
Income tax expense$86
 $50
 $45
      


The significant differences between the U.S. federalFederal statutory rate and PGE’s effectiveEffective tax rate for financial reporting purposes are as follows:
 Years Ended December 31,
  2017 2016 2015
Federal statutory tax rate35.0 % 35.0 % 35.0 %
Federal tax credits(1)
(14.0) (18.2) (19.0)
Change in federal tax law(2)
6.1
 —
 —
State and local taxes, net of federal tax benefit5.0
 4.8
 4.2
Flow through depreciation and cost basis differences1.5
 0.2
 —
Other(2.1) (1.2) 0.5
Effective tax rate31.5 % 20.6 % 20.7 %
      
 Years Ended December 31,
  202020192018
Federal statutory tax rate21.0 %21.0 %21.0 %
Federal tax credits(1)
(20.5)(13.4)(16.7)
State and local taxes, net of federal tax benefit(2)
10.1 6.5 6.5 
Flow through depreciation and cost basis differences(4.9)1.5 1.5 
Amortization of excess deferred income tax(3)
(4.7)(3.7)(4.1)
Other(1.0)(0.7)(0.8)
Effective tax rate0 %11.2 %7.4 %
(1)
Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in service dates. PGE’s PTC generation endsat various dates between 2017 and 2024.
(1)    Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation ended or will endat various dates between 2017 and 2030.
(2) IncludesIn 2019, Oregon enacted HB 3427, which imposed a $17new gross receipts tax on companies with annual revenues in excess of $1 million increaseand applies to Income tax expense relatedyears beginning on or after January 1, 2020. The legislation defines that the tax applies to the remeasurementcommercial activities sourced in Oregon, less certain deductions. The resulting amount is taxed at 0.57%.
(3) The majority of excess deferred income taxes as a resultrelated to remeasurement under the TCJA is subject to IRS normalization rules and will be amortized over the remaining regulatory life of the enacted taxassets using the average rate change under the TCJA.assumption method.


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Deferred income tax assets and liabilities consist of the following (in millions):
 As of December 31,  
  20202019
Deferred income tax assets:
Employee benefits$136 $119 
Price risk management29 26 
Regulatory liabilities23 22 
Tax credits77 64 
Total deferred income tax assets265 231 
Deferred income tax liabilities:
Depreciation and amortization504 496 
Regulatory assets128 103 
Other7 10 
Total deferred income tax liabilities639 609 
Deferred income tax liability, net$374 $378 
 As of December 31,  
  2017 2016
Deferred income tax assets:   
Employee benefits$128
 $181
Price risk management56
 59
Regulatory liabilities14
 29
Tax credits50
 56
Other4
 5
Total deferred income tax assets252
 330
Deferred income tax liabilities:   
Depreciation and amortization496
 829
Regulatory assets132
 170
Other—
 —
Total deferred income tax liabilities628
 999
Deferred income tax liability, net$(376) $(669)


As of December 31, 2017,2020, PGE has federal credit carryforwards of $50$77 million, consisting of PTCs, which will expire at various dates through 2037. PGE has analyzed the provisions of the TCJA and its effects on the Company’s deferred income tax assets, and2040. PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 20172020 and 20162019 will be realized; accordingly, no0 valuation allowance has been recorded. As of December 31, 20172020, and 2016,2019, PGE had no0 material unrecognized tax benefits.


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


NOTE 12:13: EQUITY-BASED PLANS


Employee Stock Purchase Plan


PGE has an employee stock purchase plan (ESPP) under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000$25,000 in common stock or 1,500 shares (based on fair value on the purchase date) or 1,500 shares,, whichever is less. Two six-month offering periods occur annually, January 1 through June 30 and July 1 through December 31, during which eligible employees may contribute toward the purchase of shares of PGE common stock. Purchases occur the last day of the offering period, at a price equal to 95% of the fair value of the stock on the purchase date. As of December 31, 2017,2020, there were 339,542241,281 shares available for future issuance pursuant to the ESPP.


Dividend Reinvestment and Direct Stock Purchase Plan
PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2017,2020, there were 2,470,0522,462,263 shares available for future issuance pursuant to the DRIP.




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Equity Forward Sale Agreement

PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 11,100,000 shares of its common stock in June 2013. In 2013, the Company issued 700,000 shares of its common stock pursuant to the EFSA for net proceeds of $20 million. During the second quarter 2015, PGE physically settled in full the EFSA by issuing 10,400,000 shares of common PGE common stock in exchange for cash of $271 million.

