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

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

For the fiscal year ended December 31, 20162018

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
(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)(Name of exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None.

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




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

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

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

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

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

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

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

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

As of June 30, 20162018, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $3,905,668,556.$3,802,406,147. For purposes of this calculation, executive officers and directors are considered affiliates.

As of February 3, 2017,4, 2019, there were 88,946,93289,269,775 shares 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 26, 2017.24, 2019.


PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 20162018

TABLE OF CONTENTS

Definitions
 
4
    
 
PART I
  
    
Item 1.
Business.
 
5
Item 1A.
Risk Factors.
 
2523
Item 1B.
Unresolved Staff Comments.
 
3128
Item 2.
Properties.
 
3129
Item 3.
Legal Proceedings.
 
3330
Item 4.
Mine Safety Disclosures.
 
3630
    
 
PART II
  
    
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
 
3630
Item 6.
Selected Financial Data.
 
3730
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
3830
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
 
6358
Item 8.
Financial Statements and Supplementary Data.
 
6661
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
120117
Item 9A.
Controls and Procedures.
 
120117
Item 9B.
Other Information.
 
120118
    
 
PART III
  
    
Item 10.
Directors, Executive Officers and Corporate Governance.
 
121119
Item 11.
Executive Compensation.
 
121119
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
121119
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
 
121119
Item 14.
Principal Accounting Fees and Services.
 
121119
    
 
PART IV
  
    
Item 15.
Exhibits, Financial Statement Schedules.
 
122120
    
 
SIGNATURES
 
124122


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DEFINITIONS

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


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PART I
 
ITEM 1.     BUSINESS.

General

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

PGE’s state-approved service area allocation of approximately 4,000 square miles is located entirely within Oregon and includes 51 incorporated cities, of which Portland and Salem are the largest. The Company estimates that at the end of 20162018 its service area population was 1.9 million, comprising approximately 46% of the population of the State of Oregon. During 20162018, the Company added nearly 11,00010,000 customers, and as of December 31, 20162018, served a total of 863,000885,000 retail customers.

Employees

PGE had 2,7522,967 employees as of December 31, 20162018, with 783802 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover730747 and 5355 employees and expire March 2020 and August 2017,2022, respectively.

Available Information

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

Regulation

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

FERC and Other 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.


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

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

Wholesale Energy—PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales in all markets in which it sells electricity except in its own Balancing Authority Area (BAA). The BAA is the area in which PGE is responsible for balancing customer demand with electricity generation, in real time. Continued market-based rate authority requires specific actions by PGE including the filing of triennial market power studies with the FERC, the filing of notices of change in status, and compliance with FERC rules. On June 30, 2016, PGE submitted its updated triennial market power analysis, which was supplemented in September, October, and again in December 2016. The FERC has yet to issue an order on this filing.

On August 26, 2016, PGE submitted a Notification of Change in Status for the addition of the Carty natural gas-fired generating plant (Carty). The addition of Carty resulted in PGE having over a 20% market share in its BAA, creating a presumption of market power within its BAA. PGE proposed,time, and the FERC accepted, that PGE willrestriction on sales within PGE’s BAA does not make any future sales at market-based rates within its BAA. PGE can only make sales at cost based rates in its BAA. Historically, PGE has made very few sales of electric energy and ancillary services within its BAA. Given that and in light of current low market prices, PGE’s inability to sell electric energy and ancillary services within its BAA at market-based rates is not expected to have a material impact on the Company.

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.  For additional information, see the Transmission and Distribution section in this Item 1. and Item 2.—“Properties.”

Reliability and Cyber Security Standards—Pursuant to the Energy Policy Act of 2005, the FERC has adopted mandatory reliability standards for owners, users, and operators of the bulk power system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of these standards. These standards include Critical Infrastructure Protection (CIP) standards, a set of cyber security standards that provide a framework to identify and protect critical cyber assets used to support reliable operation of the bulk power system. A new version of the NERC CIP standards came into effect July 1, 2016 that will require compliance by various dates through September 1, 2018.

There are certain FERC regulatory activities that PGE expects to undertake as part of its entry into the California Independent System Operator’s (CAISO) Energy Imbalance Market (EIM) including filing with the FERC both an updated OATT and a Readiness Criteria certification. The FERC requires this informational filing from PGE and the CAISO to declare that PGE has satisfied the CAISO’s Readiness Criteria prior to PGE’s starting EIM operations, which is planned for October 1, 2017. For further information on the EIM, see “Future Energy Resource Strategy” in the Power Supply section of this Item 1.

Natural Gas Pipelines—The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide the FERC authority in matters related to the construction, operation, extension, enlargement, safety, and abandonment of jurisdictional interstate natural gas pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority as the Company has a 79.5% ownership interest in the Kelso-Beaver (KB) Pipeline, a 17-mile interstate pipeline that provides natural gas to the Company’s natural gas-fired generating plants located near Clatskanie, Oregon: Port Westward Unit 1 (PW1); Port Westward Unit 2 (PW2); and Beaver. As the operator of record of the KB Pipeline, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety standards, operator qualification standards, and public awareness requirements.


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Hydroelectric Licensing—Under the FPA, PGE’s hydroelectric generating plants are subject to FERC licensing requirements, which includerequirements. PGE holds FERC licenses for the Company’s projects on the Deschutes, Clackamas, and Willamette Rivers. The licenses specify certain operating procedures and require capital projects focused on fish protection and reintroduction. The FERC license process includes an extensive public review process that involves the consideration of numerous natural resource issues and environmental conditions. PGE holds FERC licenses for the Company’s projects on the Deschutes, Clackamas, and Willamette Rivers. For additional information, see the Environmental Matters section in this Item 1. and the Generating Facilities section in Item 2.—“Properties.”

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

Short-term Debt—Pursuant to applicable provisions of the FPA and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. The Company, pursuant to an order issued by the FERC on February 5, 2016, has authorization to issue up to $900 million of short-term debt through February 6, 2018.

Spent Fuel Storage—The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s Trojan nuclear power plant (Trojan), which was closed in 1993. The NRC approved the 2003 transfer of spent nuclear fuel from a spent fuel pool to a separately licensed dry cask storage facility that will house the fuel on the former plant site until a United States Department of Energy (USDOE) facility is available. Radiological

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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.”

OPUC and Other 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, which is comprised of three members appointed by the governor of Oregon to serve non-concurrent four-year terms, reviews and approves the Company’s retail prices (see “Economic Regulation” below) and establishes conditions of utility service. In addition, the OPUC reviews the Company’s generation and transmission resource acquisition plans, pursuant to a bi-annual integrated resource planning process. The OPUC regulates the issuance of securities, prescribes accounting policies and practices, regulates the sale of utility assets, reviews transactions with affiliated companies, and has jurisdiction over the acquisition of, or exertion of substantial influence over, public utilities. The OPUC also oversees the Retail Customer Choice Program and approves funding for Energy Efficiency, and establishes the public purpose charges that are remitted to the Energy Trust of Oregon (ETO).

Economic Regulation—Under Oregon law, the OPUC is required toto: i) ensure that prices and terms of service are fair non-discriminatory, and non-discriminatory; and ii) provide regulated companies an opportunity to earn a reasonable return on their investments. Customer prices are determined through formal proceedings that generally include testimony by participating parties, discovery, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, may include PGE, OPUC staff, and intervenors representing PGE customer groups.groups, as well as other interested parties. The following are the more significant regulatory mechanisms and proceedings under which customer prices are determined.determined:
General Rate Cases. PGE periodically evaluates the need to change its retail electric price structure to sufficiently cover its operating costs and provide a reasonable rate of return to investors. SuchPrice changes are requested pursuant to a comprehensive general rate case process that includesreflects revenue requirements based on a forecasted test year,year. Through this public review process, the OPUC authorizes the Company’s debt-to-equity capital structure, return on equity, and overall rate of return. PGE plans to file areturn, and customer prices. For additional information regarding the Company’s most recent general rate case forcases, see “General Rate Cases” in the 2018 test year (2018 GRC) with the OPUC by the endOverview section in Item 7.—“Management’s Discussion and Analysis of FebruaryFinancial Condition and Results of Operations.”

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2017. Following a ten month public review process, the Company expects new prices to become effective in January 2018.
Power Costs. In addition to price changes resulting from the general rate case process, the 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), which consist. NVPC consists of the cost of power purchased and fuel used to generate electricity, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel usedexpense in generation (including related transportation costs) lessthe Company’s consolidated statements of income) and is net of wholesale revenues, from wholesale power and fuel sales: 
◦Annual Power Cost Update Tariff (AUT). Under this tariff, customer prices are adjusted annually to reflect the latest forecast of NVPC. An initial NVPC forecast, submitted to the OPUC by April 1st each year, is updated during such year and finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, become effective at the beginning of the following calendar year; and
◦
Power Cost Adjustment Mechanism (PCAM). Under the PCAM, PGE shares a portion of the business risk or benefitwhich are classified as Revenues, net in the consolidated statements of income. 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. 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. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90% of the variance beyond the deadband to be collected from or refunded to customers, respectively, subject to a regulated earnings test. A final determination of any customer collection or refund is made by the OPUC through a public filing and review, typically during the second half of the following year. Any estimated collection from customers pursuant to the PCAM is recorded as a reduction in Purchased power and fuel expense in the Company’s consolidated statements of income, while any estimated refund to customers is recorded as a reduction in Revenues, net. 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.” During the past three years, the Company has recorded no refunds or collections as a result of the PCAM.
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, recently extended by the OPUC through 2019, 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 “Customers and Demand” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Renewable Energy. TheIn 2007, the State of Oregon Renewable Energy Act (the Act) established a Renewable Portfolio Standard (RPS), which requiredrequires that PGE initially serve at least 5%a portion of its retail load with renewable resources by 2011, with future requirements of 15% by 2015, 20% by 2020, and 25% by 2025. PGE met the 2011 and 2015 requirements and expects to meet requirements going forward.

resources. The Act alsoRPS allows renewable energy credits,certificates (RECs), resulting from energy generated from qualified renewable resources, placed in service after January 1, 1995, and generation from certified low impact hydroelectric power resources, to be used to meet the Company’s RPS compliance obligation.

The Act providesthose requirements. In addition, a renewable adjustment clause (RAC) mechanism was established that allows for the recovery in customer prices of prudently incurred costs required to comply with the RPS. Under a renewable adjustment clause (RAC) mechanism, PGE can recoverIn 2016, 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 1st of each year for new renewable resources expected to be placed in service in the current year, with prices expected to become effective January 1st of the following year. In addition, the RAC provides for the deferral and subsequent recovery of eligible costs incurred prior to January 1st of the following year.

The Company submitted a RAC filing to the OPUC in 2014 with the expectation that Tucannon River Wind Farm (Tucannon River) would be placed into service before the end of 2014. In 2015, PGE

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submitted a RAC filing to the OPUC related to a 1.2 MW solar facility with the expectation that it would be placed into service before the end of 2015. In March 2016, PGE submitted to the OPUC a RAC filing that requested no significant additions or deferrals for 2016.

The State of Oregon passed Senate Bill 1547, effective March 8, 2016, a law referred to as the Oregon Clean Electricity and Coal Transition Plan (OCEP). The legislation prevents large utilities from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for the Company’s output from the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip))(SB 1547), increaseswhich, among its provision, increased the RPS percentages in certain future years, changes the life of certain renewable energy certificates (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.years.

Under Senate Bill 1547, PGE will be required to:
◦meet RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
◦limit the life of RECs generated from facilities that become operational after 2022 to five years, but maintain the unlimited lifespan of all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022;
◦include projected production tax credits (PTCs) in prices through any variable power cost forecasting process established by the OPUC, the first of which applied to the AUT filing for 2017; and
◦include energy storage costs in its RAC filings.
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The Company has evaluated the potential impacts and has incorporated the effects of the legislation into its 2016 Integrated Resource Plan (IRP), which was filed with the OPUC in the fourth quarter of 2016. In December 2016, the OPUC approved a tariff request submitted by PGE seeking approval to incorporate in customer prices on January 1, 2017 the estimated annual $6 million effect of accelerating recovery of the Colstrip facility from 2042 to 2030, which was required under the legislation.

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.”

Integrated Resource Plan—Unless the OPUC grants an extension, PGE is required to file an 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 “Future Energy Resource Strategy” in the Power Supply section in this Item 1.

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 pricing options other than cost-of-service, including direct access and daily market index-basedrenewable resource pricing.

All commercial and industrial customers are eligible for direct access,pricing options other than cost of service 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). Under the program, the Company is paid for delivery of the energy to the ESS customers. Large commercial and industrial customers may elect to be served by PGE on a daily market index-based price.


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All non-residential retail customers have an option to be served by an ESS for a one-year period. Certain large commercial and industrial customers may elect to be removed from cost-of-service pricing for a fixed three-year or a minimum five-year term, to be served either by an ESS, or by the Company under 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 ofIn 2018, the energy supplied under PGE’s Retail Customer ChoiceOPUC created a New Large Load Direct Access program, is provided to customers that have elected servicecapped at approximately 120 MWa, for unplanned, large, new loads and large load growth at existing sites. Customers who choose Direct Access purchase energy from an ESS underand PGE receives revenue only for the minimum five-year opt-out program.transmission and delivery of the electricity.

ESSs have supplied direct access customers with energy representing 9% of the Company’s total retail energy deliveries for each of the past three years. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs would represent approximately 14% of the Company’s total retail energy deliveries for 2016, 2015, and 2014.

The retail customer choice program does not have a material impact on the Company’s financial condition or operating results as revenue changes resulting from increases or decreases in electricity sales to direct access customers are substantially offset by changes in the Company’s cost of purchased power and fuel. Further, the program provides for “transition adjustment” charges or credits to direct access and market-based pricing customers that reflect the above- or below-market cost of energy resources owned or purchased by the Company. SuchTransition adjustments, are designedintended 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 additionCompany on cost of service pricing, are charged to cost-of-serviceDirect Access and market-based pricing residentialcustomers if market energy prices are below PGE’s fixed generation costs (or credited to, if market prices are above). For further information regarding Direct Access deliveries, see “Customers and small commercial customers can select portfolio options from PGE that include time-of-useDemand” in the Overview section of Item 7.—“Management’s Discussion and renewable resource pricing.Analysis of Financial Condition and Results of Operations.”

Energy Efficiency Funding—Oregon law provides for a “publicpublic purpose charge”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 ETOEnergy Trust of Oregon (ETO) and other agencies for administration of these programs. Approximately, $50The Company collected $52 million was collected from customers for this charge in 2016, and $512018, $53 million in both 20152017, and 2014.$50 million in 2016.

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 approximately 2.7%3.7%, 2.4%3.6%, and 3.2%2.7% of retail revenues for applicable customers in 2016, 2015,2018, 2017, and 2014,2016, respectively. Under the tariff, approximately $48$66 million $42 million, and $48 million werewas collected from eligible customers in 2016, 2015,both 2018 and 2014, respectively.2017, and $48 millionwas collected in 2016.

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

Regulatory Accounting

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

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expected future credits or refunds to customers. PGE records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future regulatory environment and related accounting guidance. For additional information,

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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. In addition, the Company distributes power to commercial and industrial customers that choose to purchase their energy supply from an ESS. TheAlthough the Company includes such “direct access”Direct Access customers in its customer counts and energy delivered to such customers in its total retail energy deliveries. Retaildeliveries, retail revenues include only delivery charges and applicable transition adjustments for these direct accessDirect Access customers. The Company conducts retail electric operations within its service territory and competes with: i) the local natural gas distribution company for the energy needs of residential and commercial space heating, water heating, and appliances; and ii) fuel oil suppliers, primarily for residential customers’ space heating needs. Energy efficiency, and conservation measures as well 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%7% of PGE’s total retail revenues or 9%10% of total retail deliveries. While the twenty largest commercial and industrial customers constituted 11%12% of total retail revenues in 20162018, they represented nineten different groups including high tech paperand other manufacturing, health care services, governmental agencies, health services,data centers, and retailers.


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PGE’s Retail revenues, retail energy deliveries, and average number of retail customers consist of the following for the years presented:
following:
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Retail revenues(1) (dollars in millions):
                      
Residential$907
 51% $895
 50% $893
 51%$948
 53 % $969
 52% $907
 51%
Commercial665
 37
 662
 37
 657
 36
665
 37
 669
 36
 665
 37
Industrial208
 12
 228
 13
 221
 13
210
 12
 212
 11
 208
 12
Subtotal1,780
 100
 1,785
 100
 1,771
 100
1,823
 102
 1,850
 99
 1,780
 100
Other accrued (deferred) revenues, net3
 —
 (10) —
 (8) —
Alternative revenue programs, net of amortization

3
 —
 —
 —
 —
 —
Other accrued (deferred) revenues, net(2)
(45) (2) 10
 1
 3
 —
Total retail revenues$1,783
 100% $1,775
 100% $1,763
 100%$1,781
 100 % $1,860
 100% $1,783
 100%
Retail energy deliveries(2) (MWh in thousands):
           
Retail energy deliveries(3) (MWh in thousands):
           
Residential7,348
 39% 7,325
 38% 7,462
 39%7,416
 39 % 7,880
 40% 7,348
 39%
Commercial7,457
 39
 7,511
 39
 7,494
 39
7,430
 39
 7,555
 38
 7,457
 39
Industrial4,166
 22
 4,546
 23
 4,310
 22
4,376
 22
 4,283
 22
 4,166
 22
Total retail energy deliveries18,971
 100% 19,382
 100% 19,266
 100%19,222
 100 % 19,718
 100% 18,971
 100%
Average number of retail customers:                      
Residential752,365
 88% 742,467
 88% 735,502
 87%772,389
 88 % 762,211
 88% 752,365
 88%
Commercial106,773
 12
 105,802
 12
 105,231
 13
109,107
 12
 107,855
 12
 106,773
 12
Industrial258
 —
 255
 —
 260
 —
270
 —
 267
 —
 258
 —
Total859,396
 100% 848,524
 100% 840,993
 100%881,766
 100 % 870,333
 100% 859,396
 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)Activity for the year ended December 31, 2018 primarily relates to the regulatory liability deferral of the 2018 net tax benefits due to the change in corporate tax rate under the Tax Cuts and Jobs Act of 2018 (TCJA). For further information, see Note 12, Income Taxes in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”
(3)Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

Additional averages for retail customers are as follows:
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Residential          
Revenue per customer (in dollars):$1,114
 $1,139
 $1,154
$1,153
 $1,181
 $1,114
Usage per customer (in kilowatt hours):9,766
 9,866
 10,145
9,601
 10,338
 9,766
Revenue per kilowatt hour (in cents):
11.40¢ 
11.55¢ 
11.37¢
12.01¢ 
11.42¢ 
11.40¢
Commercial     
    
Revenue per customer (in dollars):$6,166
 $6,254
 $6,187
$6,051
 $6,142
 $6,166
Usage per customer (in kilowatt hours):69,839
 70,987
 71,216
68,096
 70,046
 69,839
Revenue per kilowatt hour (in cents):
8.83¢ 
8.81¢ 
8.69¢
8.89¢ 
8.77¢ 
8.83¢
Industrial          
Revenue per customer (in dollars):$804,953
 $876,866
 $851,149
$776,245
 $792,466
 $804,953
Usage per customer (in kilowatt hours):16,146,371
 17,485,281
 16,576,500
16,207,263
 16,041,461
 16,146,371
Revenue per kilowatt hour (in cents):
4.99¢ 
5.01¢ 
5.13¢
4.79¢ 
4.94¢ 
4.99¢

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

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and are determined through general rate case proceedings and various tariff filings with the OPUC. Additionally, the Company offers different pricing options including a daily market price option, various time-of-use options, and

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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 in recent years, while the historical winter peak has not increased in twenty years. In the past few years, summer peaks have exceeded winter peaks and long-term load forecasts show summer peaksexpect that trend to exceed winter peaks.continue. Economic conditions can also affect residential demand; strong job growth and population growth in PGE’s service territory have led to increasing customer growth rates. Residential demand is also impacted by energy efficiency measures; however, the Company’s decoupling mechanism is intended to mitigate the financial effects of such measures.