Prior to settlement, the potentially issuable shares pursuant to the EFSA were reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period were increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could have been purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

NOTE 13:14: STOCK-BASED COMPENSATION EXPENSE


Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan as amended and restated effective February 13, 2018 (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs), to non-employee directors, officers, or certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table:
 UnitsWeighted Average
Grant Date
Fair Value
Nonvested units as of December 31, 2017399,376 $37.98 
Granted198,864 37.99 
Forfeited(8,556)39.73 
Vested(160,771)36.77 
Nonvested units of December 31, 2018428,913 38.43 
Granted210,555 49.06 
Forfeited(9,041)41.68 
Vested(167,037)37.52 
Nonvested units as of December 31, 2019463,390 43.52 
Granted202,883 56.45 
Forfeited(17,341)50.27 
Vested(170,536)45.67 
Nonvested units as of December 31, 2020478,396 48.00 
 Units 
Weighted Average
Grant Date
Fair Value
Outstanding as of December 31, 2014463,893
 $28.96
Granted181,797
 34.77
Forfeited(14,988) 34.10
Vested(187,709) 25.82
Outstanding as of December 31, 2015442,993
 32.84
Granted193,734
 35.89
Forfeited(3,044) 28.62
Vested(174,891) 31.47
Outstanding as of December 31, 2016458,792
 34.68
Granted202,145
 41.96
Forfeited(64,840) 39.57
Vested(196,721) 31.78
Outstanding as of December 31, 2017399,376
 37.98


A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 3,229,4762,737,180 shares remain available for future issuance as of December 31, 2017.2020.


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


Time-based RSUs generally vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period followingup to three years from the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was less than $1 million for the years ended December 31, 2017, 2016,2020, 2019 and 2015.2018.


Performance-based RSUs vest ifbased on the extent to which performance goals are met at the end of a three-year performance period. Grants areperiod, subject to adjustment by the Compensation and Human Resources Committee of PGE’s Board of Directors. The number of RSUs that may vest under grants awarded in 2018 is based on threetwo equally-weighted metrics: i) actual return on equity relative to allowed return on equity; ii) regulated asset base growth (applicable only for those grants made prior to 2017); and iii)ii) a relative total shareholder return (TSR) of PGE’s common stock as compared to an index of peer companies during the performance period. VestingBased on the attainment of performance-based RSUs is calculated by multiplyingthe goals, the number of units granted byRSUs that vest can range from zero to 175% of the RSUs granted. The number of RSUs that may vest under grants awarded in 2019 and 2020 is based on three equally-weighted metrics: i) actual return on equity relative to allowed return on equity; ii) average EPS growth; and iii) power supply portfolio decarbonization—and relative TSR as a performance percentage determined bymodifier to the Compensation and Human Resources Committeetotal of PGE’s Boardthe three equally-weighted metrics. Based on the attainment of Directors (Committee). Thethe goals, the number of RSUs that vest can range from 0 to 175% of the RSUs granted.


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performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the Committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

For the return on equity, average EPS growth and regulated asset base growth portionscarbon reduction metrics of the performance-based RSUs, fair value is measured based on the NYSE closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model andwith the following weighted average assumptions:
202020192018
Risk-free interest rate1.4 %2.5 %2.4 %
Expected term (in years)2.93.03.0
Volatility13.5 %-97.3 %14.8 %-74.5 %14.7 %-21.8 %
 2017 2016
Risk-free interest rate  1.5%   0.9%
Expected dividend yield  —%   —%
Expected term (in years)  3.0
   3.0
Volatility15.6%-22.9% 14.5%-25.9%


There is no expected dividend yield used in the valuation, as it is assumed that all dividends distributed during the performance period are reinvested in the Company’s underlying stock. The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 107.0%157.3%, 120.8%129.0%, and 118.2%69.0% of awarded performance-based RSUs for the respective 2017, 2016,2020, 2019, and 20152018 grants, with an estimated 5% forfeiture rate.


The total value of performance-based RSUs vested was $6$9 million for the year ended December 31, 2017, $52020, $7 million for 2016,2019, and $4 million for 2015.2018.


Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $7$11 million for the year ended December 31, 2017, and $62020, $9 million for 2016,2019, and 2015.$5 million in 2018. Such amounts differ from those reported in the consolidated statements of shareholders’ equity for Stock-basedstock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. Not included in Administrative and other expenses in the consolidated statements of income, is the net impact from these income tax payments, partially offset by the issuance of DERs, resulting in a charge to shareholders’ equity of$3 million in 2017, and $2 million in 20162020, 2019, and 2015.2018.


As of December 31, 2017,2020, unrecognized stock-based compensation expense was $7$13 million,, of which approximately $5 million and $2 million is expected to be expensed in 2018 and 2019, respectively. Norecognized over a weighted average period of one to three years. NaN stock-based compensation costs have been capitalized and the Plan had no material impact on cash flows for the years ended December 31, 2017, 2016, or 2015.capitalized.


NOTE 14:15: EARNINGS PER SHARE


Basic earnings per share are computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights;DERs. Unvested performance-based restricted stock units and iii)associated DERs are included in dilutive potential common shares issuable pursuant toonly after the EFSA. Duringperformance criteria have been met. Anti-dilutive stock awards are excluded from the second quartercalculation of 2015, PGE physically settled in full the EFSA, with the issuance of 10,400,000 shares of common stock. Prior to settlement, the potentially issuable shares pursuant to the EFSA were reflected in PGE’s diluted earnings per share calculations using the treasury stock method. See Note 12, Equity-based Plans, for additional information on the EFSA and its impact on earnings percommon share.


Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computation.computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):
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Years Ended December 31,
202020192018
Years Ended December 31,
2017 2016 2015
Weighted average common shares outstanding—basic89,056
 88,896
 84,180
Weighted average common shares outstanding—basic89,485 89,353 89,215 
Dilutive effect of potential common shares120
 158
 161
Dilutive potential common sharesDilutive potential common shares160 206 132 
Weighted average common shares outstanding—diluted89,176
 89,054
 84,341
Weighted average common shares outstanding—diluted89,645 89,559 89,347 


NOTE 15:16: COMMITMENTS AND GUARANTEES


Purchase Commitments


As of December 31, 2017,2020, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):
 Payments Due
 20212022202320242025ThereafterTotal
Capital and other purchase commitments$237 $33 $20 $1 $1 $55 $347 
Purchased power and fuel:
Electricity purchases250 257 284 278 249 2,886 4,204 
Capacity contracts9 9 9 9 9 0 45 
Public utility districts21 19 18 17 17 39 131 
Natural gas57 42 37 43 43 578 800 
Coal and transportation27 27 27 27 27 0 135 
Total$601 $387 $395 $375 $346 $3,558 $5,662 
 Payments Due
 2018 2019 2020 2021 2022 Thereafter Total
Capital and other purchase commitments$191
 $2
 $10
 $2
 $2
 $58
 $265
Purchased power and fuel:             
Electricity purchases156
 156
 201
 200
 187
 1,733
 2,633
Capacity contracts6
 5
 4
 4
 4
 8
 31
Public utility districts9
 17
 16
 16
 15
 85
 158
Natural gas51
 35
 28
 25
 24
 140
 303
Coal and transportation15
 5
 —
 —
 —
 —
 20
Total$428
 $220
 $259
 $247
 $232
 $2,024
 $3,410


Capital and other purchase commitments—Certain commitments have been made for 20182021 and beyond that include those related to hydro licenses, upgrades to generation, distribution, and transmission facilities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges.


Electricity purchases and Capacity contracts—PGE has power purchase agreements with counterparties, which expire at varying dates through 2044,2052, and power capacity contracts through 2024.2028.


Public utility districts—PGE has long-term power purchase agreements with certain public utility districts including, (PUDs) in the state of Washington:
•Grant County PUD for the Priest Rapids and Wanapum projects,Hydroelectric Projects, and
•Douglas County PUD for the Wells Hydroelectric Project.


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project, in the state of Washington. Under the Grant County agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. In addition, although PGE’s current agreement withoperable or not. Under the Douglas County ends on August 31, 2018, a new contract becomes effective on September 1, 2018 that does not require contributionsagreement, the Company is required to Douglas County debt obligation or other costs, including the operation and maintenance costs of the projects. The new contract requiresmake monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas County’s loads, and included the estimated amounts in the table above. The future minimum payments for the public utility districtsPUDs in the preceding table reflect the principal and capacity payments only and do not include interest, operation, or maintenance expenses.



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Selected information regarding these projects is summarized as follows (dollars in millions):
 
 Capacity Charges and Revenue Bonds as of December 31, 2020PGE’s Average Share as of December 31, 2020Contract
Expiration		Total PGE Contract Costs
OutputCapacity202020192018
   (in MW)    
Priest Rapids and Wanapum$1,880 8.6 %163 2052$25 $21 $17 
Wells572 16.6 94 202823 16 11 
 Revenue Bonds as of December 31, 2017 PGE’s Share as of December 31, 2017 
Contract
Expiration
 
PGE Cost,
including Debt Service
 Output Capacity  2017 2016 2015
     (in MW)        
Priest Rapids and Wanapum$1,269
 8.6% 163
 2052 $16
 $16
 $18
Wells160
 19.4
 150
 2018 11
 10
 10
Portland Hydro—
 —
 —
 2017 1
 1
 2
              

The agreements for Priest Rapids, Wanapum, and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro ratapro-rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage through August 2018, after which PGE would be responsible for a pro-rata portion of the defaulting purchaser’s share with no limitation, regardless of the reason for any default. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempttax-exempt status of any of the public utility district’s outstanding debt for the portion of the project that benefits tax exempttax-exempt purchasers.


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


Coal and transportation—PGE hashad coal and related rail transportation agreements with take-or-pay provisions related to the Boardman coal-fired generation plant (Boardman) that expireexpired in December 2020 in conjunction with the cessation of coal fired generation at various dates through 2020.


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Lease Obligations

As of December 31, 2017, PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions):

 Future Minimum Lease Payments
 Capital Leases Build-to-Suit Operating Leases
2018$7
 $—
 $9
20196
 15
 8
20206
 15
 6
20216
 14
 6
20225
 14
 8
Thereafter72
 260
 165
Total minimum lease payments$102
 $318
 $202
Less imputed interest51
    
Present value of net minimum lease payments$51
    
Less current portion2
    
Non-current portion$49
    

Capital Leases—PGE has entered into agreements to purchase natural gas transportation capacity to serve Carty via a 24-mile natural gas pipeline, Carty Lateral, that was constructed to serve the Carty facility.Boardman. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000 decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24-months prior written notice.