During 2016,2018, total residential deliveries increased 0.3%decreased 5.9% compared to 2015. Althoughwith 2017. PGE witnessed a 1.3% increase in the average number of residential customers served during the year actualwhile average usage per customer declined by 1.0%decreased 7.1% driven by unfavorable weather compared to the prior year. Both 2015Temperatures in 2018 were characterized by both a mild heating season and 2016 experienced historically warm temperaturesa milder cooling season over the summer months, decreasing residential energy deliveries. The year-over-year impact was intensified by cold during the winter heating season reducingin 2017, which increased residential energy deliveries; however, 2016 did not experience the offsetting warm temperatures during the cooling seasondeliveries in that were experienced in 2015.year. On a weather adjustedweather-adjusted basis, energy deliveries to residential customers increased by 1.4%0.2% in 20162018 when compared to 2015.with 2017.

During 2015,2017, total residential deliveries increased 7.2% compared with 2016. PGE experienced historically warm temperatureswitnessed a 1.3% increase in the average number of residential customers served during the winteryear 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 reducingin the first quarter and a warm cooling season over the summer months, increasing residential energy deliveries. Although this weather effectThe year-over-year impact was partially offsetintensified by unseasonably warm heating season temperatures during the summer cooling season, the overall result wasseen in 2016, which decreased residential energy deliveries in that total residential deliveries decreased 1.8% in 2015 compared to 2014.year. On a weather adjustedweather-adjusted basis, energy deliveries to residential customers increaseddecreased by 2.2% in 20152017 when compared to 2014.with 2016.

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

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

In 2016, despite 0.9% growth2018, a heating season that was more mild than the prior year drove a 1.7% decrease in the average number ofcommercial deliveries compared with 2017. Weather-adjusted, deliveries to commercial customers commercial deliveries decreased 0.7% compared with 2015. The decrease reflects unfavorable weather conditions, and slightly lower demand from a few groups,by 0.4% in 2018. Deliveries to several retail sectors decreased, including food and merchandise 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.health care, while other service sectors, including data centers, showed growth. Energy efficiency continues to impact growth, and conservation and building codes and standards are likely reducing energy deliveries beyond the impact of energy efficiency programs.

Deliveries to commercial customers increased 0.2% in 2015 compared with 2014, which was primarily due to an increase in deliveries to irrigation and service sector customers being mostly offset by lower deliveries to all other commercial sectors combined with
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In 2017, a 1.0% increasegrowth in the average number of commercial customers.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.

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


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The Company’s industrial energy deliveries decreased 8.4%increased 2.2% in 20162018 from 2015, largely2017, reflecting increases across several manufacturing sectors, with the strongest increases due to customers in high tech manufacturing and their suppliers. The 2.8% increase in 2017 from 2016 reflected increases across several manufacturing sectors, with the strongest increases to customers in high tech manufacturing and their suppliers. These increases have occurred even though the Company experienced the loss of a large paper manufacturing customer to which PGE has delivered approximately 450 thousand MWhs annually, with corresponding revenues of approximately $20 million, havingthat ceased operations in late 2015. Although the majority of power this customer purchased was under the Company’s daily market index-based price option,October 2017, which reduced comparative annual industrial deliveries for a portion was at cost of service prices. Adjusted for that one customer, industrial energy deliveries were 1.4% higher than 2015 levels driven by continued, albeit slowed, increases in energy deliveries to high tech manufacturing customers.

The 5.5% increase in 2015 from 2014 was due primarily to increased demand from high tech manufacturing2017 and paper manufacturing customers.all of 2018.

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.mechanism, and deferral of the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. For further information on thesethe RAC and decoupling items, see “OPUCLegal, Regulatory and Other State of Oregon RegulationEnvironmental Matters” in the RegulationOverview section of this Item 1.7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations. For further information on the TCJA, see Note 12, Income Taxes in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro and wind conditions, and daily and seasonal retail demand. Wholesale revenues represented 5%8% of total revenues in 2016, 2015,2018 and 2014.5% in each of the prior two years.

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

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, excess fuel sales, pole contact rentals, and other electric services provided to customers. Other operating revenues have represented 2%3% of total revenues in 2018 and 2% in each of the past threeprior two years.

Seasonality

Demand for electricity by PGE’s residential and, to a lesser extent, commercial customers, is affected by seasonal weather conditions. The Company uses heating and cooling degree-days to determine the effect of weather on the demand for electricity. Heating and cooling degree-days provide cumulative variances in the average daily

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temperature from a baseline of 65 degrees, over a period of time, to indicate the extent to which customers are likely to use, or have used, electricity for heating or air conditioning. The higher the number of degree-days, the greater the expected demand for electricity.


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The following table presents the heating and cooling degree-days for the most recent three-year period, along with 15-year averages for the most recent year provided by the National Weather Service, as measured at Portland International Airport:
Heating
Degree-Days
 
Cooling
Degree-Days
Heating
Degree-Days
 
Cooling
Degree-Days
20183,702 692
20174,558 700
20163,552 5483,552 548
20153,461 785
20143,794 653
15-year average4,233 4714,117 514
  
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”summer peak of 3,9493,976 MW occurred in July 2009.August 2017. The following table presents PGE’s average winter (defined as January, February, and December) and summer (defined as July, August, and September) loads for the periods presented, along with the corresponding peak load (in MWs) and month in which such peak occurred:occurred. As the table below illustrates, although the average winter loads continue to run higher than average summer loads, the Company has experienced its highest peak loads during summer in each of the past three years:
 Winter Loads Summer Loads
 Average Peak Month Average Peak Month
20162,537 3,716 December 2,246 3,726 August
20152,509 3,255 December 2,390 3,914 July
20142,574 3,866 February 2,358 3,646 August
 Winter Loads Summer Loads
 Average Peak Month Average Peak Month
20182,519 3,399 February 2,349 3,816 August
20172,698 3,727 January 2,380 3,976 August
20162,537 3,716 December 2,246 3,726 August

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

Power Supply

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

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


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

 As of December 31,
 2016 2015 2014
 Capacity % Capacity % Capacity %
Generation:           
Thermal:           
Natural gas1,805
 38% 1,371
 30% 1,389
 28%
Coal814
 17
 814
 17
 814
 17
Total thermal2,619
 55
 2,185
 47
 2,203
 45
Wind (1)
717
 15
 717
 16
 717
 15
Hydro (2)
495
 11
 495
 11
 494
 10
Total generation3,831
 81
 3,397
 74
 3,414
 70
Purchased power:           
Long-term contracts:           
Capacity/exchange250
 5
 250
 5
 250
 5
Hydro534
 12
 592
 13
 595
 12
Wind39
 1
 39
 1
 39
 1
Solar13
 —
 13
 —
 13
 —
Other18
 —
 118
 3
 118
 2
Total long-term contracts854
 18
 1,012
 22
 1,015
 20
Short-term contracts45
 1
 200
 4
 481
 10
Total purchased power899
 19
 1,212
 26
 1,496
 30
Total resource capacity4,730
 100% 4,609
 100% 4,910
 100%
            
 As of December 31,
 2018 2017 2016
 Capacity % Capacity % Capacity %
Generation:           
Thermal:           
Natural gas1,830
 38 % 1,831
 39% 1,805
 38%
Coal814
 17
 814
 17
 814
 17
Total thermal2,644
 55
 2,645
 56
 2,619
 55
Wind (1)
717
 15
 717
 15
 717
 15
Hydro (2)
495
 10
 495
 10
 495
 11
Total generation3,856
 80
 3,857
 81
 3,831
 81
Purchased power:           
Long-term contracts:           
Capacity/exchange100
 2
 100
 2
 250
 5
Hydro518
 11
 531
 12
 534
 12
Wind39
 1
 39
 1
 39
 1
Solar46
 1
 13
 —
 13
 —
Other27
 —
 18
 —
 18
 —
Total long-term contracts730
 15
 701
 15
 854
 18
Short-term contracts273
 5
 185
 4
 45
 1
Total purchased power1,003
 20
 886
 19
 899
 19
Total resource capacity4,859
 100 % 4,743
 100% 4,730
 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, 20162018, 20152017, and 20142016, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Generation

The portion of PGE’s retail load requirements generated by its plants varies from year to year and is determined by various factors, including planned and unplanned outages, availability and price of coal and natural gas, precipitation and snow-pack levels, the market price of electricity, and wind variability. In July 2016, PGE placed Carty, a natural gas-fired baseload resource, into service and in December 2014, completed construction of PW2, a flexible capacity resource, and Tucannon River, a wind resource. These additional resources resulted from the competitive bidding process completed in 2013 consistent with the Company’s 2009 IRP. For additional information on the completion of Carty, see “Carty” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 32%41% of PGE’s total retail load requirement in 20162018, 25%33% in 20152017, and 18%32% in 20142016.


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PGE increased itsThe Company operates, and has a 90% ownership interest in, the Boardman coal-fired generating plant (Boardman) through the acquisition of the 10% interest of a co-owner, increasing the Company’s ownership share to 90% from 80% on December 31, 2014.

The Company operates Boardman and 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 19%17% of the Company’s total retail load requirement in 20162018, compared with 22%18% in 20152017, and 24%19% in 20142016. Boardman is scheduled 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

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Oregon, until 2035. For additional information on Senate BillSB 1547, see “Legal, Regulatory, and Environmental Matters” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
    
The thermal plants provide reliable power and capacity reserves for PGE’s customers. These resources have a combined capacity with the addition of Carty, of 2,6192,644 MW, representing approximately 68%69% of the net capacity of PGE’s generating portfolio. Thermal plant availability, excluding Colstrip, was 92%93% in 20162018, 88% in 2017, and 89%92% in both 2015 and 20142016, while Colstrip availability was 85%82% in 20162018, compared with 93%86% in 20152017 and 83%85% in 20142016.

WindPGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River.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 10% of the Company’s total retail load requirement in 20162018, 9% in 20152017, and 6%10% in 20142016. Availability for these resources was95%92% in 20162018, compared with 97%96% in 20152017 and 94%95% in 20142016. The expected energy from wind resources differs from the nameplate capacity and is expected to range from 135 MWa to 180 MWa for Biglow Canyon and from 80 MWa to 110 MWa for Tucannon River, dependent upon wind conditions.

Hydro
The Company’s FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), four plants on the Clackamas River, and one on the Willamette River. The licenses for these projects expire at various dates ranging from 2035 to 2055. Although these plants have a combined capacity of 495 MW, actual energy received is dependent upon river flows. Energy from these resources provided 9%8% of the Company’s total retail load requirement in 2016, 8% in 20152018, and 9% in both 2017 and 20142016, with availability of 99% in both 2016 and 2015, and 100%93% in 20142018, 95% in 2017, and 99% in 2016. Northwest hydro conditions have a significant impact on the region’s power supply, with water conditions significantly impacting PGE’s cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases.

PGE has a 66.67% ownership interest in the 455 MW Pelton/Round Butte hydroelectric project on the Deschutes River, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The Tribes have an option to purchase an additional undivided 16.66% interest in Pelton/Round Butte at its discretion on December 31, 2021. The Tribes have a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If both options are exercised by the Tribes, the Tribes’ ownership percentage would exceed 50%.

Dispatchable Standby Generation (DSG)—PGE has a DSG program under which the Company can start, operate, and monitor customer-owned diesel-fueled standby generators when needed to provide NERC-required operating reserves. As of December 31, 20162018, there were 5862 sites with a total DSG capacity of 117129 MW. Additional DSG projects are being pursued with a total goal of 135MW online by the end of 2021.

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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.


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PGE owns 79.5%, and is the operator of record, of the Kelso-Beaver Pipeline, which directly connects PW1, PW2, and Beaver to Northwest Pipeline, an interstate natural gas pipeline operating between British Columbia and New Mexico. Currently, PGE transports natural gas on the Kelso-Beaver Pipeline for its own use under a firm transportation service agreement, with capacity offered to others on an interruptible basis to the extent not utilized by the Company. PGE has access to 103,305 Dth per day of firm natural gas transportation capacity to serve the three plants.

PGE also has contractual access to natural gas storage in Mist, Oregon from which it can draw as needed. The Company expects to utilize this resource when economic factors favor its use or in the event that natural gas supplies are interrupted. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PW1, PW2, and Beaver.

PGE has entered into a long-term agreement with this gas companyNW Natural 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 winterSpring of 2018-2019,2019, at a cost of approximately $128$144 million.

Beaver has the capability to operate on No. 2 diesel fuel oil when it is economical or if the plant’s natural gas supply is interrupted. PGE had an approximate four dayfour-day supply of ultra-low sulfur diesel fuel oil at the plant site as of December 31, 2016.2018. The current operating permit for Beaver limits the number of gallons of fuel oil that can be burned daily, which effectively limits the daily hours of operation of Beaver on fuel oil.

To serve Coyote Springs and Carty, PGE has access to 119,500 Dth per day of firm natural gas transportation capacity on three pipeline systems accessing gas fields in Alberta, Canada. PGE believes that sufficient market supplies of natural gas are available for Coyote Springs and Carty for the foreseeable future, based on anticipated operation of the plants. Although Coyote Springs was designed to also operate on fuel oil, such capability has been deactivated in order to optimize natural gas operations.

Coal
PGE has fixed-price purchase agreements that, together with existing inventory, will provide coal sufficient for the anticipated operating needs for Boardman during 2017.2019. The coal is obtained from surface mining operations in Wyoming and Montana and is delivered by rail under twoseparate transportation contracts which extend through 2020.

The terms of contracts and the quality of coal are expected to be staged in alignment with required emissions limits. PGE believes that sufficient market supplies of coal are available to meet anticipated coal-fired operations of Boardman through 2020.

The Colstrip co-owners currently obtain coal to fuel the plant via conveyor belt from a mine that lies adjacent to the facility. The current contract forfacility and is the sole source of coal supply for the plant. The company that owns and operates the mine declared bankruptcy in the fourth quarter of 2018. Debtors in the bankruptcy proceeding filed notice on January 19, 2019 of their decision to reject the co-owners’ current coal contract, which currently extends through December 31, 2019. The co-owners have filed objections to such a plan, and a hearing on the debtor’s plan is expected to be held by March 1, 2019. In the event the current coal supply contract is ultimately rejected in bankruptcy, Colstrip and the co-owners may have a material limitation on coal supply for a portion of 2019, and the Colstrip co-owners arebeyond, which may result in the process of negotiating an extension to the contract.

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increased replacement power costs.

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

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provide the most favorable economic mix on a variable cost basis. Such contracts have original terms ranging from one month to 5337 years and expire at varying dates through 2055.2055.

PGE’s medium termmedium-term power cost strategy helps mitigate the effect of price volatility on its customers due to changing energy market conditions. The strategy allows the Company to take positions in power and fuel markets up to five years in advance of physical delivery. By purchasing a portion of anticipated energy needs for future years over an extended period, PGE mitigates a portion of the potential future volatility in the average cost of purchased power and fuel.
The Company’s major power purchase contracts consist of the following (also see the preceding table which summarizes the average resource capabilities related to these contracts):

Capacity/exchange—PGE has two contractsone contract that provide PGEprovides the Company with firm capacity to help meet the Company’s peak loads. The contracts represent two power purchase agreementsagreement allows for up to 100 MW of seasonal peaking capacity oneduring winter periods through February 2019. A new seasonal peaking capacity agreement coversduring the summer and winter from December 2014 to Februaryperiods for 100 MW will begin in July 2019 and the second agreement covers summer from July 2014 to September 2018. During 2016, PGE also had one contract representing 150continue through February 2024. An additional 200 MW of annual capacity which expiredwill be added in December 2016.January 2021, with a five-year term.

Hydro—During 2016,2018, the Company had four contracts that provided for the purchase of power generated from hydroelectric projects with an aggregate capacity of 59 MW and contract expirations between 2017 and 2033. In addition, PGE has the following:following agreements:

Mid-Columbia hydro—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of threetwo hydroelectric projects on the mid-Columbia River. One contract representing 150159 MW of capacity that expires in 20182028 and aone contract representing 163 MW of capacity that expires in 2052. Although the projects currently provide a total of 313322 MW of capacity, actual energy received is dependent upon river flows and capacity amounts may decline over time.

Confederated Tribes—PGE has a long-term agreement under which the Company purchases, at index prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides approximately 162159 MW of net capacity, actual energy received is dependent upon river flows. The term of the agreement coincides with the term of the FERC license for this project, which expires in 2055. In 2014, PGE entered into an agreement with the Tribes under which the Tribes have agreed to sell, on modified payment terms, their share of the energy generated from the Pelton/Round Butte hydroelectric project exclusively to the Company through 2024.

Other— PGE has two contracts that provide for the purchase of power generated from hydroelectric projects with an aggregate capacity of 37 MW and contract expiration in 2032.

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

Solar—PGE has threefifteen agreements that expire during 2036 andthroughout 2031 to 2037 to purchase power generated from photovoltaic solar projects, which have a combined generating capacity of 740 MW. In addition, the Company operates, and purchases power from threetwo solar projects with an aggregate of approximately 6 MW of capacity. The expected energy from these solar resources will vary from the nameplate capacity due to varying solar conditions.

Other—These primarily consist of long-term contracts to purchase power from various counterparties, including other Pacific Northwest utilities and Qualifying Facilities under the Public Utilities Regulatory Policies Act (QF), over terms extending into 2031.2032.


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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.


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PGE also utilizes spot purchases of power in the open market to secure the energy required to serve its retail customers. Such purchases are made under contracts that range in duration from 15 minutes to less than one month. For additional information regarding PGE’s power purchase contracts, see Note 15,16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Future Energy Resource Strategy

PGE’s IRP outlines how the Company proposesCompany’s plan to meet future customer demand and describes PGE’s future energy supply strategy. The Company’s IRP filing acknowledged byFor a detailed discussion of the OPUC in December 2014, and updated in December 2015, included an “Action Plan” that covered PGE’s proposed actions to occur before the end of 2017. As a result, in September 2015, the Company announced plans to explore participation in the western EIM, which was launched in 2014 by the CAISO. The western EIM is a real-time energy wholesale market that automatically dispatches the lowest-cost electricity resources available to meet utility customer needs, while optimizing use of renewable energy over a large geographic area. PGE signed an agreement, which was approved by the FERC in January 2016, to join the western EIM. The agreement outlines a schedule of activities and milestones leading to the Company’s participation in the EIM, targeted to begin in the fall of 2017.

PGE filed a subsequent IRP (2016 IRP) with the OPUC in mid- November 2016. The 2016 IRP addresses 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 also considers the OCEP, which, among other things, increased the RPS requirements for 2025 and future years. For further information on the OCEP,IRPs, see the “Legal, Regulatory and Environmental” section of in“Integrated Resource Plans” within the Overview section inof Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

All portfolios analyzed in the 2016 IRP pursue: i) compliance with the RPS through 2050; ii) inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and iii) retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.

The 2016 IRP is available on PGE’s website. The recommended Action Plan in the 2016 IRP encompasses both demand-side and supply-side actions as well as integration through flexible technologies. Specific recommendations include: i) the deployment of a minimum of 135 MWa of cost-effective energy efficiency; ii) the pursuit of up to 77 MW of additional demand response; and iii) the addition of approximately 175 MWa in RPS compliant renewable resources, which could include unbundled RECs. The current draft also identifies the need for PGE to acquire up to 850 MW of capacity, which includes 375-550 MW of long-term dispatchable resources and up to 400 MW of annual capacity resources.

Acknowledgment of the 2016 IRP is targeted for mid-2017. Upon acknowledgment, PGE will request approval from the OPUC to issue one or more RFPs to acquire capacity and renewable resources through a combination of resource options that could include wind, solar, geothermal, biomass, efficient combined-cycle natural gas-fired facilities, and generic capacity facilities such as seasonal contracts, power purchase agreements, energy storage, and combustion turbines. The RFP process will include oversight by an independent evaluator and review by the OPUC.

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

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territory. In 2016,2018, PGE delivered approximately 2224 million megawatt hours (MWh)MWh in its balancing authority area through 1,2481,256 circuit miles of transmission lines operating at or above 115 kV.kilovolts (kV).

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

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

On property owned or leased by PGE;

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

Under or over private property primarily pursuant to easements obtained from the record holder of title at the time of grant; and

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

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

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

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

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

PGE is subject to state regulatory requirements related to the quality and reliability of its distribution system. Such requirements are reflected in specific indices that measure outage duration, outage frequency, and momentary power interruptions. The Company is required to include performance results related to service quality measures in annual reports filed with the OPUC.

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


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Environmental Matters

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


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Air Quality

Clean Air Act—PGE’s operations, primarily its thermal generating plants, are subject to regulation under the federal Clean Air Act (CAA), which addresses, among other things, particulate matter, hazardous air pollutants, and greenhouse gas emissions (GHGs). Oregon and Montana, the states in which PGE’s thermal facilities are located, also implement and administer certain portions of the CAA and have set standards that are at least equal to federal standards.

The EPA issued a rule effective in April 2012, aimed at the reduction of toxic air emissions from power plants. Specifically, these mercury and air toxics standards (MATS) are intended to reduce emissions from new and existing coal- and oil-fired electric utility steam generating units. Existing emissions controls at Boardman and Colstrip allow the plants to meet the MATS requirements without additional capital investment. Oregon Department of Environmental Quality (DEQ) rules provide for coal-fired operation at Boardman to cease no later than December 31, 2020. The Company does not anticipate further capital investment to meet the requirements currently in place.

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

PGE manages its air emissions 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 recent installation of 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.

Climate Change—The EPA has taken the lead role on climate change policy utilizing existing authority under the CAA to develop regulations. In August 2015, the EPA released a final rule, which it calls the “Clean Power Plan.” Under the final rule,Plan” (CPP), under which each state would have to reduce the carbon intensity ofdioxide emissions from its power sector on a state-wide basis by an amount specified by the EPA. The rule establishes state-specific goals in terms of pounds of carbon dioxide emitted per MWh of energy produced. The rule 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.

The target amounts were determined based on the EPA’s view of the options for each state, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants; and iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy). The final goal would need to be met by 2030 and interim goals for each state would need to be met from 2022 to 2029. Under the rule, states have flexibility in designing programs to meet their emission reduction targets, including the three approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

PGE cannot predict how the states in which the Company’s generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations. The Company continues to monitor the developments around the implementation of the rule and efforts by state regulators to develop state plans. Onbasis. In February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP.

On August 21, 2018, the EPA proposed the Affordable Clean Power Plan pendingEnergy (ACE) rule, which would replace the resolution of legal challengesCPP and establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. The public comment period on the proposed ACE rule closed on October 31, 2018. The EPA has yet to finalize the rule.

The Company continues to monitor the developments around the CPP and the potential new rule. The Company cannot predict the impact of the stay, the ultimate outcome of the legal challenges to, and the regulatory process of, the EPA, or whether Oregon and Montana will continue to developimplement the state’s implementation plan in light ofrules or how the Supreme Court’s stay.

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. Althoughrules may impact the guideline does not mandate reductions by any specific entity, nor include penalties for failure to meet the goal, the Company is required to report to the DEQ the amount of GHG emissions produced along with the total amount of energy produced or purchased by PGE for consumption in Oregon.


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Company’s operations.

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. If incremental costs were incurred as a result of changes in the regulations regarding GHGs, the Company would seek recovery in customer prices. 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 68%69% of the Company’s net generating capacity at December 31, 2016. If PGE were to incur incremental costs as a result of changes in the regulations regarding GHGs, the Company would seek recovery in customer prices.2018.

Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill 1547, effective March 8, 2016. The legislation prevents large utilities from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for PGE’s output from the Colstrip facility), increases the RPS percentages in certain future years, changes the life of certain RECs, requires the development of community solar programs, seeks the development of transportation electrification programs, and requires that a portion of electricity come from small scale renewable or certain biomass projects. For more information regarding the OCEP, and its impact on PGE,CPP, see the “Legal, Regulatory, and Environmental Matters” section of Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Water Quality

The federal Clean Water Act requires that any federal license or permit to conduct an activity that may result in a discharge to waters of the United States must first receive a water quality certification from the state in which the activity will occur. In Oregon, Montana, and Washington, the Departments of Environmental Quality are

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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 Note 18, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Threatened and Endangered Species and Wildlife

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

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

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

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application for a permit, along with a draft Eagle Conservation Plan, to the USFWS, pertaining to Biglow Canyon that would address the incidental take of eagles, and expects to submitsubmitted a similar draft application for Tucannon River in 2017.

Hazardous WasteMaterial

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

The generation of electricity at Boardman and Colstrip produces a by-productby-products known as coal combustion residuals (CCRs), which have historically not been considered hazardous waste under the RCRA.. In December 2014, the EPA signed a final rule, which became effective as ofin October 19, 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 new EPA rule. PGE has determined that it will continue use of the on-site landfill in compliance with the newCCR rule, and the Company believes the new EPACCR rule will not have a material effect on operations at Boardman. Based on information from the Colstrip operator, this 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 7,8, 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, (CERCLA), 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.

A 1997
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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 outlines the EPA’s selected remediation alternative to clean-up for Portland Harbor. The estimated total cost of the remedy has 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. 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.

On July 15, 2016, the Company filed a deferral application with the OPUC to allow for the deferral of the future environmental remediation costs related to Portland Harbor, as well as seek authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company has reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, subject to OPUC final decision, which is expected in the first quarter of 2017. The mechanism, as proposed, would allow the Company to recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism would establish annual prudency reviews of environmental expenditures and be subject to an annual earnings test. For additional information on thisregarding the EPA action on Portland Harbor, see Note 17,18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


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Under the Nuclear Waste Policy Act of 1982, the USDOE is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel from Trojan that is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel at the former plant site. The spent nuclear fuel is expected to remain in the ISFSI until permanent off-site storage is available. Shipment of the spent nuclear fuel from the ISFSI to off-site storage is not expected to be completed prior to 2034. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 7,8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


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ExecutiveOfficers

The following are PGE’s current executive officers:
Name Age Current Position and Previous Experience Year Appointed Officer
       
Larry N. Bekkedahl 58 Vice 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 Bonneville Power Administration (“BPA”) (June 2012 to August 2014), Vice President of Engineering and Technical Services at BPA (2008 to August 2014). 2014
Bradley Y. Jenkins 55 Vice 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 Power Plant (September 2012 to November 2013), Operations Manager, Boardman Power Plant (March 2012 to September 2012). 2015
Lisa A. Kaner 58 Vice 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. Kochavatr 45 Vice 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
James F. Lobdell 60 Senior Vice President, Finance, Chief Financial Officer and Treasurer (March 2013 to present), Vice President, Power Operations and Resource Strategy (August 2004 to March 2013), Vice President, Power Operations (September 2002 to August 2, 2004), Vice President, Risk Management Reporting, Controls and Credit (May 2001 until September 2002). 2001
Anne F. Mersereau 56 Vice President, Human Resources, Diversity 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
William O. Nicholson 60 Vice President, Utility Technical Services (January 2019 to present), Vice President, Customer Service, Transmission and Distribution (April 2011 to January 2019), Vice President, Distribution Operations (August 2009 to April 2011), Vice President, Customers and Economic Development (May 2007 to August 2009). General Manager, Distribution Western Region (April 2004 to May 2007), General Manager, Distribution Line Operations and Services (February 2002 to April 2004). 2007
Maria M. Pope 54 President (October 2017 to present) and Chief Executive Officer (January 2018 to present), Senior Vice President, Power Supply, Operations and Resource Strategy (March 2013 to January 2018), 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 Robertson 52 Vice President, Public Policy (August 2009 to present), Director of Government Affairs (June 2004 to August 2009). 2009

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Kristin A. Stathis 55 Vice President, Customer Solutions (January 2019 to present), 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

ITEM 1A.     RISK FACTORS.

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

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

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

PGE attempts to manage its costs at levels consistent with the OPUC approved prices. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the Company’s financial and operating results could be adversely affected.

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

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

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

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


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Volatility in these markets can affect the availability, price and demand for power and natural gas. Disruption in power and natural gas markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect regulatory and legislative processes in unpredictable ways, affect wholesale power prices, and impair PGE’s ability to manage its energy portfolio. Changes in power and natural gas prices can also affect the fair value of derivative instruments and cash requirements to purchase power and natural gas. If power and natural gas prices decrease from those contained in the Company’s existing purchased power and natural gas agreements, PGE may be required to provide increased collateral, which could adversely affect the Company’s liquidity. Conversely, if power and natural gas prices rise, especially during periods when the Company requires greater-than-expected

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volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated.

The risk of volatility in power costs is partially mitigated through the AUT and the PCAM. Application of the PCAM requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, the PCAM is expected to only partially mitigate the potentially adverse financial impacts of forced generating plant outages, reduced hydro and wind availability, interruptions in fuel supplies, and volatile wholesale energy prices.

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

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

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

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

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

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.


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

Access to capital markets is important to PGE’s ability to operate its business and complete its capital projects. Credit rating agencies evaluate the Company’s credit ratings on a periodic basis and when certain events occur. A ratings downgrade could increase 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

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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 17,18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

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

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

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

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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.


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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. For additional information concerning PGE’s capital requirements, see “Capital Requirements” in the Liquidity and Capital Resources section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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

Legislative or regulatory efforts to reduce 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.

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

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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.

In addition, it is possible that the Company might not be aware of certain developments at the time it makes such a representation in connection with a request for a loan, which could cause the representation to be untrue at the time

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made and constitute an event of default. Such a circumstance could result in a loss of the banks’ commitments under the credit facilities and, in certain circumstances, the accelerated repayment of any outstanding loan balances.

A similar risk exists with respect to the Company’s letter of credit facilities, which currently provide for a total capacity of $160 million.

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

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

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

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

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

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

Development of alternative technologies may negatively impact the value of PGE’s generation facilities.

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


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

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


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

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

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

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

Beginning in 2011, the OPUC authorized the Company to collect $2 million annually from retail customers for such damages and to defer any amount not utilized in the current year. During 2015 and 2016, PGE fully utilized the existing reserve balance as a result of restoration costs associated with storm damage occurring during those years.

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

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

PGE is subject to regulation by the FERC, the OPUC, and by certain federal, state, and local authorities under environmental and other laws. Such regulation significantly influences the Company’s operating environment and can have an effect on many aspects of its business. Changes to regulations are ongoing, and the Company cannot predict with certainty the future course of such changes or the ultimate effect that they might have on its business. However, changes in regulations could delay or adversely affect business planning and transactions, and substantially increase the Company’s costs.
 
ITEM 1B.     UNRESOLVED STAFF COMMENTS.

None.

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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, 20162018 (in MW):
Facility Location 
Net
Capacity (1)
Wholly-owned:    
Natural Gas/Gas or Oil:    
Beaver Clatskanie, Oregon 508
MW
Carty Boardman, Oregon 434437
Port Westward Unit 1 (PW1) Clatskanie, Oregon 395411
Coyote Springs Boardman, Oregon 243249
Port Westward Unit 2 (PW2) Clatskanie, Oregon 225
Wind:    
Biglow Canyon Sherman County, Oregon 450
Tucannon River Columbia County, Washington 267
Hydro:    
North Fork Clackamas River 58
Faraday Clackamas River 46
Oak Grove Clackamas River 45
River Mill Clackamas River 25
T.W. Sullivan Willamette River 18
Jointly-owned (2):
    
Coal:    
Boardman (3)
 Boardman, Oregon 518
Colstrip (4)
 Colstrip, Montana 296
Hydro:    
Round Butte (5)
 Deschutes River 230
Pelton (5)
 Deschutes River 73
Net capacity   3,8313,856
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)ReflectsNet capacity 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.interest in the facility, which is operated by Talen Montana, LLC.
(5)PGE operates Pelton and Round Butte and has a 66.67% ownership interest.


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PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the 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, 2016,2018, PGE owned an electric transmission system consisting of 1,2481,256 circuit miles as follows: 287 circuit miles of 500 kV line; 402410 circuit miles of 230 kV line; and 559 miles of 115 kV line. The Company also has 27,25927,627 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 capacity on the Colstrip Project Transmission facilities from Colstrip to BPA’s transmission system; and
Approximately 20% of the capacity on the Pacific Northwest Intertie, a 4,800 MW transmission facility between the John Day Substation near the Columbia River in northern Oregon, and Malin, in southern Oregon, near the California border. The Pacific Northwest Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

In addition, the Company has contractual rights to the following transmission capacity:
Approximately 3,4903,715 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.

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

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

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

In August 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions abating these class action proceedings until the OPUC responded with respect to the certain issues that had been remanded to the OPUC by the Circuit Court. In October 2006, the Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions.

Following the October 2014 decision of the Oregon Supreme Court upholding the OPUC refund order in the related Trojan regulatory proceeding, the Circuit Court granted PGE’s motion to lift the abatement in June 2015. PGE filed a motion for summary judgment dismissing the lawsuits. Following oral argument on PGE’s motion for summary judgment, Plaintiffs moved to amend the complaints. PGE opposed the request to amend.

On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the Complaint and, on March 16, 2016, entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs.


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On April 14, 2016, the plaintiffs appealed the general judgment of the Circuit Court in the Court of Appeals for the State of Oregon. For additional information on this matter, seeSee Note 17,18, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

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

In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, expanded the refund period to include January 1, 2000 through December 24, 2000 for certain types of claims, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. Those orders included a finding by the FERC that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund proponents appealed these procedural orders at the Ninth Circuit. On December 17, 2015, the Ninth Circuit held that the FERC reasonably applied the Mobile-Sierra presumption to the class of contracts at issue in the proceedings and dismissed evidentiary challenges related to the scope of the proceeding.

Plaintiffs on behalf of the California Energy Resources Scheduling division of the California Department of Water Resources filed a request for rehearing on February 1, 2016. By order issued April 18, 2016, the Ninth Circuit denied plaintiffs’ request for panel rehearing of its decision regarding application of the Mobile-Sierra presumption.

In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order finding that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. In December 2015, the FERC denied all requests for rehearing of its order. With respect to the remaining respondent, FERC ordered additional proceedings, and, in an order issued October 18, 2016, rejected the Plaintiffs’ request for refunds from the respondent, finding that the Plaintiffs had not met their Mobile-Sierra burden of proof.

The Company has settled all of the direct claims asserted against it in the proceedings for an immaterial amount. The settlements and associated FERC orders did not fully eliminate the potential for so-called “ripple claims,Data,” which have been described by the FERC as “sequential claims against a succession of sellers in a chain of purchases that are triggered if the last wholesale purchaser in the chain is entitled to a refund.” As a result of the FERC orders to date, there are only two sellers from whom ripple claims could arise if those orders are overturned on appeal. Both of these sellers have now authorized on-the-record representations that they would not pursue ripple claims if they were required to pay refunds. As a result, the Company does not believe that it will incur any material loss in connection with this matter.



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Portland General Electric Company v. Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon.

In 2013, the Company entered into an agreement (Construction Agreement) with its engineering, procurement and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of Carty. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

On December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. On January 28, 2016, the Company received notice from the International Chamber of Commerce International Court of Arbitration that Abengoa S.A. had submitted a request for arbitration. In the request, Abengoa S.A. alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to any liability of Abengoa S.A. under the terms of a guaranty in favor of PGE and pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. Abengoa S.A. is also seeking to implead the Contractor into this arbitration. PGE disagrees with the assertions in the request for arbitration and, on February 29, 2016, filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration.

On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries, including the four entities that collectively comprise the Contractor, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the Company’s District Court action against Abengoa S.A. was stayed. In June 2016, the Company filed with the bankruptcy court in the Chapter 11 proceeding a motion for relief from stay with respect to the four entities that collectively comprise the Contractor, which allows the Company to bring claims against such entities in the U.S. District Court. On October 21, 2016, PGE filed a complaint in the U.S. District Court for the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. For further information regarding this complaint, see “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,” below.

On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:

1.that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and

2.that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the foregoing assertions and on March 23, 2016 filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. 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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On April 15, 2016, the Sureties filed a motion to stay this U.S. District Court proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A., and referenced above, because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE opposed the motion and filed a motion to enjoin the Sureties from pursuing, in the ICC arbitration proceeding, claims relating to the Performance Bond.

On July 27, 2016, the judge denied the Sureties’ motion to stay the case in favor of a pending ICC Arbitration and granted PGE’s motion for an injunction prohibiting the Sureties from pursuing any Performance Bond claims in the ICC Arbitration. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals. On December 13, 2016, the Ninth Circuit issued an Order staying the district court proceeding pending a decision on the Sureties’ appeal. Oral argument on the Sureties’ appeal is scheduled for May 2017.

For additional information on this matter, see Note 17, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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.

On October 21, 2016, PGE filed a complaint in the U.S. District Court of the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa 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. For additional information on this matter, see Note 17, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

proceedings.

ITEM 4.     MINE SAFETY DISCLOSURES.

Not applicable.

PART II

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

PGE’s common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol “POR”. As of February 3, 2017, there were 800holders of record of PGE’s common stock and the closing sales price of PGE’s common stock on that date was $43.55per 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.

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  High Low 
Dividends
Declared
Per Share
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
2015      
Fourth Quarter $39.08
 $34.97
 $0.30
Third Quarter 38.00
 33.09
 0.30
Second Quarter 37.69
 33.04
 0.30
First Quarter 41.04
 34.72
 0.28
While PGE expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

ITEM 6.     SELECTED FINANCIAL DATA.