As of December 31, 2017, a capital lease asset of $57 million was reflected within Electric utility plant and accumulated amortization of such assets of $6 million was reflected within Accumulated depreciation and amortization in the table above. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $49 million in Other noncurrent liabilities on the consolidated balance sheets. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Also for ratemaking purposes, such rental payments were capitalized to the Carty project prior to its in service date of July 29, 2016 and, as a result, amortization of the leased asset of $2 million and interest expense of $3 million was capitalized to CWIP. Beginning August 1, 2016, amortization of the leased asset of $1 million and interest expense of $2 million has been recorded to Purchased power and fuel expense in the consolidated statements of income through December 31, 2016. For the year ended December 31, 2017, amortization of the leased asset of $3 million and interest expense of $4 million has been recorded to Purchased power and fuel expense in the consolidated statements of income.

Build-to-suit—PGE has entered into a 30-year leasecoal agreement with a local natural gas company, NW Natural,take-or-pay provisions related to expand their current natural gas storage facilities, including the development of an underground storage reservoirColstrip Units 3 and construction of a new compressor station and 13-mile pipeline, which will be designed to provide no-notice storage and transportation services to PGE’s PW1, PW2, and Beaver natural gas-fired 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 the gas company estimates 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 CWIP and a corresponding liability for the same amount to Other noncurrent liabilities in the consolidated balance sheets as of December 31, 2017. In 2016, PGE recorded $21 million to CWIP and a corresponding liability for the same amount to Other noncurrent liabilities in the consolidated balance sheets as of

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December 31, 2016. 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. The table above reflects PGE’s estimated future minimum lease payments pursuant to the agreement based on estimated costs and assumes three 10-year renewable options are exercised.

Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities4 coal-fired generation plant (Colstrip) that expire in various years, including the Port of St. Helens land lease, which expires in 2096 and covers the location of PW1, PW2, and Beaver. Rent expense was $9 million in 2017, and $10 million in 2016 and 2015.December 2025.

The future minimum operating lease payments presented is net of sublease income of $4 million in each of 2018, 2019, 2020, and 2021; and$2 million in 2022. Sublease income was $4 million in 2017 and 2016, and $3 million in 2015.


Guarantees


PGE enters into financial agreements, and purchase and sale agreements involving physical delivery of, both power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 2017,2020, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.


NOTE 17: LEASES

PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the
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Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability.

Operating leases reflect lease expense on a straight-line basis, while finance leases result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

PGE does not record leases with a term of 12-months or less in the consolidated balance sheets. Total short-term lease costs as of December 31, 2020 are immaterial. PGE has lease agreements with lease and non-lease components, which are accounted for separately.

The Company’s leases relate primarily to the use of land, support facilities, gas storage, and power purchase agreements that rely on identified plant. Variable payments are generally related to gas storage and power purchase agreements for components dependent upon variable factors, such as energy production and property taxes, and are not included in the determination of the present value of lease payments.

The components of lease cost were as follows (in millions):
20202019
Operating lease cost$8 $7 
Finance lease cost:
Amortization of right-of-use assets$5 $3 
Interest on lease liabilities10 6 
Total finance lease cost$15 $9 
Variable lease cost$12 $19 
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Supplemental information related to amounts and presentation of leases in the consolidated balance sheets is presented below (in millions):
Balance Sheet ClassificationDecember 31, 2020December 31, 2019
Operating Leases:
Operating lease right-of-use assetsOther noncurrent assets$44 $51 
Current liabilitiesAccrued expenses and other current liabilities$8 $8 
Noncurrent liabilitiesOther noncurrent liabilities36 43 
Total operating lease liabilities*$44 $51 
Finance Leases:
Finance lease right-of-use assetsElectric utility plant, net$145 $150 
Current liabilitiesCurrent portion of finance lease obligations$16 $16 
Noncurrent liabilitiesFinance lease obligations, net of current portion129 135 
Total finance lease liabilities$145 $151 
*Included in lease liabilities are $25 million and $32 million related to power purchase agreements for the years ended December 31, 2020 and 2019, respectively.

Lease term and discount rates were as follows:
December 31, 2020December 31, 2019
Weighted Average Remaining Lease Term (in years)
Operating leases2624
Finance leases2829
Weighted Average Discount Rate
Operating leases3.6 %3.5 %
Finance leases7.3 %7.3 %
PGE’s gas storage finance lease contains five 10-year renewal periods which have not been included in the finance lease obligation.


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As of December 31, 2020, maturities of lease liabilities were as follows (in millions):
Operating LeasesFinance Leases
2021$8 $16 
20228 16 
20238 14 
20247 14 
20251 13 
Thereafter45 222 
Total lease payments77 295 
Less imputed interest(33)(150)
Total$44 $145 

Supplemental cash flow information related to leases was as follows (in millions):
December 31, 2020December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$8 $7 
Operating cash flows from finance leases10 5 
Financing cash flows from finance leases6 4 
Right-of-use assets obtained in leasing arrangements:
Operating leases$0 $56 
Finance leases0 154 

As of December 31, 2020, PGE has an additional operating lease for an energy storage agreement that has not yet commenced with an estimated present value of future lease payments of $30 million. This lease is expected to commence in 2022 with a lease term of 20 years.