The following consolidated selected financial data should be read in conjunction with Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8.—“Financial Statements and Supplementary Data.”
 Years Ended December 31,
 2018 2017 2016 2015 2014
 (In millions, except per share amounts)
Statement of Income Data:         
Total revenues$1,991
 $2,009
 $1,923
 $1,898
 $1,900
Income from operations*346
 380
 340
 318
 303
Net income212
 187
 193
 172
 174
Net income attributable to Portland General Electric Company212
 187
 193
 172
 175
Earnings per share—basic2.38
 2.10
 2.17
 2.05
 2.24
Earnings per share—diluted2.37
 2.10
 2.16
 2.04
 2.18
Dividends declared per common share1.4275
 1.340
 1.260
 1.180
 1.115
Statement of Cash Flows Data:         
Capital expenditures595
 514
 584
 598
 1,007
*
The years ended December 31, 2014 and 2015 include a $10 million and $9 million reclassification of the non-service cost component of net periodic pension and postretirement benefit costs, respectively, as such costs are no longer considered in the subtotal of Income from operations pursuant to the adoption of ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. For information regarding this matter, see “Recently Adopted Accounting Pronouncements” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

 Years Ended December 31,
 2016 2015 2014 2013 2012
 (In millions, except per share amounts)
Statement of Income Data:         
Revenues, net$1,923
 $1,898
 $1,900
 $1,810
 $1,805
Gross margin68% 65% 62% 58% 60%
Income from operations*$333
 $309
 $293
 $206
 $302
Net income*193
 172
 174
 104
 140
Net income attributable to Portland General Electric Company*193
 172
 175
 105
 141
Earnings per share—basic*2.17
 2.05
 2.24
 1.36
 1.87
Earnings per share—diluted*2.16
 2.04
 2.18
 1.35
 1.87
Dividends declared per common share1.260
 1.180
 1.115
 1.095
 1.075
Statement of Cash Flows Data:         
Capital expenditures584
 598
 1,007
 656
 303
 As of December 31,
 2018 2017 2016 2015 2014
 (Dollars in millions)
Balance Sheet Data:         
Total assets$8,110
 $7,838
 $7,527
 $7,210
 $7,030
Total long-term debt2,478
 2,426
 2,350
 2,193
 2,489
Total capital lease obligations49
 51
 54
 —
 —
Total shareholders’ equity2,506
 2,416
 2,344
 2,258
 1,911
Common equity ratio49.8% 49.4% 49.4% 50.7% 43.4%
     
* The year ended December 31, 2013 includes $52 million of costs expensed related to the Company’s Cascade Crossing Transmission Project, which was originally proposed as a 215-mile, 500 kV transmission project.

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 As of December 31,
 2016 2015 2014 2013 2012
 (Dollars in millions)
Balance Sheet Data:         
Total assets*
$7,527
 $7,210
 $7,030
 $6,090
 $5,661
Total long-term debt*
2,350
 2,193
 2,489
 1,905
 1,627
Total capital lease obligations54
 —
 —
 —
 —
Total Portland General Electric Company shareholders’ equity2,344
 2,258
 1,911
 1,819
 1,728
Common equity ratio*
49.4% 50.7% 43.4% 48.9% 51.3%
* Total assets, total long-term debt, and common equity ratios have been adjusted to reflect the retrospective adoption of ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30) for the years ended December 31, 2015 through December 31, 2012. For more information, see “Recently Adopted Accounting Pronouncements” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


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.

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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 not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished.

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

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the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 17,18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;
unseasonable or extreme weather and other natural phenomena, which could affect customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;
operational factors affecting PGE’s power generating facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;
the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
volatility in wholesale power and natural gas prices, which could require PGE to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to power and natural gas purchase agreements;
changes in the availability and price of wholesale power and fuels, including natural gas coal, and oil,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;

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changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE’s service territory;
the effectiveness of PGE’s risk management policies and procedures;
declines in the fair value of securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;
cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and a significant number of employees approaching retirement;
new federal, state, and local laws that could have adverse effects on operating results;
political and economic conditions;
natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;
changes in financial or regulatory accounting principles or policies imposed by governing bodies; and
acts of war or terrorism.


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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.

Overview

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

PGE’s mission is to provide an accessible, affordable clean energy future to customers in all of the communities it serves, responding proactively to an evolving landscape of customer expectations, technology changes, and regulatory frameworks by focusing efforts on four strategic initiatives: i) delivering exceptional customer service; ii) investing in a reliable and clean energy future; iii) building a smarter, more resilient grid; and iv) pursuing excellence in its work.

By choosing renewable sources, like solar, wind, and water, PGE filed its 2016can supply power without creating carbon emissions. As the largest electric utility in Oregon, bringing customers renewable power is one of PGE’s most important objectives. Delivering exceptional customer service requires PGE to be responsive to the changing expectations of an evolving 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 OPUC in mid- November 2016.local economy. The areasCompany is also working to advance transportation electrification, with projects to expand and increase access to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of focus forelectric vehicles.

Reducing carbon emissions also involves using less energy. PGE helps customers make smart choices by using energy efficient appliances, lights, thermostats and more.

Building a smarter, more resilient grid is essential to affordably delivering the 2016 IRP include, among other topics, acquisition of additional resourcesclean energy future that may be needed in order to meet RPS requirements and to replace energy and capacity from Boardman, which is scheduled to cease coal-fired operations at the end of 2020. For further information oncustomers want. This requires embracing new technologies, modernizing the Company’s 2016 IRP, see “Integrated Resource Plan” in the Regulation section of Item 1.—“Business.”existing infrastructure, and

During 2016, PGE committed to join the western EIM with a target participation date in the fall
32
Table of 2017. The EIM is a real-time energy wholesale market that automatically dispatches the lowest-cost electricity resources, while optimizing use of renewable energy over a large geographic area. For further information on the Company’s participation in the EIM, see “Future Energy Resource Strategy” in the Power Supply section of Item 1.—“Business.”Contents


Theimplementing a new customer information system to create a foundation to integrate emerging technologies. PGE’s capital requirements contemplate the impact of making investments in new, renewable resource generation and energy storage facilities, as well as improvements to its transmission, distribution, and information technology infrastructure.

In 2007, the Oregon State Legislature set a goal to achieve GHG levels that are at least 75 percent below 1990 levels by 2050. Recent GHG policy proposals suggest a new goal of Oregon passed Senate Bill 1547, effective March 8, 2016, a law referred to as the Oregonat least 80 percent below 1990 levels by 2050. Additionally, Oregon’s Clean Electricity and Coal Transition Plan, (OCEP). The legislation prevents large utilitiesenacted in 2016, set a benchmark for how much electricity must come from renewable sources like wind and solar (50 percent by 2040) and requires the elimination of coal from Oregon utility customers’ energy supply by 2035. Local governments are also enacting clean energy policy goals.

In June 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, including the costscities of Milwaukie and benefits associated with coal-fired generation in their Oregon retail rates after 2030, with certain exceptions, and increasesHillsboro, are considering similar goals. These commitments reflect the RPS percentages in future years. For further information on the OCEP, see “Legal, Regulatory and Environmental” in this Overview section of Item 7.values held by customers.

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.

CartyIntegrated Resource Plans—On July 29,PGE’s 2016 Carty, a natural gas-fired baseload resource in Eastern Oregon, was placed into service. AsIRP addressed acquisition of December 31,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 help integrate variable energy resources, such as wind or solar resources. The 2016 PGE had $634 million in Electric utility plant in service related to Carty. IRP is available on PGE’s website.

The Company currently estimates that2016 IRP also considered the total capital expenditureseffects of SB 1547, which, among other things, increased the RPS requirements for Carty will be approximately $640 million. This cost estimate does not reflect any amounts that may be received from2025 and future years. For further information on SB 1547, see the Sureties pursuant to“Legal, Regulatory, and Environmental” section of the Performance Bond or from the Contractor or Abengoa S.A. This estimate also excludes approximately $17 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor. The Company believes these liens are invalid and is contesting the claims in the courts. For additional details regarding various legal proceedings related to Carty, see Note 17, Contingencies, in the Notes to the Consolidated Financial StatementsOverview section in Item 8.7.— “Financial Statements“Management’s Discussion and Supplementary Data.Analysis of Financial Condition and Results of Operations.”

In August 2017, the OPUC acknowledged PGE’s 2016 IRP, an action that allowed the Company to, among other things, finalize agreements to purchase additional annual and seasonal capacity as well as pursue renewable energy and energy storage as described in the paragraphs that follow.

Renewable Energy—The final orderOPUC, 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 November 2017, PGE submitted to the OPUC an addendum to the 2016 IRP that included a request for the issuance of an RFP for RPS compliant renewable resources.

In December 2017, the OPUC acknowledged the addendum and, as a result, in May 2018, the Company issued the RFP seeking to procure approximately 100 MWa of qualifying renewable resources.

With the oversight by an independent evaluator selected by the OPUC on November 3, 2015to help conduct the RFP and review bids to ensure a fair and transparent process, the Company determined a Final Shortlist of proposals. PGE submitted a benchmark project into the RFP process that included a wind resource that would qualify for federal production tax credits. The benchmark project was considered along with other renewable resource proposals and was among the bids included in connectionthe Final Shortlist.

The proposals provided various combinations of wind, solar, and battery storage options that included power purchase agreements (PPAs) along with up to 100 MW of Company-owned wind resources. The OPUC acknowledged the RFP Final Shortlist and PGE immediately commenced negotiations with the Company’s 2016 General Rate Case authorized the inclusion in customer prices of capital costs for Carty of up to $514 million, as well as Carty’sbidders.


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operatingAs a result of those negotiations, PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. have announced plans to construct a new energy facility in eastern Oregon combining 300 megawatts (MW) of wind generation with 50 MW of solar generation and 30 MW of battery storage.

The new project, called the Wheatridge Renewable Energy Facility, will consist of 120 wind turbines manufactured by GE Renewable Energy, Inc. PGE will own 100 MW of the wind resource with an investment of approximately $160million. Subsidiaries of NextEra Energy Resources, LLC plan to build and operate the facility and will own the balance of wind resource, along with the solar and battery components, and sell their portion of the output to PGE under 30-year PPAs.

The wind component of the facility is expected to be operational by December 2020 and qualify for federal production tax credits at the 100 percent level. Construction of the solar and battery components is planned for 2021 and is expected to qualify for federal investment tax credits. Any tax credits will help reduce the cost of the project and thus reduce costs to PGE’s customers.

The agreements signed by PGE and subsidiaries of NextEra Energy Resources, LLC will be subject to prudency review on customers’ behalf by the OPUC. The agreements are also subject to approval by senior management of NextEra Energy, Inc., which is anticipated in March 2019.

Additional information regarding the RFP (OPUC Docket UM 1934) is available on the OPUC website at such timewww.oregon.gov/puc.

Energy Storage—Pursuant to OPUC acknowledgment of the 2016 IRP, PGE filed an energy storage proposal in November 2017 with the OPUC. The proposal 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 plant was placed into service, provided that occurreddevelopment of five energy storage projects by July 31, 2016. As Carty was placedPGE with an expected capital cost of approximately $45 million.

IRP Update—In March 2018, PGE filed an update to its 2016 IRP with the OPUC. The OPUC acknowledged the IRP Update at its April 24, 2018 meeting, and, as a result, PGE included the resource and financial parameters in service on July 29,its May 1, 2018 annual avoided cost update filing.

Since 2016, the Company was authorizedhas experienced significant growth in contract requests from QFs, which, when and if brought to includecompletion, may offset a portion of the capacity currently provided by Boardman. Reliance on QF requests to provide future capacity introduces risk to the Company in its planning process, as the QFs may never come on line, which ultimately influences the amount of capacity and renewables PGE may actually need to procure.

PGE continues to see a trend in which QF contracts are executed and subsequently packaged and sold to large, sophisticated multi-national developers in an effort to take advantage of contract rates that are significantly higher than current market rates. PGE continues to work with the OPUC and stakeholders to evaluate Oregon’s implementation of the QF contracting process to promote alignment with RPS targets and decarbonization policy and to ensure customers receive reasonably-priced and reliable renewable energy, while continuing to comply with legal requirements.

As part of the IRP Update filing, PGE’s capacity need has been updated to reflect the recently executed bilateral capacity contracts, changes to load forecast, and additional executed QF contracts. The Company expects that the anticipated procurement of resources through the Renewable RFP and energy storage will contribute to meeting the forecasted need identified in the 2016 IRP.


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2019 IRP—In preparation for its 2019 IRP, PGE conducted an informal public process throughout the past year. The Company has presented multiple enabling studies to support the 2019 IRP, including a:
Decarbonization Study evaluating the potential impacts of reducing economy-wide GHG emissions in the PGE service area by 80% by 2050;
Market Capacity Study evaluating the potential for shifting regional loads and resources to impact the availability of market capacity in the Pacific Northwest over time;
Distributed Resource and Flexible Load Study, which provided a holistic view of potential Distributed Energy Resource adoption, electric vehicle adoption, and demand response and flexible load program participation among PGE customers; and
Supply-Side Option Study that provided costs and performance characteristics for supply-side renewables, storage, and thermal resources.

PGE is using the results of the studies and continuing to engage stakeholders in the informal public process to shape the 2019 IRP along with a proposed action plan, which the Company expects to file with the OPUC in the summer of 2019.

General Rate Cases—On February 15, 2018, PGE filed with the OPUC a general rate case based on a 2019 test year (2019 GRC). 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.

On December 14, 2018, the OPUC issued an order (Order) that, when combined with customer credits and the effects of tax reform, would result in an overall annual increase in PGE’s annual revenues of $9 million, resulting in a 0.5% increase in customer prices, to become effective AugustJanuary 1, 2016, its revenue requirement necessary2019. In addition, the Order approved a capital structure of 50% debt and 50% equity, a return on equity of 9.50%, a cost of capital of 7.30%; and rate base of $4.75 billion. The Order provided for the use of a trended weather input assumption to allowreflect normal conditions in the load forecasting models, which the Company sought, although it did not grant the request for full volumetric decoupling that would include the effects of weather, nor the changes to the storm recovery mechanism.    

Primary elements of the 2019 GRC include cost recovery for:

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.

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 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 costsstructure of up50% 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 TCJA was enacted into law with substantially all of the provisions of the TCJA having an effective date of January 1, 2018. The most significant change to $514PGE’s financial condition was the federal corporate tax rate decrease from 35% to 21%.


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As a result of the change in corporate tax rate, PGE expected to incur lower income tax expense throughout 2018 than what was estimated in setting customer prices in the Company’s 2018 GRC. PGE proposed in a filing with the OPUC on December 29, 2017, to track and defer tax savings as a result of the TCJA and work with the OPUC to determine strategies to provide customers the appropriate benefit.

On December 4, 2018, PGE received OPUC approval to refund a total of $45 million to customers for the 2017-2018 net benefits associated with the constructionTCJA. The refund began amortizing in customer prices on January 1, 2019 over two years. The refund settlement amount was recorded as a reduction to Revenues, net in the consolidated statements of Carty, as well as operating costs. The price change consistedincome.

In 2018, PGE, and other individual public utilities received a show cause order from the FERC to justify why the Company’s current transmission rates have remained just and reasonable in light of an $85 million annualized increase related to cost recoverythe TCJA and its reduction of Carty and a $41 million annualized decrease ($17 million over the remainder of 2016) relatedcorporate taxes. PGE responded to the amortizationshow cause order and asked FERC to hold in abeyance their show cause proceeding pending PGE’s analysis of certain customer credits through supplemental tariffs. As actual project costs for Carty have exceeded $514 million,its transmission rates, which the Company has incurredpledged to complete after the finalization of its FERC Form 1 filing. The FERC granted PGE’s request for a higher cost of service than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation and interest expense.

On July 29, 2016, the Company also 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, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Incremental expenses related to Carty, primarily due to depreciation and amortization, were $3 million for the year ended December 31, 2016 and are estimated to be $6 million in 2017. Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval.stay.

Capital Requirements and Financing—PGE’s capital requirements amounted to $596$606 million for 2016,2018, with $190$26 million related to the construction of Carty,customer information system, excluding AFDC. The remainder of the 20162018 capital requirements related to a non-utility capital purchase of PGE’s corporate headquarters, 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. During 20162018, thePGE funded its capital requirements through a combination of cash from operations in the amount of $553$630 million, the $130 million cash proceeds from the settlement of the Carty matter, and proceeds from issuancesthe issuance of FMBs and unsecured term loans in the amount of $290$75 million. Due to the upcoming repayment of long-term debt in 2019, $300 million fundedwas classified as current on the Company’s capital requirements.consolidated balance sheets as of December 31, 2018.

Capital requirements in 20172019 are expected to approximatebe $610580 million. PGE plans to fund the 20172019 capital requirements and current maturities of long-term debt of $150 million with cash from operations during 2017,2019, which is expected to range from $450$550 million to $500$600 million, and the issuance of debt securities of approximately $450 million. These amounts do not includeup to$375 million, and the issuance of commercial paper, as needed. The actual timing and amount of any estimated proceeds toother issuances of debt or commercial paper will be received fromdependent upon the Sureties pursuant to the performance bond, which cannot be reasonably estimated at this time.timing and amount of capital expenditures. For further information, see the “Liquidity” and the “Debt and Equity Financings” sections of this Item 7.

General Rate Cases—PGE plans to file a 2018 GRC with the OPUC by the end of February 2017 that will be based on a 2018 test year and include investments to ensure system safety and reliability and better meet customers’ changing needs and service expectations. Regulatory review of the 2018 GRC is expected to occur throughout 2017, with new customer prices effective in January 2018.

In February 2015, PGE filed with the OPUC a 2016 GRC, which was based on a 2016 test year and included costs related to Carty. In November 2015, the OPUC issued an order in the Company’s 2016 GRC, intended primarily to allow recovery of costs associated with the construction and operation of Carty. The annual revenue requirement change was implemented in two phases, with the first, a decrease, effective January 1, 2016 consisting of a reduction in base business costs and a decrease related to the amortization and recognition of certain customer credits through supplemental tariffs. The second phase was a price increase, consisting of the combination of an increase related to the cost recovery of Carty and a decrease related to the amortization of certain customer credits through supplemental tariffs, effective when Carty was placed into service. For further discussion on Carty, see “Carty” in this Overview section of Item 7.

The 2016 GRC filing, as well as copies of the orders, direct testimony, exhibits, and stipulations are available on the OPUC website at www.oregon.gov/puc.

Operating Activities—PGE, isas a vertically integratedvertically-integrated electric utility, engagedengages in the generation, transmission, distribution, and retail sale of electricity as well asto retail customers within in its approved service territory in the State of Oregon. In addition, the Company purchases and sells electricity in the wholesale purchasemarket to meet its retail load requirements and salebalance its energy supply with customer demand. In 2017, the Company began participation in the California Independent System Operator’s Energy Imbalance Market (western EIM), which allows the Company to integrate more renewable energy into the grid by better matching the variable output of electricity andrenewable resources. PGE also purchases wholesale natural gas in the United States and Canada to meetfuel its retail load requirements.generating portfolio and sells excess gas back into the wholesale market. The Company generates revenues and cash flows primarily from the retail sale and distribution of electricity to customers in its service territory in the State of Oregon.retail customers.

The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has been a winter-peaking utility that typically experiences its highest retail energy demand during the winter heating season, although increasedseason. Increased use of air conditioning in the Company’s service territoryterritory; however, has caused the summer peaks to increase in recent years and the long-term load forecasts showindicate summer peaks exceedingwill 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 effectimpact on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations.


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Customers and Demand—In 2016,2018, retail energy deliveries decreased 2.1%2.5% from 2015,2017. Residential customer deliveries which was driven by decreasesare most sensitive to fluctuations in industrialweather, and commercial energycustomer deliveries partially offset by an increase in residential energy deliveries.contributed to the decrease, while the industrial customer deliveries increased. For 20162018 and 2015,2017, the average number of retail customers and deliveries, by customer type, were as follows:

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2016 2015 
Increase/
(Decrease)
in Energy
Deliveries
2018 2017 
Increase/
(Decrease)
in Energy
Deliveries
Average
Number of
Customers
 
Energy
Deliveries *
 
Average
Number of
Customers
 
Energy
Deliveries *
 
Average
Number of
Customers
 
Energy
Deliveries *
 
Average
Number of
Customers
 
Energy
Deliveries *
 
Residential752,365
 7,348
 742,467
 7,325
 0.3 %772,389
 7,416
 762,211
 7,880
 (5.9)%
                  
Commercial (PGE sales only)106,460
 6,932
 105,472
 7,002
 (1.0)%108,570
 6,783
 107,364
 6,932
 (2.2)%
Direct Access313
 525
 330
 509
 3.1 %537
 647
 491
 623
 3.9 %
Total Commercial106,773
 7,457
 105,802
 7,511
 (0.7)%109,107
 7,430
 107,855
 7,555
 (1.7)%
                  
Industrial (PGE sales only)195
 2,968
 199
 3,369
 (11.9)%203
 2,987
 199
 2,943
 1.5 %
Direct Access63
 1,198
 61
 1,177
 1.8 %67
 1,389
 68
 1,340
 3.7 %
Total Industrial258
 4,166
 255
 4,546
 (8.4)%270
 4,376
 267
 4,283
 2.2 %
                  
Total (PGE sales only)859,020
 17,248
 848,138
 17,696
 (2.5)%881,162
 17,186
 869,774
 17,755
 (3.2)%
Total Direct Access376
 1,723
 391
 1,686
 2.2 %604
 2,036
 559
 1,963
 3.7 %
Total859,396
 18,971
 848,524
 19,382
 (2.1)%881,766
 19,222
 870,333
 19,718
 (2.5)%
     
 *In thousands of MWh.

In late 2015, a large paper manufacturing customer, to which PGE has delivered approximately 450 thousand MWhs annually, with corresponding revenues2018, heating degree-days, an indication of approximately $20 million, ceased operations.electricity use for heating, were 10% below the 15-year average and 19% lower than 2017. 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. The Company’s 2016 GRC took into consideration the loss of this customer load and incorporated it into prices and load forecasts for 2016 and, as a result, minimal earnings impact occurred. After adjusting for the loss of this large customer, industrial energy deliveries increased by 1.4% and total energy deliveries increased by 0.1% in 2016. The increase in industrial energy deliveries developed as increased energy deliveries to the high tech manufacturing sector were partially offset by decreased energy deliveries to the metals and transportation equipment manufacturing sectors.

The increase in demand from residential customers is largely attributable to strong customer growth of 1.3% for 2016 relative to 2015. The increase is largely offset by a decrease of 1.0% in residential use per customer which is driven, primarily, by unfavorable year over year weather conditions. Both 2015 and 2016 experienced unusually warm temperatures during the winter heating season, reducing residential energy deliveries, however 2016 did not experience the offsetting warm temperatures during the cooling season that were experienced in 2015.

The full year 2015 was the warmest year on record for the State of Oregon. During the summer months, the generally warmer weather increased residential energy deliveries slightly due to cooling demand, but only partially offset the decline in energy deliveries that resulted during the heating season. Total heating degree-days in 2016 (anthe first quarter of 2017 were unusually high, heating degree days each quarter of 2018 were below those of the comparable quarter of 2017. Cooling degree-days, a similar indication of the extent to which customers are likely to use, or have used electricity for heating)cooling, although just 1% below the 2017 level, were 16% lower than35% above the 15-year moving average.

Residential energy deliveries were 5.9% lower in 2018 than 2017 due largely to the effects of warmer temperatures during the winter season and a continued trend of lower use per customer, despite residential average although 3% above total heating degree-days in 2015. For further detail on heating and cooling degree-days, seecustomer growth of 1.3%. See “Revenues”in the 20162018 Compared to 20152017 section of Results of Operations inwithin this Item 7. Lower commercial7, for further information on heating and cooling degree days.

Commercial deliveries despitealso decreased by 1.7% largely as a 0.9% growth in the average numberresult of customers, reflects unfavorableless favorable weather conditions, and slightly lower demand from a few groups,conditions. Deliveries to several retail sectors decreased, including food and merchandise stores which were impacted by a series of mergers and bankruptcies, government and education, and irrigation customers 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.health care, while other service sectors, including data centers, showed growth. Energy efficiency programs and efforts continues to impact growth and conservation and building codes and standards are likely reducing energy deliveries beyond the impact of energy efficiency programs.deliveries.

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TableThe 2.2% increase in industrial energy deliveries is due to continued increases in energy deliveries to the high-tech manufacturing sector. This increase resulted even though the Company experienced the closure of Contentsa large paper customer in October 2017, which reduced comparative deliveries in 2018.

On a weather-adjusted basis, total retail deliveries increased 0.4% from 2017 reflecting a 0.2% increase in residential deliveries, as growth in average number of customers was mostly offset by a decline in the average usage per customer, a decline of 0.4% in commercial deliveries and a 2.4% increase in industrial deliveries driven primarily by strength in the high-tech manufacturing sector.

ESSs supplied Direct Access customers with energy representing 11% of the Company’s total retail energy deliveries during 2018 and 10% for 2017. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 14% of the Company’s total retail energy deliveries for 2018, and 13% in 2017.

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 withthrough the decoupling mechanism,

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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 weather adjustedweather-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 2016,In 2018, PGE recorded an estimated collection of $3$2 million under the mechanism as weather adjustedweather-adjusted energy use per customer was less than that estimated and approved in the Company’s 20162018 GRC. A final determination of the 2016 estimate2018 amount will be made by the OPUC through a public filing and review in 2017.2019. Any resulting collection from customers is expected to begin January 1, 2018.2020. The $9$11 million estimated refund forcollection deferred in the 20152017 year was submitted to the OPUC for review during 2016. The resulting refund to customers began January 1, 2017.2019. For 2014,2016, amortization of the net $5$3 million refundcollection amount beganoccurred in January 20162018 following a final determination of the amount through a public filing and review by the OPUC during 2015.OPUC.

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

Plant availability is impacted by planned maintenance and forced, or unplanned, outages, during which the respective plant is unavailable to provide power. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year. Availability of all the plants PGE operates approximated 93%, 93%, and 92% for the yearsyear ended December 31, 2018, 90% for 2017, and 93% for 2016,2015, and 2014, respectively, with the availability of Colstrip, which PGE does not operate, approximating 85%82%, 93%86%, and 83%85% for the years ended December 31, 2018, 2017, and 2016, respectively.

During the year ended December 31, 20162018, the Company’s generating plants provided approximately 70%76% of its retail load requirement compared to 65%69% in 20152017 and 58%70% in 20142016. Through the addition of Carty in July 2016, and Tucannon River and PW2 in late 2014, PGE has the ability to economically generate a greater portion of its total system load and reduce reliance on higher-cost purchased power.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increaseddecreased 5%10% in 20162018 compared to 20152017, primarily due to moreless favorable hydro conditions in 20162018. These resources provided 17% of the Company’s retail load requirement for 20162018, compared with 16% for 2015 and 18% for 20142017 and 17% for 2016. Energy received from these sources fell below projected levels included in PGE’s AUT by 4% in 2018, exceeded projected levels included in the Company’s AUT by 6% in 2017, and did not materially differ from the projections (or “normal”) included in the Company’s AUT in 2016, fell short of projections by 7% in 2015, and exceeded projections by 2% in 20142016. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year. “Normal” representsNormal 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 year30-year period. Any shortfall is generally replaced with power from higher cost sources, while any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources. See “Purchased power and fuel” in the 20162018 Compared to 20152017 section of Results of Operations in this Item 7.7, for further detail on regional hydro forecasts.results.

Energy expected to be received from wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT based on historical generation. Any excess in wind generation from that projected in the AUT generally displaces power from higher-cost sources, while any shortfall is generally replaced with power from higher-cost sources. Energy received from wind generating resources fell short of that projected in PGE’s AUT by 5% in 2018, 18% in 2017, and 7% in 2016, 15% in 2015 and 9% in 2014. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation shortfalls, production tax credits have not materialized to the extent contemplated in the Company’s prices.

Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Subject to a regulated earnings test, 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
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Pursuant to the Company’s PCAM, customer prices can be adjusted to reflectexceed a portion of the difference between each year’s forecasted NVPC included in customer prices (baseline NVPC), as established under the AUT, and actual NVPC for the year, to the extent such difference is outside of a pre-determined “deadband,”prescribed “deadband” limit, which ranges from $15$15 million below to $30$30 million above baseline NVPC. To the extent actual NVPC is above or below the deadband, the PCAM provides for 90% of the variance beyond the deadband to be collected from or refunded to 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 20162018, 20152017, and 20142016:

For 2016,2018, actual NVPC was below baseline NVPC by $10$3 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 20162018. A final determination regarding the 20162018 PCAM results will be made by the OPUC through a public filing and review in 2017.2019.

For 20152017, 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 was made by the OPUC through a public filing and review in 2018, which confirmed no collection from customers pursuant to the PCAM for 2017.

For 2016, actual NVPC was below baseline NVPC by $310 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2015.2016. A final determination regarding the 20152016 PCAM results was made by the OPUC through a public filing and review in 20162017, which confirmed no refund to customers pursuant to the PCAM for 2015.2016.

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 western 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 Gas Storage2014, actual NVPC was below baseline NVPC—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 $7a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the construction of a new reservoir, compressor station, and 13-miles of pipeline, which will collectively be designed to provide no-notice storage services to these PGE generating plants. NW Natural estimates construction will be completed in the spring of 2019, at a cost of approximately $144 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 $131 million, which was within to construction work-in-progress (CWIP) and a corresponding liability for the established deadband range. Accordingly, no estimated refundsame amount to customers was recordedOther noncurrent liabilities in the consolidated balance sheets as of December 31, 2014. A final determination regarding the 2014 PCAM results was made by the OPUC through a public filing2018. See Note 2, Summary of Significant Accounting Policies in Item 8. - “Financial Statements and review in 2015, which confirmed no refund to customers pursuant to the PCAMSupplementary Data” for 2014.

For further information concerning the PCAM, see Power Costs under “OPUC and Other Statelease considerations of Oregon Regulation” in the Regulation section of Item 1.—“Business.”this agreement.

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:

Anthe ongoing environmental investigation of environmental matters regarding Portland Harbor; and
Claims pertaining to the termination of the Construction Agreement for Carty and recovery of incremental costs.

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

Clean Power Plan—In August 2015, the EPA released a final rule,the CPP, under which it calls the “Clean Power Plan.” Under the final rule, each state would have to reduce the carbon intensity of its power sector on a state-wide basis by an amounta specified by the EPA. The rule established state-specific goals and is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030. Onamount. In February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the Clean Power PlanCPP, pending the resolution of legal challenges to the rule. For additional information regarding this newIn October 2017, the EPA published a proposed rule see “Air Quality” in which it outlined a rationale for repealing the Environmental Matters section of Item 1.—“Business.”CPP. The public comment period for the repeal rule closed April 26, 2018.

Oregon Clean ElectricityOn August 21, 2018, the EPA proposed the ACE rule, which would replace the CPP and Coal Transition Planestablish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. The

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public comment period on the proposed ACE rule closed on October 31, 2018. The EPA has yet to finalize either rulemaking.

The Company continues to monitor the developments around the CPP legal challenges and the potential new rule. The Company cannot predict the ultimate outcome of the legal challenges and the regulatory process of the EPA, or whether the states in which the Company’s thermal generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations.

Senate Bill 1547—The State of Oregon passed, Senate Bill 1547, effective in March 8, 2016, a law referred to as the OCEP.Oregon Clean Electricity and Coal TransitionPlan (SB 1547). The legislation prevents large utilitieswill impact PGE in several ways, one of which is to prevent the Company from including the costs and benefits associated with coal-fired generation in theirits Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for PGE’s output from Colstrip). As a result, in October 2016, the Company filed a tariff request, which the OPUC approved, to incorporate in customer prices, on January 1, 2017, the approximate $6 million annual effect of accelerating recovery of PGE’s investment in Colstrip facility), increasesfrom 2042 to 2030, as required under the RPS percentages in certain future years, changes the life of certain RECs, requires the development of community solar programs, seeks the development of transportation electrification programs, and requires that a portion of electricity come from small scale renewable or certain biomass projects.legislation.

UnderOther future effects under the new law PGE will be required to:include:

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fully depreciate its portion of the Colstrip facility by 2030, with the potential to utilize the output of the facility,An increase in Oregon, until 2035;
meet RPS thresholds ofto 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
limitA limitation on the life of RECs generated from facilities that become operational after 2022 to five years, but maintain thecontinued unlimited lifespan offor all existing RECs and allowallowance for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022;
include projected PTCs in prices through any variable power cost forecasting process established by the OPUC, the first of which applied to the AUT filing for 2017; and
includeAn allowance for energy storage costs related to renewable energy in itsthe Company’s RAC filings.

The Company has evaluated the potential impacts and incorporated the effects of the legislation into its 2016 IRP, which was filed with the OPUC in mid- November 2016.

In October 2016, the Company filed a tariff request with the OPUC seeking approval to incorporate in customer prices on January 1, 2017 the estimated annual $6 million effect of accelerating recovery of the Colstrip facility from 2042 to 2030, as required under the legislation. The OPUC approved the tariff request.IRP.

Ballot Measure 97Oregon Legislative Initiatives—The State of Oregon hadlegislators proposed Senate Bill 1070, which was referred to as the Clean Energy Jobs Bill, during the abbreviated 35-day legislative session in 2018, in an effort to reduce greenhouse gas emissions that contribute to climate change through a citizens’ initiative, Measure 97, on the November 2016 ballot thatstatewide cap and trade program. Although such legislation did not pass. Ifemerge from the 2018 legislative session, a new, similar proposal called the Oregon Climate Action Program, House Bill 2020, was introduced in 2019 legislative session that began in January 2019. As initially proposed, the legislation would, among other things:
Modify statewide greenhouse gas emissions reduction goals;
Require a program to place a cap on greenhouse gas emissions and provide a market-based mechanism for covered entities to demonstrate compliance with program; and
Authorize the OPUC to allow recovery in customer prices to reflect amounts for programs that enable public utilities to assist low-income residential customers.

The Company is monitoring developments around this proposal that could emerge from the full length 2019 legislative session.

Senate Bill 978—The State of Oregon legislature passed a bill in its 2017 session referred to as SB 978, which directed the OPUC to investigate and provide a report to the legislature on how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. PGE actively worked on this initiative with both external stakeholders and the OPUC, to provide guidance and support for the report. The OPUC issued the final report to the legislature on September 14, 2018 in which the OPUC committed to four focus areas:
Exploring performance-based ratemaking and other regulatory tools to align utility incentives with customer goals, industry trends, and statewide goals;
▪Cooperating with other states to support and explore development of an organized regional market;

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▪Developing a strategy for low income and environmental justice groups’ engagement and inclusion in OPUC processes that will carry forward beyond the SB 978 proceeding; and
▪Improving the Commission’s regulatory tools to value system costs and benefits, which enables customer choice and a strong utility system.

The OPUC also stated that it would have imposedcollaborate with the legislature and stakeholders to make progress on climate change, noting that their authority is limited to that of an economic regulator. The legislature may address the limitation identified by the OPUC for direct authority to address climate change through expected comprehensive cap and trade legislation during the 2019 legislative session.

Green Tariff—The Company continues to pursue OPUC approval of a minimum taxproposed green tariff program that would allow business customers to access bundled renewable energy from new resources. Through this proposed tariff, submitted to the OPUC in early 2018, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system. PGE proposes to avoid stranded costs and cost shifting by having subscribers continue under the Company’s existing cost of 2.5% on Oregon gross receipts on businessesservice tariff, with annual Oregon salesthe green tariff added, and procuring competitive, renewable energy through the use of power purchase agreements or additional renewable generation. PGE expects an OPUC decision in excess of $25 million.early 2019.

Other Regulatory Matters—The following discussion highlights certain regulatory items whichthat have impacted or are expected to impact, the Company’s revenues, results of operations, or cash flows.flows for 2018 compared with 2017, have affected retail customer prices, or may in the future, as authorized by the OPUC. In some cases, the Company has deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Power Costs—Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. In the event a general rate case is filed in any given year, forecasted power costs would be included in such filing. Such forecast assumes the following for the different types of PGE-owned generating resources:
▪Thermal—Expected operating conditions;
▪Hydroelectric—Regional hydro generation based on historical stream flow data and current hydro operating parameters; and
Wind—Generation levels based on a five-year historical rolling average of the wind farm. To the extent historical information is not available for a given year, the projections are based on wind generation studies.
    
As part of the Company’s 2015 GRC, the OPUC approved the 2015 power cost forecast with an expected reduction in annual revenues of approximately $60 million. This amount was included in the overall $15 million revenue increase authorized by the OPUC in 2015 GRC with corresponding customer prices effective January 1, 2015. Actual NVPC for 2015, as calculated for regulatory purposes under the PCAM, was $3 million below the 2015 baseline NVPC.

In June 2016, the Company submitted the 2015 results of the PCAM to the OPUC for final regulatory review and determination of any customer refund or collection. Based on its review, no refund or collection resulted, and in September 2016, the OPUC issued an order to such effect. For further information, see “Power Operations” in the Operating Activities section of this Overview, above.

PGE’s forecastAs part of its 2019 GRC, PGE included an initial projected increase in power costs for 2016of $39 million that was included in the overall request submitted to the OPUC. As approved by the OPUC within December 2018, the 2019 GRC included a final projected increase in power costs for 2019 and a corresponding increase in annual revenue requirement, of $25 million from 2018 levels.

As part of its 2018 GRC, PGE included an expectedinitial projected reduction in annual revenuespower costs of approximately $31 million. This amount$29 million that was included in the expected netoverall request submitted to the OPUC. As approved by the OPUC in December 2017, the 2018 GRC included a final projected reduction in power costs for 2018 and a corresponding reduction in annual revenue requirement, increase the OPUC authorized under the Company’s 2016 GRC. Actual NVPC for 2016, as calculated for regulatoryof $47 million from 2017 levels.

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purposes under the PCAM, was $10 million below the 2016 baseline NVPC. For further information, see “General Rate Cases” in this Overview section, above.