NOTE 16:18: JOINTLY-OWNED PLANT


As of December 31, 2017,2020, PGE had the following investments in jointly-owned plant (dollars in millions):
 
PGE
Share
 In-service Date 
Plant
In-service
 
Accumulated
Depreciation*
 
Construction
Work In
Progress
Boardman90.00% 1980 $515
 $426
 $—
Colstrip20.00
 1986 546
 351
 5
Pelton/Round Butte66.67
 1958/1964 251
 68
 7
Total      $1,312
 $845
 $12
 PGE
Share		In-service DatePlant
In-service		Accumulated
Depreciation*		Construction
Work In
Progress
Colstrip20.00 %1986$566 $387 $7 
Pelton/Round Butte66.67 %1958/1964283 82 7 
Total$849 $469 $14 
*Excludes AROs and accumulated asset retirement removal costs.

*    Excludes AROs and accumulated asset retirement removal costs.

Under the respective joint operating agreements for the three generating facilities, each participating owner is responsible for financing its share of construction,capital and operating and leasing costs.expenses. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.


The Company operated, and continues to have a 90% ownership interest in, Boardman, which ceased coal-fired operations during the fourth quarter of 2020. The Company has begun the initial steps toward decommissioning the
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facility. As of December 31, 2020, PGE’s ARO liability for its 90% share of the decommissioning costs was $44 million.

NOTE 17:19: CONTINGENCIES


PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.


A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the CompanyCompany: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate,estimate; or ii) discloses that an estimate cannot be made and the reasons.


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


The CompanyPGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts are in dispute; vi) there are a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, willwould be shared among multiple defendants); or vii) there is a wide range of potential outcomes.outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Carty

In 2013, PGE entered into a turnkey engineering, procurement, and construction agreement (Construction Agreement) with Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership (collectively, the “Contractor”), affiliates of Abengoa S.A. - for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (together, the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) in connection with the Construction Agreement.

In December 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE brought on new contractors and construction resumed.

Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved capital cost of $514 million. Actual costs for the construction of Carty exceeded the approved amount and, as of December 31, 2017, PGE has capitalized $637 million to Electric utility plant.

As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. These incremental expenses are recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP.

As actual project costs for Carty have exceeded $514 million, the Company has incurred a higher cost of service than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation,

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interest expense and legal expenses. Such incremental expenses were $14 million and $3 million for the year ended December 31, 2017 and 2016, respectively. Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval.

Actual costs do not reflect any offsetting amounts that may be received from the Sureties, pursuant to the Performance Bond. The amounts recorded also exclude $8 million of liens and claims filed for goods and services provided under contracts with the former Contractor that remain in dispute. The Company believes these liens and claims are invalid and is contesting the liens and claims in the courts.

The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, completing the remaining construction work, correcting deficiencies and defects in work performed by the former Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials.

Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage that resulted from poor storage and maintenance on the part of the former Contractor.

In July 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 regulatory proceeding. The Company has requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved.

Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC. The Company believes that costs incurred to date and capitalized in Electric utility plant, net, in the condensed consolidated balance sheet, were prudently incurred. There have been no settlement discussions with regulators related to such costs.

The Company is involved in several litigation proceedings concerning the termination of the Construction Agreement and the payment obligations of the Sureties.

PGE is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the Contractor and claims against the Sureties pursuant to the Performance Bond. The Sureties have denied liability in whole under the Performance Bond.

Various actions relating to this matter have been filed in the U.S. District Court for the District of Oregon (U.S. District Court), in the Ninth Circuit Court of Appeals (Ninth Circuit), and in an arbitration proceeding, including the following:

A breach of contract claim dated March 23, 2016, Portland General Electric Company v. Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon, brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.


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A claim dated October 21, 2016, Portland General Electric Company v. Abeinsa EPC LLC, Abener Construction Services, LLC (formerly known as Abener Engineering and Construction Services, LLC), Teyma Construction USA LLC, and Abeinsa Abener Teyma General Partnership, U.S. District Court of the District of Oregon, brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from the Contractor in excess of $200 million for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors, and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest.

A claim dated December 31, 2015, In the Matter of an Arbitration Under the Rules of the International Chamber of Commerce’s Court of Arbitration, International Chamber of Commerce’s Court of Arbitration, by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the terms of the agreement and did not give rise to any liability of Abengoa S.A.; and

A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement and $44 million based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals.

Following various procedural arguments in the ICC arbitration and the U.S. District Court, in July 2017, the Ninth Circuit held that the ICC arbitral tribunal had jurisdiction to determine what parties and what claims could be presented in the ICC arbitration as opposed to in court. A hearing before the ICC arbitral tribunal is expected to take place on April 9 and 10, 2018. The decision of the ICC arbitral tribunal is expected to determine the forum in which the above referenced claims will be heard.