As a result of the OCEP legislation described above, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year. Prior to this legislative change, PGE included forecasts of PTCs only in General Rate Case proceedings. The inclusion of PTCs in the AUT provides for annual forecast updates for these estimated tax credits, thus reducing the risk of regulatory lag in terms of adjusting customer prices. The 2017 AUT filing, approved by the OPUC in November 2016 and included in customer prices effective January 1, 2017, projectsprojected a reduction in power costs for 2017, and a corresponding reduction in annual

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revenue requirement, of $56 million from 2016 levels. Actual NVPC for 2017, as calculated for regulatory purposes under the PCAM, was $15 million above the 2017 baseline NVPC.

Renewable Resource Costs—Pursuant to the RAC mechanism, PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placedresources. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in service in the current year.future RAC filings, under certain conditions. The Company may submit a filing to the OPUC by April 1st1 each year, with prices expected to become effective January 1st of the following year. As part ofNo significant filings have been submitted under the RAC the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.

On April 1, 2015, PGE submitted to the OPUC a RAC filing that requested revenue requirements related to a new 1.2 MW solar facility. Concurrent with this filing, PGE also requested authorization to engage in a property sale as part of a sale-leaseback agreement for the facility. The Company estimates that overall annual impact on annual revenues for this RAC filing will be an approximately $2 million reduction in revenues over a one-year period that began January 1, 2016. On October 2, 2015, the OPUC issued an order approving the deferral of costs associated with the facility.

On March 30, 2016, PGE submitted to the OPUC a RAC filing that requested no significant additionsduring 2018, 2017, or deferrals for 2016.

Decoupling Mechanism—The decoupling mechanism, which the OPUC had authorizedhas now extended through 2016,2022, 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. On September 26, 2016, the OPUC issued an order extending the decoupling mechanism through 2019. The mechanism provides for collection from (or refund to) customers if weather adjustedweather-adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

The Company recorded an estimated collection of $3$2 million during the year ended December 31, 2018, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2018 GRC. Collections under the decoupling mechanism are subject to an annual limitation of 2% of the applicable rate schedule, which was $18 million for 2018. Any collection from customers, as approved, for the 2018 year is expected to occur over a one-year period, which would begin January 1, 2020.

The Company recorded a deferral for an estimated collection of $11 million during the year ended December 31, 2017, as a result of variances from amounts established in the 2016 GRC. Collection for the year ended December 31, 2017 will occur over a one-year period, which began January 1, 2019.

The $3 million collection recorded in 2016 that resulted from variances between actual weather adjusted use per customer and that projected in the 2016 GRC. Any collection is expectedGRC, occurred during 2018. Similarly, a refund of the $9 million recorded during 2015 occurred during 2017.

Storm Restoration Costs—Beginning in 2011, the OPUC authorized the Company to occur over a one-year period, which would begin January 1, 2018. See “Customerscollect $2 million annually from retail customers to cover incremental expenses related to major storm damages, and Demand” to defer any amount not utilized in the Operating Activities sectioncurrent year. The 2018 GRC, as approved by the OPUC, increased the annual collection amount to $3 million, beginning in 2018. Under the 2019 GRC, the annual collection amount will be increased to $4 million beginning in 2019.

Due to a series of thisOverview, abovestorm events in the first half of 2017, the Company exhausted the $2 million storm collection authorized for further information2017. Consequently, PGE was exposed to the incremental costs related to such major storm events, which totaled $9 million, net of the $2 million amount collected in 2017. During 2016, due to excessive storm restoration costs, PGE had exhausted the available reserve at the end of the year.

As a result of the additional costs incurred, PGE filed an application with the OPUC requesting authorization to defer incremental storm restoration costs from the date of the application, in the first quarter of 2017, through the end of 2017, net of the $2 million being collected annually under the methodology at that time. An OPUC decision on the decoupling mechanism.application remains pending. The Company is unable to predict how the OPUC will ultimately rule on this application or state with any certainty whether these incremental costs are probable of recovery and, accordingly, no deferral has been recorded to-date. In the event it becomes probable that some or all of these costs are recoverable, the Company will record a deferral for such amounts at such time. The OPUC, in its decision on the Company’s 2019 GRC, directed OPUC Staff to bring this matter before the OPUC within 90 days of the issuance of the decision on the 2019 GRC.



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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, 2018, 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, 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 Portland Harbor, although such costs could be material to PGE’s financial position. However, the impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved in 2017, the Company’s environmental recovery mechanism 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 customer prices, as 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. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test.

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

Consistent with past regulatory precedent, on May 11, 2018, the Company submitted an application to the OPUC to defer the revenue requirement associated with this 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 costs, primarily related to depreciation and amortization, of the new customer information system upon it being placed in service.

On November 21, 2017, the OPUC opened docket UM 1909 to conduct an investigation of the scope of its authority under Oregon law to allow the deferral of costs related to capital investments for later inclusion in customer prices. On October 29, 2018, the OPUC issued Order 18-423 (Order) concluding that the OPUC lacks authority under Oregon law to allow deferrals of any costs related to capital investments. In the Order, the OPUC acknowledged that this decision is contrary to its past limited practice of allowing deferrals related to capital investments and will 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.

In response to the Order, PGE has considered its alternatives, and has requested reconsideration and clarification. PGE believes that the costs incurred to date associated with the customer information system were prudently incurred and has not withdrawn its deferral application to recover the revenue requirement of this capital project.

During the nine months ended September 30, 2018, PGE had deferred a total of $7 million related to the project. However, the Order has impacted the probability of recovery of the customer information system deferral and, as such, the Company has recorded a reserve for the full amount of the capital deferral through September 30, 2018 as well as an additional $5 million for the three months ended December 31, 2018. The full amount of the reserve was recognized as a charge to the results of operations in 2018 in the amount of $12 million. Any amounts that may ultimately be approved by the OPUC in subsequent proceedings 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.


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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 exceeded the amount authorized by the OPUC, PGE’s cost of service exceeded what was allowed in the Company’s revenue requirement primarily due to higher depreciation and amortization on the incremental capital cost, interest expense, and legal expense. These incremental costs totaled $8 million and $14 million for the years ended December 31, 2018 and 2017, respectively, and is reflected in the Company’s results of operations.

On July 16, 2018, the Company entered into a settlement to resolve all claims between the Company and each of Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership (collectively, the Contractor), Abengoa S.A., and Liberty Mutual Insurance Company and Zurich American Insurance Company (together, the Sureties). Under the terms of the settlement, i) the Sureties paid $130 million to PGE, and ii) the Contractor, Abengoa S.A., and the Sureties released all claims against the Company arising out of the Carty construction, and in return, PGE released all such claims against the Contractor, Abengoa S.A., and the Sureties, relating to Carty construction. The proceeds fully offset the incremental construction costs, thus eliminating ongoing excess depreciation and amortization, interest expense, and partially offsetting the Company’s other accumulated damages.

In July 2016, PGE requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the excess capital costs for Carty. The Company 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, were resolved. As a result of the settlement described above, the Company withdrew the deferral application.

For additional details regarding various legal and regulatory proceedings related to Portland Harbor, Carty, and other matters, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”
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 Total 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 consolidated statementspresentation of incomeGross margin is intended to supplement an understanding of PGE’s operating performance in relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company’s definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.


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The results of operations are as follows for the years presented (dollars in millions):
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Amount 
As %
of Rev
 Amount 
As %
of Rev
 Amount 
As %
of Rev
Amount 
As %
of Rev
 Amount 
As %
of Rev
 Amount 
As %
of Rev
Revenues, net$1,923
 100% $1,898
 100% $1,900
 100%
Total revenues (1)
$1,991
 100 % $2,009
 100% $1,923
 100%
Purchased power and fuel(1)617
 32
 661
 35
 713
 38
571
 30
 592
 30
 617
 32
Gross margin1,306
 68
 1,237
 65
 1,187
 62
1,420
 70
 1,417
 70
 1,306
 68
Other operating expenses:                      
Generation, transmission and distribution286
 15
 266
 14
 257
 13
292
 15
 309
 16
 286
 15
Administrative and other247
 13
 241
 13
 227
 12
271
 13
 260
 13
 240
 12
Depreciation and amortization321
 16
 305
 16
 301
 16
382
 19
 345
 17
 321
 17
Taxes other than income taxes119
 6
 116
 6
 109
 6
129
 6
 123
 6
 119
 6
Total other operating expenses973
 50
 928
 49
 894
 47
1,074
 53
 1,037
 52
 966
 50
Income from operations333
 18
 309
 16
 293
 15
346
 17
 380
 18
 340
 18
Interest expense, net*112
 6
 114
 6
 96
 5
Interest expense, net (2)
124
 6
 120
 6
 112
 6
Other income:                      
Allowance for equity funds used during construction21
 1
 21
 1
 37
 2
11
 1
 12
 1
 21
 1
Miscellaneous income, net1
 —
 1
 —
 1
 —
(4) —
 1
 —
 (6) —
Other income, net22
 1
 22
 1
 38
 2
7
 1
 13
 1
 15
 1
Income before income taxes243
 13
 217
 11
 235
 12
229
 12
 273
 13
 243
 13
Income tax expense50
 3
 45
 2
 61
 3
17
 1
 86
 4
 50
 3
Net income193
 10
 172
 9
 174
 9
$212
 11 % $187
 9% $193
 10%
Less: net loss attributable to noncontrolling interests—
 —
 —
 —
 (1) —
Net income attributable to Portland General Electric Company$193
 10% $172
 9% $175
 9%
                      
     
*(1) As reported on PGE’s Consolidated Statements of Income
(2) Includes an allowance for borrowed funds used during construction of $6 million in 2018 and 2017, and $11 million in 2016, $13 million in 2015, and $22 million in 2014.2016.


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Revenues, energy deliveries (presented in MWh), and average number of retail customers consist of the following for the years presented:
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Revenues(1) (dollars in millions):
                      
Retail:                      
Residential$907
 47% $895
 47 % $893
 47%$948
 48 % $969
 48% $907
 47%
Commercial665
 35
 662
 35
 657
 34
647
 32
 652
 32
 652
 34
Industrial208
 11
 228
 12
 221
 12
185
 9
 192
 10
 193
 10
Direct Access43
 2
 37
 2
 28
 2
Subtotal1,780
 93
 1,785
 94
 1,771
 93
1,823
 91
 1,850
 92
 1,780
 93
Other accrued (deferred) revenues, net3
 —
 (10) (1) (8) —
Alternative revenue programs, net of amortization3
 —
 —
 —
 —
 —
Other accrued (deferred) revenues, net(2)
(45) (2) 10
 1
 3
 —
Total retail revenues1,783
 93
 1,775
 93
 1,763
 93
1,781
 89
 1,860
 93
 1,783
 93
Wholesale revenues103
 5
 88
 5
 95
 5
159
 8
 105
 5
 103
 5
Other operating revenues37
 2
 35
 2
 42
 2
51
 3
 44
 2
 37
 2
Total revenues$1,923
 100% $1,898
 100 % $1,900
 100%$1,991
 100 % $2,009
 100% $1,923
 100%
                      
Energy deliveries(2) (MWh in thousands):
           
Energy deliveries (MWh in thousands):           
Retail:                      
Residential7,348
 33% 7,325
 33 % 7,462
 34%7,416
 31 % 7,880
 34% 7,348
 33%
Commercial7,457
 33
 7,511
 34
 7,494
 34
6,783
 29
 6,932
 30
 6,932
 31
Industrial4,166
 19
 4,546
 21
 4,310
 20
2,987
 13
 2,943
 13
 2,968
 13
Subtotal17,186
 73
 17,755
 77
 17,248
 77
Direct access:           
Commercial647
 3
 623
 3
 525
 2
Industrial1,389
 6
 1,340
 6
 1,198
 6
Subtotal2,036
 9
 1,963
 9
 1,723
 8
Total retail energy deliveries18,971
 85
 19,382
 88
 19,266
 88
19,222
 82
 19,718
 86
 18,971
 85
Wholesale energy deliveries3,352
 15
 2,560
 12
 2,520
 12
4,290
 18
 3,193
 14
 3,352
 15
Total energy deliveries22,323
 100% 21,942
 100 % 21,786
 100%23,512
 100 % 22,911
 100% 22,323
 100%
                      
Average number of retail customers:                      
Residential752,365
 88% 742,467
 88 % 735,502
 87%772,389
 88 % 762,211
 88% 752,365
 88%
Commercial106,773
 12
 105,802
 12
 105,231
 13
108,570
 12
 107,364
 12
 106,460
 12
Industrial258
 —
 255
 —
 260
 —
203
 —
 199
 —
 195
 —
Direct access604
 —
 559
 —
 376
 —
Total859,396
 100% 848,524
 100 % 840,993
 100%881,766
 100 % 870,333
 100% 859,396
 100%
                      
     
(1)
Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those customers that purchase their energy from ESSs. Commercial revenues from ESS customers were $18million, $17 million, and $13 million $12 million,for 2018, 2017, and $15 million for 2016, 2015, and 2014, respectively. Industrial revenues from ESS customers were $25 million, $20 million, and $15 million $16 million,for 2018, 2017, and $18 million for 2016, 2015, and 2014, respectively.
(2)Includes both energy soldAmount at December 31, 2018 primarily relates to retail customersthe regulatory liability deferral of the 2018 net tax benefits due to the change in corporate tax rate under the Tax Cuts and energy deliveriesJobs Act of 2018 (TCJA). For further information, see Note 12, Income Taxes in the Notes to those commercialConsolidated Financial Statements in Item 8.—“Financial Statements and industrial customers that purchase their energy from ESSs. Commercial deliveries to ESS customers, in thousands of MWhs, were 525, 509, and 563 in 2016, 2015, and 2014, respectively. Industrial deliveries to ESS customers, in thousands of MWhs, were 1,198, 1,177, and 1,099 in 2016, 2015, and 2014, respectively.Supplementary Data.”

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PGE’s sources of energy, total system load, and retail load requirement for the years presented are as
follows:
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Sources of energy (MWh in thousands):                      
Generation:                      
Thermal:                      
Natural gas7,515
 33% 6,228
 28% 5,811
 27%
Coal3,492
 16% 4,128
 19% 4,466
 21%3,106
 14% 3,344
 15
 3,492
 16
Natural gas5,811
 27
 4,783
 22
 3,429
 16
Total thermal9,303
 43
 8,911
 41
 7,895
 37
10,621
 47
 9,572
 43
 9,303
 43
Hydro1,629
 8
 1,453
 7
 1,750
 8
1,474
 7
 1,774
 8
 1,629
 8
Wind1,912
 9
 1,788
 8
 1,172
 6
1,875
 8
 1,641
 8
 1,912
 9
Total generation12,844
 60
 12,152
 56
 10,817
 51
13,970
 62
 12,987
 59
 12,844
 60
Purchased power:                      
Term6,961
 32
 7,364
 35
 8,552
 40
6,714
 30
 7,192
 33
 6,961
 32
Hydro1,541
 7
 1,572
 7
 1,568
 7
1,603
 7
 1,648
 7
 1,541
 7
Wind301
 1
 303
 2
 317
 2
286
 1
 264
 1
 301
 1
Total purchased power8,803
 40
 9,239
 44
 10,437
 49
8,603
 38
 9,104
 41
 8,803
 40
Total system load21,647
 100% 21,391
 100% 21,254
 100%22,573
 100% 22,091
 100% 21,647
 100%
Less: wholesale sales(3,352)   (2,560)   (2,520)  (4,290)   (3,193)   (3,352)  
Retail load requirement18,295
   18,831
   18,734
  18,283
   18,898
   18,295
  
                      

Net income attributable to Portland General Electric Companyfor the year ended December 31, 20162018 was $193212 million, or $2.162.37 per diluted share, compared towith $172187 million, or $2.042.10 per diluted share, for the year ended December 31, 20152017. TheAmong the factors that led to the $2125 million, or 12%13%, increase resulted in part fromnet income were the following:
Temperature contrasts contributed to lower net variable power costs than what was reflectedenergy demand in revenues2018 as customers used less energy in the Company’s 2016 AUT.warmer 2018 heating season compared with the colder than average 2017 period.
While retail deliveries were lower in 2018, lower Purchased power and fuel cost contributed to hold Gross margin comparable to 2017, as Wholesale revenues increased.
The reduction in Generation, transmission and distribution expense reflects the significant storm related costs decreased as the region experienced better hydro conditionsrecorded in 2016 than in 2015,2017 as well as improved wind generation, which also produced more PTCs. Average variable power cost per MWh declined 8% from 2015 and a 31%lower plant maintenance expenses in 2018.
The increase in the volume of wholesale energy sales also helped to reduce net variable power costs. Retail revenues increased only slightly as continued expansionAdministrative and general expenses in the average number of customers served and price changes authorized in the 2016 GRC were largely2018 was partially offset by the influences of weather and energy efficiency measures. Incremental depreciationa $14 million expense relatedreduction due 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 terminationconclusion of the Carty Construction Agreement, along withlitigation and cash settlement.
The increase in Depreciation and amortization largely reflects capital additions, including $8 million higher storm and service restoration costsamortization due to the new customer information system.
The Company recorded $9 million lower revenues under the decoupling mechanism in 2016 somewhat countered the other improvements2018 than in net income.2017.

Net income attributable to Portland General Electric Company for the year ended December 31, 20152017 was $172187 million, or $2.042.10 per diluted share, compared with $175193 million, or $2.18$2.16 per diluted share, for the year ended December 31, 20142016. The $36 million, or 2%3%, decrease in net income was largely a resultresulted primarily from the net impact of warmer than normalthe following three items: i) Gross margin increased due to higher energy demand, primarily due to weather and strength in the winter months of 2015 contributing to energy deliveries being lower than planned. The effects of the weather were partially offset by the increase in rate base associated with placing in service two generation resources in late 2014 that were included in customer price increases approved by the OPUC in the Company’s 2015 GRC. Purchased power and fuel costs declined year over year, although less than anticipated when customer prices were set for 2015, as the Company incurred higher than expected power costsindustrial sector; ii) Operating expense increased due to below normal regional hydro and wind conditions. Other operating expenses increased largely as expectedhigher 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 operationimpacts of the two additional generation resources, although higher storm costs in 2015TCJA, and insurance recoveries in 2014 did contribute to the net income impact year over year. AFDC declined in 2015, which, in part, contributed to increased interest expense in 2015, as a result of the completion of the two new generating facilities. Lower income before income taxes and an increase in production tax credits from expanded wind generation served to reduce income tax expense in 2015, although not to the extent anticipated when customer prices were set in the 2015 GRC.lower PTCs.


49
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20162018 Compared to 20152017

RevenuesTotal revenues increaseddecreased $2518 million, or 1.3%0.9%, in 20162018 compared with 20152017 as a result of the items discussed below.

Total retail revenues increaseddecreased $879 million, or 0.5%4.2%, in 20162018 compared with 20152017, primarily due to the net effect of the following:of:
A $49
$47 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 result of the Company’s 2016 GRC;
A $10 million increase resultingreduction resulted from 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 million2.5% 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%a 5.9% decrease in residential deliveries, and 0.7% decreasesa 1.7% decrease in industrial and commercial deliveries, respectively, partially offset by a 0.3% increase2.2% in residentialcrease in industrial deliveries. SeeThe effects of weather on electricity demand is reflected predominantly in the Residential revenue line in the table above. Considerably warmer temperatures in the first quarter of 2018 than experienced in 2017, which was colder than average, along with more moderate temperatures in the balance of 2018 than 2017, combined to drive deliveries lower. For further information on customer demand, see “Customers and Demand” in the Overview section of this Item 7. for further information on customer demand; and7;
A $23
$45 million decrease related to reflect the deferral of revenues for refund to customers as a result of the TCJA, which is reflected in the Other accrued (deferred) revenues, net line in the table above. This reduction in revenues is offset with lower income tax expense; and
$9 million decrease from the results of the decoupling mechanism, net of amortization, as a $2 million collection from customers during 2015was deferred into revenue in 2018, as opposed to a $11 million collection from customers deferred into revenue in 2017; partially offset by
$14 million increase as a result of costs associated with previous capital project deferrals, with no comparable collectionthe expiration of the credits to customers for the Trojan spent fuel refund, the effect of which is offset in 2016. This decreaseDepreciation and amortization expense; and
$9 million increase in revenues is largely offset byas a comparable decreaseresult of price changes, which includes a $47 million reduction in depreciation and amortization expense.revenues attributable to lower estimated NVPC, as filed in the 2018 GRC.

Total heating degree-days in 20162018 were lower thanbelow the 15-year average (as provided by the National Weather Service, as measured at Portland International Airport) although somewhat greater thanand down considerably from total heating degree-days in 2015.2017. Total cooling degree-days in 20162018 exceeded the 15-year average althoughby 35% and were considerably less thancomparable to the 20152017 total. The following table presents the number of heating and cooling degree-days in 20162018 and 20152017, along with the 15-year averages:averages, reflecting that weather had a considerable influence on comparative energy deliveries:
Heating Degree-Days Cooling Degree-Days   Heating Degree-Days Cooling Degree-Days   
2016 2015 15-Year Average 2016 2015 15-Year Average2018 2017 15-Year Average 2018 2017 15-Year Average
1st quarter1,585
 1,481
 1,866
 —
 —
 —
1,766
 2,171
 1,813
 —
 —
 —
2nd quarter403
 513
 689
 154
 207
 70
471
 686
 656
 116
 129
 85
3rd quarter78
 76
 78
 394
 573
 399
69
 78
 75
 575
 571
 426
4th quarter1,486
 1,391
 1,600
 —
 5
 2
1,396
 1,623
 1,573
 1
 —
 3
Total3,552
 3,461
 4,233
 548
 785
 471
3,702
 4,558
 4,117
 692
 700
 514
Increase (decrease) from the 15-year average(16)% (18)%   16% 67%  (10)% 11%   35% 36%  
                      

On a weather adjustedweather-adjusted basis, total 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%.2018 increased 0.4% from 2017 levels. PGE projects that retail energy deliveries for 20172019 will be nearly comparable to or slightly lower than 2016 weather adjustedabove 2018 weather-adjusted levels, after allowance forreflecting strength in industrial deliveries, partially offset by 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

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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.


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In 20162018, the $1554 million, or 17%51%, increase in wholesale revenues fromover 20152017 consisted of a $27resulted from $36 million increase related to 31% greatera 34% increase in wholesale sales volume partially offset bycombined with $18 million from a $12 million decrease related to 11% lower13% increase in average prices received when the Company sold power into the wholesale market prices.market.
 
Other operating revenues increased $27 million, or 6%16%, in 20162018 from 20152017, primarily dueapproximately half of which was attributable to the sale of excess natural gas not used to fuel the Company’s generating facilities, and 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 steamthe Company’s transmission revenue sales.

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 20162018, Purchased power and fuel expense decreased $4421 million, or 7%4%, from 20152017, which was driven by a $51$24 million or 8%, declinedecrease that resulted from a lower average variable power cost per MWh and a $3 million increase related to thetotal system load.

The $24 million decrease related to average variable power is due to a decrease in cost per MWh from $26.80 in 2017 to $25.31 per MWh in 2018. The price decrease was driven primarily by a 16% reduction in the average variable power cost per MWh to $28.50 in 2016 from $30.91 in 2015,PGE generating resources. This was partially offset by a $7 million increase resulting from a 1%an 8% increase in total system load.

The decrease related tothe average variable power cost per MWh for purchased power as the Company, on average, purchased power at higher market prices.

The $3 million increase due to total system load was driven primarily by a reduction in purchased power prices. The net34% increase in total system load was comprised of a $38 million, or 22%, increase due towholesale deliveries, partially offset by lower retail energy generateddeliveries. Energy obtained from the Company’s natural gas-fired resources increased 21% when compared to 2017, however this was partially offset by the combination of a $13 million, or 15%,17% decrease in energy generatedobtained from Company-owned coal-firedthe Company’s hydro resources and an $18 million, or 5%, reduction indue to less favorable hydro conditions.

In 2018, 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 PGE-owned wind generating resources (BiglowBiglow Canyon and Tucannon River)River increased 7%14% from 20152017 due to more favorable wind conditions and representedprovided 10% of the Company’s retail load requirement in 20162018 compared with 9% in 2015. 2017.

As a result of improvedthe less favorable hydro conditions in the region for 2018, energy received from PGE-owned hydroelectric projects and fromin combination with mid-Columbia projects combined for 2016 was 5% above 201510% below 2017 levels and represented 17% of the Company’s retail load requirement for 2016 and 16%2018 compared with 18% for 2015.2017.

The following table presents the forecast of theactual April-to-September 2017 runoff (as of February 9, 2017) compared to the actual runoffs for 20162018 and 20152017: runoff at particular points of major rivers relevant to PGE’s hydro resources:
 
Runoff as a Percent of Normal *
Location
2017
Forecast
 
2016
Actual
 
2015
Actual
Columbia River at The Dalles, Oregon99% 89% 69%
Mid-Columbia River at Grand Coulee, Washington95
 91
 77
Clackamas River at Estacada, Oregon101
 71
 53
Deschutes River at Moody, Oregon98
 91
 85
*Volumetric water supply forecasts and historical 30-year averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.
 Runoff as a Percent of 30-year Average
Location
2018
Actual
 
2017
Actual
Columbia River at The Dalles, Oregon98% 98%
Mid-Columbia River at Grand Coulee, Washington99
 98
Clackamas River at Estacada, Oregon97
 97
Deschutes River at Moody, Oregon96
 98

Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, decreased $59$75 million for 2016in 2018 compared with 2015.2017. The decrease attributable to changes in Purchased power and fuel expense was the result of an 8%a6% decline in the average variable power cost per MWh, offset slightly by a 1%2% increase in total system load. The decrease in actual NVPC was also driven by a 31%34% 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 beingthat were sold, into the wholesale market. The increase was partially offset by an 11% decrease in theon average, at 13% higher 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.MWh.

For 2016,2018, actual NVPC, as calculated for regulatory purposes under the PCAM, was $10$3 million below the 20162018 baseline NVPC. In 2015,2017, NVPC was $3$15 million belowabove the anticipated baseline. For further information regarding NVPC, see “Power Operations” in the Overview section of this Item 7.

Generation, transmission, and distribution expense increased $20decreased $17 million, or 8%6%, in 20162018 compared with 2015.2017. The increasedecrease was driven by the combination of $13 million in lower storm costs and $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 higherlower 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.expenses.

Administrative and other expense increased $6$11 million, or 2%4%, in 20162018 compared with 2015,2017, primarily due to $5$12 million higher legal costs attributable to Carty. The Company experienced slightly higher overall labor and employee benefit expenses althoughand $8 million higher expense due to an increase in the reserve for light and power receivables, offset by a $3$10 million expense reduction in pensionfor the Carty cash settlement, and $4 million lower legal expenses and a $2 million reduction in injuries and damages expense offset a large portionattributable to the conclusion of those increases.litigation around Carty construction.

Depreciation and amortization expense in 20162018 increased $16$37 million, or 5%11%, compared with 2015.2017. The increase was primarily driven by $17 million less expense in 2017 due to credits for the amortization of the regulatory liability provided to customers for the ISFSI spent fuel settlement, $10 million higher expense in 2018 resulting from capital additions, $8 million higher amortization due to the new customer information system in 2018, and a $4 million increase to asset retirement obligations.

Taxes other than income taxes expense increased $6 million, or 5%, in 2018 compared with 2017, driven by $3 million higher Oregon property taxes and $2 million higher franchise fees.

Interest expense increased $4 million, or 3%, in 2018 compared with 2017 due to higher expense as a result of a 2.7% increase in the average balance of debt outstanding.

Other income, net was $7 million in 2018 compared to $13 million in 2017, primarily due to losses on the non-qualified employee benefit trust.

Income tax expense decreased $69 million, or 80%, in 2018 compared to 2017. The decrease was driven by a lower federal corporate tax rate and other items pursuant to the TCJA, excess deferred tax amortization, lower pre-tax income and a 2017 remeasurement of deferred taxes. The reduction in expense driven by the TCJA is offset by $45 million that will be refunded to customers, and was recorded as a reduction to Revenues, net in the Consolidated Statements of Income.

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, net of amortization as an estimated $11 million collection was deferred into revenue 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
 1,866
 —
 —
 —
2nd quarter686
 403
 689
 129
 154
 70
3rd quarter78
 78
 78
 571
 394
 399
4th quarter1,623
 1,486
 1,600
 —
 —
 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 projected that retail energy deliveries for 2018 would 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.


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Wholesale revenues in 2017 increased $2 million, or 2%, from 2016, with such increase consisting of a $7 million increase that resulted from a 7% increase in average prices received when the Company sold power into the wholesale market, partially offset by a $5 million decrease related to 5% less wholesale sales volume.

Other operating revenues increased $7 million, or 19%, in 2017 from 2016, as the sale of excess natural gas not used to fuel the Company’s generating facilities accounted for the majority of the increase.

Purchased power and fuel expense in 2017 decreased $25 million, or 4%, from 2016, driven by a $38 million, or 6%, decline related to the decrease in the average variable power cost per MWh to $26.80 in 2017 from $28.50 in 2016, partially offset by a $13 million increase resulting from a 2% increase in total system load.

The decrease related to average variable power cost per MWh was driven primarily by: i) a 7% reduction 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 the purchase of replacement power due to 14% less energy received from the Company’s wind generating resources.

In 2017, energy received from Biglow Canyon and Tucannon River decreased 14% 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 improved hydro conditions in the region during 2017, energy received from PGE-owned hydroelectric projects, in combination with mid-Columbia projects, was 8% above 2016 levels and represented 18% of the Company’s retail load requirement for 2017 compared with 17% for 2016.

The following table presents the actual of the April-to-September runoff for 2017 and 2016:
 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 decreased $27 million for 2017 compared with 2016. The decrease attributable to changes in Purchased power and fuel expense was the result of an 6% decline in the average variable power cost per MWh, offset slightly by a 2% increase in total system load. The decrease in actual NVPC was also driven by a 7% increase in the average price per MWh of wholesale power sales, offset slightly by a 5% decrease in the volume of wholesale energy deliveries as the Company’s retail load requirement increased in 2017, largely due to the effects of weather, which resulted in a greater portion of its system load used to meet retail load requirements.

For 2017, actual NVPC, as calculated for regulatory purposes under the PCAM, was $15 million above the 2017 baseline NVPC, compared with $10 million below the anticipated baseline for 2016.

Generation, transmission, and distribution expense increased $23 million, or 8%, in 2017 compared with 2016. The increase was driven by the combination of $10 million in higher costs due to the addition of Carty, $8 million higher service restoration and storm costs, $3 million higher plant maintenance expenses, and $2 million higher information technology expenses.

Administrative and other expense increased $20 million, or 8%, in 2017 compared with 2016, primarily due to $12 million higher overall labor and employee benefit expenses, $3 million higher legal costs attributable to Carty and a $3 million difference in the non-service cost component of net periodic pension expense reclassified as a result of the adoption of ASU 2017-07, see Note 2, Summary of Significant Accounting Policies in Item 8. - “Financial Statements and Supplementary Data”.

Depreciation and amortization expense in 2017 increased $24 million, or 7%, compared with 2016. The increase was primarily driven by $26 million higher expense resulting from capital additions, partially offset by a $7$3 million reduction in expense increase resulting from thedue to higher amortization credits in 2015 from gains recorded on the sale of assets, and a $5 million expense increase from lower amortization credits in 20162017 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 authorized in the Company’s 2011 GRC.spent fuel settlement. The overall impact resulting from the amortization of the regulatory assets and liabilities is directly offset by corresponding reductions in retail revenues.

Taxes other than income taxes expense increased $3$4 million, or 3%, in 20162017 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 with $4 million lower expense resulting from a 3% decrease in the average balance of debt outstanding, partially offsetdriven by $2 million less allowance for borrowed funds used during construction credits.

Other income, net was $22 million in both 2016higher Oregon property taxes and2015, 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 to 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.

2015 Compared to 2014

Revenues decreased $2 million, or less than 1%, in 2015 compared with 2014 as a result of the items discussed below.

Total retail revenues increased $12 million, or 1%, in 2015 compared with 2014, primarily due to the net effect of the following:

An $11 million increase in revenues related to a 0.6% increase in retail energy deliveries, consisting of 5.5% and 0.2% increases in industrial and commercial deliveries, respectively, partially offset by a 1.8% decrease in residential deliveries; and

A $4 million net increase that related to higher average retail prices resulting from the January 1, 2015 price increase authorized by the OPUC in the Company’s 2015 GRC, which was net of a $28 million decrease due to various supplemental tariff changes, including $20 million in customer credits in 2015 related to proceeds received in connection with the settlement of a legal matter regarding the operation of the ISFSI at the former Trojan nuclear power plant site and tax credits, all of which are offset in Depreciation and Amortization expense.

Total heating degree-days in 2015 were lower than the 15-year average (as provided by the National Weather Service, as measured at Portland International Airport) and total heating degree-days in 2014, while total cooling degree-days in 2015 exceeded the 15-year average and 2014 total cooling degree-days. The following table presents the number of heating and cooling degree-days in 2015 and 2014, along with the 15-year averages:
 Heating Degree-Days Cooling Degree-Days
 2015 2014 15-Year Average 2015 2014 15-Year Average
1st quarter1,481
 1,891
 1,864
 —
 —
 —
2nd quarter513
 530
 713
 207
 57
 70
3rd quarter76
 18
 85
 573
 579
 382
4th quarter1,391
 1,355
 1,602
 5
 17
 1
Total3,461
 3,794
 4,264
 785
 653
 453
Increase (decrease) from the 15-year average(19)% (11)% 

 73% 44% 


On a weather adjusted basis, retail energy deliveries in 2015 were 2.3% above 2014.

Wholesale revenues in 2015 decreased $7 million, or 7%, from 2014, with such decrease comprised of $8 million related to a 9% lower average wholesale market prices partially offset by a $2 million increase related to 2% greater wholesale sales volume.

Other operating revenues decreased $7 million, or 17%, in 2015 from 2014, primarily due to a $4 million decline in high voltage service revenues and a $3 million decrease in transmission resale revenues. Resale of excess natural gas and oil needed for operations was comparable in 2015 to 2014.


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Purchased power and fuel expense in 2015 decreased $52 million, or 7%, from 2014, driven by a $57 million, or 8%, decline related to the decrease in the average variable power cost per MWh to $30.91 in 2015 from $33.54 in 2014, partially offset by a $5 million increase resulting from a 1% increase in total system load.

As a result of below normal hydro conditions in the region, energy received from PGE-owned hydroelectric projects and from mid-Columbia projects combined for 2015 was 9% below 2014 levels, and represented 16% of the Company’s retail load requirement for 2015 and 18% in 2014. Total hydroelectric energy received from these sources fell short of that projected in PGE’s AUT by approximately 7% for 2015 and 2% for 2014.

The following table presents the actual of the April-to-September runoff for 2015 and 2014:
 
Runoff as a Percent of Normal *
Location
2015
Actual
 
2014
Actual
Columbia River at The Dalles, Oregon69% 108%
Mid-Columbia River at Grand Coulee, Washington77
 110
Clackamas River at Estacada, Oregon53
 97
Deschutes River at Moody, Oregon85
 98
*Actual volumetric water supply amounts and historical 30-year averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.

In 2015, energy received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River, which was placed in service during December 2014) increased 53% from 2014, and represented 9% of the Company’s retail load requirement in 2015 compared to 6% in 2014. Energy received from wind generating resources fell short of projections included in the Company’s AUT by approximately 15% in 2015 compared with 9% in 2014.

Actual NVPC decreased $45 million for 2015 compared with 2014. The decrease was largely due to an 8% decline in the average variable power cost per MWh combined with a 2% increase in the volume of wholesale power sales, net of a 9% decrease in the average price per MWh of wholesale power sales. The 2015 GRC had anticipated a decrease of approximately $60 million in NVPC from the 2014 baseline, with customer prices set accordingly. For 2015, actual NVPC, as calculated for regulatory purposes under the PCAM, was $3 million below baseline NVPC, compared with $7 million below for 2014.

Generation, transmission, and distribution expense increased $9 million, or 4%, in 2015 compared with 2014. The increase was driven by the combination of $9 million higher costs due to the addition of PW2 and Tucannon River, $3 million higher information technology expenses, $2 million higher plant maintenance expenses, increased outside services of $2 million, higher labor of $2 million, and higher service restoration and storm costs of $2 million. Partially offsetting the increases were lower expense of $8 million related to repair and maintenance work during the annual planned outage and economic displacement of Boardman in 2015, coupled with the unplanned outages at Colstrip in January 2014, and $3 million lower expenses related to high voltage customer services.

Administrative and other expense increased $14 million, or 6%, in 2015 compared with 2014, primarily due to a $5 million increase in information technology expenses, an increase of $3 million in non-labor and outside services expenses, a $3 million increase in injuries and damages resulting from insurance recoveries related to prior year claims received in 2014, and a $1 million increase in compensation and benefits expense.

Depreciation and amortization expense in 2015 increased $4 million, or 1%, compared with 2014. A $26 million higher expense resulting from capital additions was largely offset by a $22 million reduction from the amortization of deferred regulatory liabilities for the Trojan spent fuel settlement and tax credits as they were refunded to customers in 2015. An increase in asset retirement obligations (AROs) expenses and amortization of costs previously deferred for four capital projects as authorized in the Company’s 2011 GRC were partially offset by

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amortization of gains recorded on the sale of assets. The overall reduction in expenses resulting from the amortization of the regulatory liabilities is directly offset by corresponding reductions in retail revenues.

Taxes other than income taxes expense increased $7 million, or 6%, in 2015 compared with 2014, primarily due to a $5 million increase in property taxes attributed to the addition of PW2 and Tucannon River and a $2 million increase in franchise fees.payroll taxes.

Interest expense increased $18$8 million, or 19%7%, in 20152017 compared towith 20142016 as $9a result of a $4 million resulted from lowerdecrease in the credits for the allowance for borrowed funds used during construction. In December 2014, PW2construction (primarily due to the Carty plant being placed in service in 2016) and Tucannon River were placed into servicean increase of $3 million resulting infrom a lower average CWIP balance, the basis for AFDC, during 2015. In addition, $7 million related to a 7% increase in the5% larger average balance of debt outstanding.