After exhausting all remedies against the aforementioned parties, the Company intends to seek approval to recover any remaining excess amounts in customer prices in a subsequent regulatory proceeding. However, there is no assurance that such recovery would be allowed by the OPUC.

In accordance with GAAP and the Company’s accounting policies, any such excess costs may be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood is less than probable that a portion of the cost of Carty will be disallowed for recovery in customer prices. Accordingly, no loss has been recorded to date related to the project.

EPA Investigation of Portland Harbor


An investigation by the United States Environmental Protection Agency (EPA) that began in 1997 of a segment of the Willamette River known as Portland Harbor hasthat began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs).site. PGE was included among the PRPsPotentially Responsible Parties (PRPs) as it has historically owned or operated property near the river.

In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation, as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.100.


The Portland Harbor site remedial investigation had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the
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remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

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The EPA has finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6,in 2017. The ROD outlinesoutlined the EPA’s selected remediation plan tofor clean-up forof the Portland Harbor site, which has an undiscounted estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion.costs. Remediation construction costs arewere estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. Stakeholders have raised concerns that EPA’s cost estimates are understated. The EPA acknowledgesacknowledged the estimated costs are based on data that is nowwas outdated and that a period of pre-remedial design sampling iswas necessary to gather updated baseline data to better refine the remedial design and estimated cost. In December 2017,

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA announcedfor review. The evaluation report concluded that fourthe conditions of the Portland Harbor Superfund site have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has indicated it will take the initial lead to perform remedial design on the remaining areas. The EPA announced on February 12, 2021 that 100% of Portland Harbor is under an administrative order on consent to conduct this additional sampling, which is estimated to be completed in two years. PGE is not among the four PRPs performing this sampling.active engineering design phase.


PGE is participatingcontinues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including results of the pre-remedialremedial design, sampling, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. BasedHowever, based on the above facts and remaining uncertainties, PGE cannotdoes not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.Harbor, although such costs could be material to PGE’s financial position.


WhereIn cases in which injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process.(NRD). The EPA does not manage NRDANRD assessment activities but providesdoes provide claims information and coordination support to the Natural Resource Damages (NRD)NRD trustees. DamageNRD assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site. The Portland Harbor NRD trustees areconsist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the Statestate of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS), and certain tribal entities.the Nez Perce Tribe.


The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. The Company believes that PGE’s portion of NRDANRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, the amount of natural resource damages, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

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.


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The impact of such costs to the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC in 2017, the PHERA allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. Under the PHERA mechanism in 2020, PGE incurred and deferred $6 million related to defense costs, net of an immaterial estimated refund as a result of PGE overearning in the regulated earnings test for this deferral. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from the EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices.


Trojan Investment Recovery Class Actions


In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.


Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.


In 2003, in two separate legal proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court;Court (Circuit Court); and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seeksought damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.


In August 2006, the Oregon Supreme Court (OSC) issued a ruling ordering the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.


In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds, of $33 million, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the OSC in October 2014.


In June 2015, based on a motion filed by PGE, the Marion County Circuit Court (Circuit Court) lifted the abatement and in July 2015,on the Circuit Courtclass action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. On April 14, 2016, theThe plaintiffs subsequently appealed the Circuit Court dismissal to the Court of Appeals for the Statestate of Oregon. Briefing on

In November 2019, the appeal is now complete, with a Court of Appeals decision pending.

PGE believesissued an opinion that affirmed the October 2, 2014 OSC decision and the recent Circuit Court decisions have reduceddismissal. On December 30, 2019, the riskplaintiffs filed a motion for reconsideration, which the Court of Appeals denied on February 4, 2020.

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On April 7, 2020, the Plaintiffs filed a loss topetition with the Company in excessOSC requesting review and reversal of the amounts previously recorded and discussed above. However, becauseCourt of Appeals opinion. On July 16, 2020, the class actions remain subject to a decision inOSC issued an order that denied the appeal, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.petition for review.


Deschutes River Alliance Clean Water Act Claims


OnIn August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company Deschutes(Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon, whichseeksOregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimsclaimed PGE hashad violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA allegesalleged the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.


The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of

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the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters.


In September 2016,March and April 2018, DRA and PGE filed a motion to dismiss,cross-motions for summary judgment and PGE and CTWS, which asserted thatco-own the CWA does not allow citizen suits of this nature, and that the FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motionProject, filed separate motions to dismiss. On April 6, 2017, PGE filed a motion with the District Court for certification to file an interlocutory appeal with the Ninth Circuit and for a stay of the District Court proceeding. The District Court granted PGE’s request on May 19, 2017, but the Ninth Circuit denied the appeal on August 14, 2017. On April 7, 2017, the District Court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the caseCTWS initially appeared as a friend of the court. The Tribes share ownership ofcourt, but subsequently was found to be a necessary party to the Project with PGE, but have not been namedlawsuit and joined as a defendant.


Following conferences and negotiations involving various parties, and withIn August 2018, the expirationU.S. District Court of the stay, the District Court Judge, on January 17, 2018, established a briefing scheduleof Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, motions.ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.


In October 2018, DRA filed an appeal, and PGE and CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. The appeals are fully briefed and the parties await a schedule for oral argument.

The Company cannot predict the outcome of this matter but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time,or determine the likelihood of whether the outcome of this matter will result in a material loss.

Shareholder Lawsuits

During September and October, 2020, three putative class action complaints were filed in U.S. District Court for the District of Oregon against PGE and certain of its officers, captioned Hessel v. Portland General Electric Co., No. 20-cv-01523 (“Hessel”), Cannataro v. Portland General Electric Co., No. 3:20-cv-01583 (“Cannataro”), and Public Employees’ Retirement System of Mississippi v. Portland General Electric Co., No. 20-cv-01786 (“PERS of Mississippi”). Two of these actions were filed on behalf of purported purchasers of PGE stock between April 24, 2020, and August 24, 2020; a third action was filed on behalf of purported purchasers of PGE stock between February 13, 2020, and August 24, 2020.

During the fourth quarter of 2020, the plaintiff in Hessel voluntarily dismissed his case and the court consolidated Cannataro and PERS of Mississippi into a singlecase captioned In re Portland General Electric Company Securities Litigation and appointed Public Employees’ Retirement System of Mississippi lead plaintiff (“Lead Plaintiff”). On January 11, 2021,Lead Plaintiff filed an amended complaint asserting causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 for alleged misstatements and omissions regarding,
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among other things, PGE’s alleged lack of sufficient internal controls and risks associated with PGE's trading activity in wholesale electric markets, purportedly on behalf of purchasers of PGE stock between February 13, 2020, and August 24, 2020. The complaint demands a jury trial and seeks compensatory damages of an unspecified amount and reimbursement of plaintiffs' costs, and attorneys' and expert fees.

The Company intends to vigorously defend against the lawsuit.Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

Putative Shareholder Derivative Lawsuit

On January 26, 2021, a putative shareholder derivative lawsuit, was filed in Multnomah County Circuit Court, Oregon, captioned Shimberg v. Pope, No. 21- cv-02957, against one current and one former PGE executive and several members of the Company's Board of Directors (collectively, the "Individual Defendants") and naming the Company as a nominal defendant only. The plaintiff asserts a claim for alleged breaches of fiduciary duties purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the Individual Defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company of not less than $10 million, equitable relief to remedy the alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs.

Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

Other Matters


PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.




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QUARTERLY FINANCIAL DATA
(Unaudited)
 Quarter Ended
  March 31 June 30 September 30 December 31
 (In millions, except per share amounts)
2017       
Revenues, net$530
 $449
 $515
 $515
Income from operations123
 68
 77
 108
Net income73
 32
 40
 42
Earnings per share:*
       
Basic0.82
 0.36
 0.44
 0.48
Diluted0.82
 0.36
 0.44
 0.48
2016       
Revenues, net$487
 $428
 $484
 $524
Income from operations99
 64
 64
 106
Net income61
 37
 34
 61
Earnings per share:*
       
Basic0.68
 0.42
 0.38
 0.68
Diluted0.68
 0.42
 0.38
 0.68
* Earnings per share are calculated independently for each period presented. Accordingly, the sum of the quarterly earnings per share amounts may not equal the total for the year.


ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.


ITEM 9A.     CONTROLS AND PROCEDURES.


(a)     Disclosure Controls and Procedures


Management of the Company, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are effective.


(b)     Management’s Annual Report on Internal Control over Financial Reporting


The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.


Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of the end of the period covered by this report pursuant to Rule 13a-15(c) under the Exchange Act. Management’s assessment was based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management has concluded that, as of December 31, 2017,2020, the Company’s internal control over financial reporting is effective.


The Company’s internal control over financial reporting, as of December 31, 2017,2020, has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audits the Company’s consolidated financial statements, as stated in their report included in Item 8.—“Financial Statements and Supplementary Data,” which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2017.2020.


(c)     Changes in Internal Control over Financial Reporting


There have not been any changes in the Company’sCompany's internal control over financial reporting during the fourth quarter of 20172020 that have materially affected, or are reasonably likely to materially affect, the Company’sCompany's internal control over financial reporting.


ITEM 9B.     OTHER INFORMATION.


None.


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PART III
 
ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.


TheCertain information required by Item 10 is incorporated herein by reference to the relevant information under the captions “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance,” “ProposalGovernance” and “Item 1: Election of Directors,” and “Executive Officers”Directors” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SECUnited States Securities and Exchange Commission (SEC) in connection with the Annual Meeting of Shareholders scheduled to be held on April 25, 2018.28, 2021. Information regarding executive officers of Portland General Electric Company may be found in Part I, Item 1. Business of this Annual Report on Form 10-K.


ITEM 11.     EXECUTIVE COMPENSATION.


The information required by Item 11 is incorporated herein by reference to the relevant information under the captions “Corporate Governance—Non-Employee Director Compensation,” “Corporate Governance—Compensation Committee Interlocks, and Insider Participation,” “Compensation and Human Resources Committee Report,” “Compensation Discussion and Analysis,” and “Executive Compensation Tables” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on April 25, 2018.28, 2021.


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


The information required by Item 12 is incorporated herein by reference to the relevant information under the captions “Security Ownership of Certain Beneficial Owners, Directors and Executive Officers” and “Equity Compensation Plans,Officers,” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on April 25, 2018.28, 2021.



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


The information required by Item 13 is incorporated herein by reference to the relevant information under the caption “Corporate Governance” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on April 25, 2018.28, 2021.


ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES.


The information required by Item 14 is incorporated herein by reference to the relevant information under the captions “Principal Accountant Fees and Services” and “Pre-Approval Policy for Independent Auditor Services” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on April 25, 2018.28, 2021.



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PART IV
 
ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES.


(a)    Financial Statements and Schedules


The financial statements are set forth under Item 8 of this Annual Report on Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.


(b)    Exhibit Listing


Exhibit
Number
Description
(3)Articles of Incorporation and Bylaws
3.1*
3.2*
(4)Instruments defining the rights of security holders, including indentures
4.1*Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945 (Form 8, Amendment No. 1 dated June 14, 1965) (File No. 001-05532-99).
4.2*Fortieth Supplemental Indenture dated October 1, 1990 (Form 10-K for the year ended December 31, 1990, Exhibit 4) (File No. 001-05532-99).
4.3*
4.4*
(10)4.5*Material Contracts
10.1*4.6*
(10)Material Contracts
10.1*
10.210.2*
10.310.3*
10.4*
10.4*10.5*
10.5*10.6*
10.6*10.7*
10.7*10.8*
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10.8*
Exhibit
Number
Description
10.9*
10.9*
Portland General Electric Company Senior Officers’ Life Insurance Benefit Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.3) (File No. 001-05532-99). +
10.10*

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Exhibit
Number
Description
10.11*
10.12*
10.13*
Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan (Form 8-K filed May 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.14*10.13*
10.15*
Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters (Form 8-K filed December 24, 2009, Exhibit 10.1) (File No. 001-05532-99). +
10.16*10.14*
10.17*10.15*
10.18*10.16*
(12)10.17*Statements Re Computation
12.110.18*
(23)10.19
10.20
10.21
10.22
(23)Consents of Experts and Counsel
23.1
(31)Rule 13a-14(a)/15d-14(a) Certifications
31.1
31.2
(32)Section 1350 Certifications
32.1
(101)Interactive Data File
101.INSXBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
101.LABXBRL Taxonomy Extension Label Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
104Cover page information from Portland General Electric Company’s Annual Report on Form 10-K filed February 14, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language).

*Incorporated by reference as indicated.
+Indicates a management contract or compensatory plan or arrangement.
*    Incorporated by reference as indicated.
+    Indicates a management contract or compensatory plan or arrangement.
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Certain instruments defining the rights of holders of other long-term debt of PGE are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. PGE hereby agrees to furnish a copy of any such instrument to the SEC upon request.


Upon written request to Investor Relations, Portland General Electric Company, 121 S.W. Salmon Street, Portland, Oregon 97204, the Company will furnish shareholders with a copy of any Exhibit upon payment of reasonable fees for reproduction costs incurred in furnishing requested Exhibits.



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ITEM 16.     FORM 10-K SUMMARY.
Table of Contents

None.


SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 15, 2018.18, 2021.
 
PORTLAND GENERAL ELECTRIC COMPANY
PORTLAND GENERAL ELECTRIC COMPANY
By:
By:/s/ MARIA M. POPE
Maria M. Pope
President and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 15, 2018.18, 2021.


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SignatureTitle
SignatureTitle
/s/ MARIA M. POPE
President, Chief Executive Officer, and Director
(principal executive officer)
Maria M. Pope
/s/ JAMES F. LOBDELLA. AJELLO
Senior Vice President of Finance, Chief Financial Officer, and Treasurer
(principal financial and accounting officer)
James F. LobdellA. Ajello
/s/ JOHN W. BALLANTINEDirector
John W. Ballantine
/s/ RODNEY L. BROWN, JR.Director
Rodney L. Brown, Jr.
/s/ JACK E. DAVISDirector
Jack E. Davis
/s/ DAVID A. DIETZLERDirector
David A. Dietzler
/s/ KIRBY A. DYESSDirector
Kirby A. Dyess
/s/ MARK B. GANZDirector
Mark B. Ganz
/s/ MARIE OH HUBERDirector
Marie Oh Huber
/s/ KATHRYN J. JACKSONDirector
Kathryn J. Jackson
/s/ MICHAEL A. LEWISDirector
Michael A. Lewis
/s/ MICHAEL H. MILLEGANDirector
Michael H. Millegan
/s/ NEIL J. NELSONDirector
Neil J. Nelson
/s/ M. LEE PELTONDirector
M. Lee Pelton
/s/ CHARLES W. SHIVERYDirector
Charles W. Shivery
/s/ JAMES P. TORGERSONDirector
James P. Torgerson

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