Other income, net was $22$13 million in 20152017 compared to $38with $15 million in 2014. The2016, with the decrease was primarily due to a $16 million decrease in thelower allowance for equity funds used during construction, resultingwhich resulted from Carty being placed in service during 2016. In addition, there is a $3 million difference in the lower average CWIP balance.non-service cost component of net periodic pension expense reclassified to Miscellaneous income, net as a result of the adoption of ASU 2017-07, see Note 2, Summary of Significant Accounting Policies in Item 8. - “Financial Statements and Supplementary Data”

Income tax expense decreased $16increased $36 million, or 26%72%, in 20152017 compared with 2014, while the effective tax rate decreased to 20.7% for 2015 from 26.0% for 20142016. LowerThe change relates to a $13 million increase due to higher pre-tax income accounted forand $7 million due to lower production tax credits. Additionally, Income tax expense increased $17 million due to the remeasurement of deferred taxes pursuant to the decreasechange in incomecorporate tax expense. A $14 million increaserates in PTCs in 2015, resulting primarily from the additionTCJA. For more information regarding the Company’s approved OPUC order, see the “Tax Reform” Section of Tucannon River wind generation, was partially offset by a $5 million relative effect of lower AFDC equity.this Item 7.
 
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 20162018 and projected capital expenditures and future debt maturities for 20172019 through 20212023 (in millions, excluding AFDC):
Years Ending December 31,Years Ending December 31,
2016 2017 2018 2019 2020 20212018 2019 2020 2021 2022 2023
Ongoing capital expenditures(1)$406
 $604
 $427
 $294
 $300
 $290
$580
 $580
 $500
 $500
 $500
 $500
Carty190
 6
 —
 —
 —
 —
Customer information system(2)
26
 —
 —
 —
 —
 —
Wheatridge Renewable Energy Facility—
 —
 140
 15
 —
 —
Total capital expenditures$596
* 
$610
 $427
 $294
 $300
 $290
$606
(3) 
$580
 $640
 $515
 $500
 $500
                      
Long-term debt maturities$—
 $150
 $—
 $300
 $—
 $160
$—
 $300
 $—
 $160
 $—
 $—
     
* Amounts shown include preliminary engineering and removal costs, which are included in other net operating activities in the consolidated statements of cash flows.
(1)Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects, and the non-utility purchase of PGE’s corporate headquarters in 2018.
(2)
Total capital expenditures for the customer information system through December 31, 2018 were $140million, excluding AFDC.
(3)Includes preliminary engineering and removal costs, which are included in other net operating activities in the consolidated statements of cash flows.

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

Ongoing capital expenditures—This line in the table above consists primarily of upgrades to, and replacement of, generation, transmission, distribution infrastructure, as well as new customer connections. For the years 2017 through 2018, approximately $63 million relates to the implementation of the Company’s new customer information and meter data management systems. In addition, $149million is included for transmission, distribution, and generation resiliency projects in 2017.


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Carty—On July 29, 2016, Carty, a natural gas-fired baseload resource in Eastern Oregon, was placed into service. As of December 31, 2016, PGE had $634 million in plant in service related to Carty. The Company expects to incur certain trailing costs in 2017 that could amount to $6 million and currently estimates that the total capital expenditures for Carty will be approximately $640 million, including AFDC. This estimate excludes approximately $17 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor. The Company believes these liens are invalid and is contesting the claims in the courts. Estimated total expenditures for Carty would be offset by any amounts received from the Sureties pursuant to the performance bond. For additional information, see “Carty” in the Overview section in 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,Years Ended December 31,
2016 2015 20142018 2017 2016
Cash and cash equivalents, beginning of year$4
 $127
 $107
$39
 $6
 $4
Net cash provided by (used in):          
Operating activities553
 520
 520
630
 597
 562
Investing activities(585) (522) (994)(471) (514) (585)
Financing activities34
 (121) 494
(79) (50) 25
Net change in cash and cash equivalents2
 (123) 20
80
 33
 2
Cash and cash equivalents, end of year$6
 $4
 $127
$119
 $39
 $6
          

20162018 Compared to 20152017

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 $33 million increase in cash flows from operating activities in 20162018 compared to 2015 was largely2017 is due to increasesan overall increase in Net income of $25 million, an increase in Depreciation and amortization of $37 million due to higher average plant balances, an increase of $46 million in Accounts payable and accrued liabilities partially due to increased fuel costs from higher gas prices, and an increase of $45 million due to the net income and depreciation expense, partlybenefits received from tax reform. These costs were offset by a $87 million decrease in Deferred income taxes primarily due to the impactdecrease in the corporate tax rate as a result of changes in other non-cash income and expense items including amounts recorded under the decoupling mechanism,TCJA, and a decrease$26 million increase in margin deposits. The remaining non-cash incomeAccounts receivable and expenses and other components of working capital were fairly consistent year over year.unbilled revenue.

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 20172019 will range from $340$400 million to $350$420 million. Combined with all other sources, cash provided by operations in 20172019 is estimated to range from $450$550 million to $500$600 million.

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 $63$43 million increasedecrease in net cash used in investing activities in 20162018 compared to 2015 waswith 2017 is primarily due to $120 million cash inflow as a distributionresult of $50the Carty litigation settlement, which was partially offset by higher capital expenditures largely due to a $45 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

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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,non-utility capital investment in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”purchase of PGE’s corporate headquarters.
 
The Company plans for approximately $610$580 million of capital expenditures in 20172019 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. The planned amount reflects estimated capital expenditures to complete Carty of $6 million, excluding AFDC. PGE plans to fund the 20172019 capital expenditures and current maturities of long-term debt of $150 million with cash from operations during 2017,2019, 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 20162018, cash used in financing activities consisted primarily of the issuance of $75 million of long-term debt, less the repayment $24 million of Pollution Control Bonds and payment of dividends in the amount of $125 million. During 2017, cash provided by financing activities consisted of the issuance of $290$225 million of long-term debt, less the repayment $133of $150 million of FMBsterm loans 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$118 million.


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20152017 Compared to 20142016

Cash Flows from Operating Activities—The $35 million increase in cash flows from operating activities in 2017 compared to 2016 reflects that while Net income was nearly comparable, adjustments to Net income to reconcile to net cash provided included increases of $33 million for Deferred income taxes ($17 million of which related to Tax reform), $19 million for Other non-cash income and expenses, and $24 million for Depreciation and amortization expense. PGE has reclassified $9 million from Other, net within the Cash flows from operating activities to Other, net within the Cash flows from financing activities on the consolidated statements of cash flows for the year ended December 31, 2016 as a result of the adoption of ASU 2016-15. For further information, see Note 2, Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data.2015 remained comparable

Somewhat offsetting those increases were decreases of $28 million from Margin deposits outstanding due to 2014. A decreasechanges in prices of power and fuel underlying contracts with counterparties and $16 million as a result of the net change in working capital itemsdecoupling mechanism, which reflects both the current year deferral and a decrease in the amount received from Bonneville Power Administration to be returnedrefund to customers pursuantrelated to the Residential Exchange Program, which collectively, were nearly offset by an increase in the combination of Net income and non-cash income and expenses, net.prior years.

Cash Flows from Investing Activities—The $472$71 million decrease in net cash used in investing activities in 20152017 compared to 20142016 was primarily due to a $409 million decrease in capitalCapital expenditures largely due to the completion of construction of PW2 and Tucannon Riveras Carty was placed into service in December 2014. In addition, the Company received $23 million from a sales tax refund related to Tucannon River and a distribution of $50 million from the Nuclear decommissioning trust. For additional information regarding the distribution from the Nuclear decommissioning trust, see Note 3, Balance Sheet Components, and Note 7, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”July 2016.

Cash Flows from Financing Activities—During 20152017, cash used in financing activities consisted primarily of repaymentsthe issuance of $225 million of long-term debt less the repayment of $442$150 million of term loans and the payment of dividends of $97 million, partially offset by net proceeds received from the issuances of common stock in the amount of $271 million and FMBs of $145$118 million. During 20142016, net cash provided by financing activities consisted of net proceeds received fromissuance of $290 million of long-term debt less the issuancesrepayment of term bank loans$133 million of $305 millionFMBs and FMBs of $280 million, partially offset by the payment of dividends of $87$110 million.


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Dividends on Common Stock

The following table presents common stock dividends declared in 20162018:
Declaration Date  Record Date  Payment Date  
Declared Per
Common Share
February 17, 2016 March 25, 2016 April 15, 2016 $0.30
April 27, 2016 June 27, 2016 July 15, 2016 0.32
July 27, 2016 September 26, 2016 October 17, 2016 0.32
October 26, 2016 December 27, 2016 January 17, 2017 0.32
Declaration Date  Record Date  Payment Date  
Declared Per
Common Share
February 14, 2018 March 26, 2018 April 16, 2018 $0.3400
April 25, 2018 June 25, 2018 July 16, 2018 0.3625
July 25, 2018 September 25, 2018 October 15, 2018 0.3625
October 24, 2018 December 26, 2018 January 15, 2019 0.3625

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 15, 2017,13, 2019, a common stock dividend of $0.32$0.3625 per share was declared, payable April 17, 201715, 2019 to shareholders of record on March 27, 2017.25, 2019. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s and S&P, with current credit ratings and outlook as follows:
 Moody’s  S&P
First Mortgage BondsA1 A-A
Senior unsecured debtA3 BBBBBB+
Commercial paperPrime-2P-2 A-2
OutlookStable StablePositive

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

As of December 31, 2016,2018, PGE had posted approximately $25$64 million of collateral with these counterparties, consisting of $8$16 million in cash and $17$48 million in bank letters of credit, $11 million of which is related to master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 20162018, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $91$65 million and decreases to approximately $51$20 million by December 31, 20172019 and $31$7 million by December 31, 2018.2020. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $174$162 million and decreases to approximately $93$95 million by December 31, 20172019 and $71$73 million by December 31, 2018.2020.

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.

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The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 20162018, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $1.2$1 billion of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65% of total capitalization (debt to total capital ratio). As of December 31, 20162018, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 51.0%51.5%.

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors. Management believes that the availability of revolving credit facilities, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.

For 2017,2019, PGE expects to fund estimated capital requirements with cash from operations, the issuance of debt securities of approximately $450up to $375 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.


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Short-term Debt—Pursuant to an order issued by the FERC on January 3, 2018, PGE has approval from the FERCauthorization to issue short-term debt up to a total of $900 million through February 6, 2018.2020.

As of December 31, 2016,2018, PGE had a $500 million revolving credit facility scheduled to expire inNovember 2019.2021. On January 15, 2019 PGE executed an amendment to the credit facility extending the termination date to November 14, 2022 and allowing for unlimited extension requests, provided that Lenders with a pro-rata share of more than 50%, 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.

PGE 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, 20162018, PGE hadno borrowings outstanding, and no commercial paper or letters of credit issued. As a result, as of December 31, 20162018, the aggregate unused available credit capacity under the revolving credit facility was $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 a total capacity of $160$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 $56$84 million were outstanding as of December 31, 20162018.


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Long-term Debt—During 2016,2018, PGE issued a total of $140 million and repaid $133 million of FMBs. In January 2016, the Company issued $140 million of 2.51% Series FMBs due 2021 and repaid $58 million of 3.81% Series FMBs, due in 2017 and $75 million of 5.80% series FMBs due in 2018. Due to the anticipated repaymentat an interest rate of this $133 million in early January 2016, this amount4.47% with a maturity date of long-term debt was classified as current on the Company’s consolidated balance sheets as of December 31, 2015.

2048. In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under whichaddition, the Company had the opportunity to obtain three separate term loansrepaid $24 million of Pollution Control Revenue Bondsthat were early redeemed in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained the following term loans:

$50 million on May 4, 2016;

$75 million on June 15, 2016; and

$25 million on October 31, 2016.

The term loan interest rates are 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, approximately 1.37% as of December 31, 2016, with no other fees.

The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable. As such, $150 million is reflected on the consolidated balance sheet as Current portion of long-term debt as of December 31, 2016. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults, and other customary defaults for financings of this type.2018.

As of December 31, 20162018, total long-term debt outstanding, net of $11$10 million of unamortized debt expense, was $2,350$2,478 million, of which $150$300 million of the term loans areis scheduled to mature in 2017.2019.

Capital Structure—PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50% 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 ratios were 49.4%ratio was 49.8% and 50.7%49.4% as of December 31, 20162018 and 2015,2017, respectively.


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Contractual Obligations and Commercial Commitments

The following table presents PGE’s contractual obligations as of December 31, 20162018 (in millions):
 
2017 2018 2019 2020 2021 
There-
after
 Total2019 2020 2021 2022 2023 
There-
after
 Total
Long-term debt$150
 $—
 $300
 $—
 $160
 $1,751
 $2,361
$300
 $—
 $160
 $—
 $—
 $2,028
 $2,488
Interest on long-term debt (1)
116
 114
 101
 95
 91
 1,530
 2,047
112
 106
 102
 101
 100
 1,549
 2,070
Capital and other purchase commitments176
 8
 2
 9
 1
 60
 256
143
 9
 1
 1
 1
 58
 213
Purchased power and fuel:                          
Electricity purchases221
 157
 181
 256
 239
 1,750
 2,804
167
 190
 186
 194
 193
 1,853
 2,783
Capacity contracts7
 6
 5
 4
 4
 12
 38
1
 —
 9
 9
 9
 18
 46
Public Utility Districts4
 4
 1
 —
 1
 11
 21
12
 11
 9
 8
 8
 35
 83
Natural gas53
 39
 32
 27
 24
 158
 333
54
 42
 31
 31
 30
 208
 396
Coal and transportation17
 9
 5
 —
 —
 —
 31
6
 —
 —
 —
 —
 —
 6
Pension Plan Contributions (2)
3
 21
 21
 21
 20
 —
 86
—
 41
 26
 30
 31
 —
 128
Capital leases7
 7
 6
 6
 6
 77
 109
6
 6
 6
 6
 5
 67
 96
Build-to-suit lease—
 4
 14
 13
 13
 237
 281
11
 14
 13
 13
 13
 225
 289
Operating leases10
 9
 6
 6
 7
 177
 215
4
 5
 5
 6
 7
 97
 124
Total$764
 $378
 $674
 $437
 $566
 $5,763
 $8,582
$816
 $424
 $548
 $399
 $397
 $6,138
 $8,722
     
(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, 20162018.
(2) Contributions beyond 20212023 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 threethe Priest Rapids and Wanapum hydroelectric projects (the Priest Rapids, Wanapum, and Wells hydroelectric projects). The Company is requiredunder 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 rata share of both the output and the operating and debt service costs of the defaulting purchaser. For

Under an agreement for output of the Wells project, PGE receives a share of the production in return for a fixed payment. If any other purchaser of output were to default, PGE would be allocated up toreceive a cumulative maximum of 25%pro-rata portion of the defaulting purchaser’s percentageshare of the output. Forproject output and associated costs, with no limitation, regardless of the Priest Rapids and Wanapum projects, PGE would be allocated upreason for the default. The share of the project 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 Districtsutility districts” in Note 15,16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”


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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:
PGE hasfour letter of credit facilities that provide capacity up to a total 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, $84 million has been issued as of December 31, 2018; and
As a co-owner of Colstrip, PGE has provided surety bonds of $8 million in December 2018 and $10 million in January 2019 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 Stations, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is currently anticipated that each co-owner of Colstrip will be required, at some future point, to post a third tranche of financial assurance to support additional performance by the operator of closure and remediation actions under the AOC.


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Critical Accounting Policies

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

Regulatory Accounting

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

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

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Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Changes that may arise over time with regard to these assumptions and determinations can change future amounts recorded for AROs.

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

Revenue Recognition

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

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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.

Price Risk Management

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

Fair value adjustments consist of reevaluating the fair value of derivative contracts at the end of each reporting period for the remaining term of the contract and recording any change in fair value in Net income for the period. Fair value is the present value of the difference between the contracted price and the forward market price multiplied by the total quantity of the contract. For option contracts, a theoretical value is calculated using Black-Scholes models that utilize price volatility, price correlation, time to expiration, interest rate and forward commodity price curves. The fair value of these options is the difference between the premium paid or received and the theoretical value at the fair value measurement date.

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

Pension Plan

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

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


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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 reduction in the discount rate, would have the effect of increasing the 20162018 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.debt; and iv) interest rate swaps. 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

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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.

Risk Management Committee

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

Commodity Price Risk

PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company engages in price risk management activities to manage exposure to volatility in net power costs for its retail customers. The Company uses power purchase contracts to supplement its 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 of fuel for the Company’s natural gas- and coal-fired generating plants. These contracts for the purchase of power and fuel expose the Company to market risk. The Company uses instruments such as: 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. PGE does not engage in trading activities for non-retail purposes.


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The following table presents energy commodity derivative fair values as a net liability as of December 31, 20162018 that are expected to settle in each respective year (in millions):
2017 2018 2019 2020 2021 Thereafter Total2019 2020 2021 2022 2023 Thereafter Total
Commodity contracts:                          
Electricity$6
 $7
 $7
 $7
 $7
 $77
 $111
$4
 $6
 $6
 $6
 $6
 $55
 $83
Natural gas20
 7
 6
 2
 —
 —
 35
28
 14
 6
 1
 —
 —
 49
$26
 $14
 $13
 $9
 $7
 $77
 $146
$32
 $20
 $12
 $7
 $6
 $55
 $132

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 included in the PCAM. PGE remains subject to cash flow risk in the form of collateral requirements based on the

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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. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy.

As of December 31, 2016,2018, a 10% change in the value of the Canadian dollar would result in an immaterial change in exposure for transactions that will settle over the next twelve months.

Interest Rate Risk

To meet short-term cash requirements, PGE has the ability to issue commercial paper for terms of up to 270 days and has 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, 2016,2018, PGE had no borrowings outstanding under its revolving credit facility and no commercial paper outstanding or other short-term debt outstanding.

PGE currently has no financial instrumentsused two forward starting interest rate swap lock agreements to mitigatehedge a portion of its interest rate risk related toassociated with anticipated issuances of fixed-rate, long-term debt securities. These derivatives were designated as cash flow hedges, protecting against the risk of changes in short-termfuture interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance.

The notional amount of the interest rate swaps is $170 million with a mandatory cash settlement date in January 2019. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. Such amounts are also included as a component of cost of debt for ratemaking purposes.

Until settlement, the interest rate swaps are carried at fair value as a derivative asset or liability with the corresponding offset recorded as either a regulatory liability or regulatory asset, respectively. The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates including thosecompared to the interest rates fixed by the swaps. As of December 31, 2018, the fair value of the interest rate swaps was a $4 million loss, which is recorded in Liabilities from price risk management activities—current on commercial paper; however, it may consider such instruments in the future as considered necessary.


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Company’s consolidated balance sheets.

As of December 31, 20162018, 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
Total
Fair
Value
 Carrying Amounts by Maturity Date
Total 2017 2018 2019 2020 
There-
after
Total 2019 2020 2021 2022 
There-
after
First Mortgage Bonds$2,411
 $2,090
 $—
 $—
 $300
 $—
 $1,790
$2,662
 $2,390
 $300
 $—
 $160
 $—
 $1,930
Unsecured Term Bank Loans150
 150
 150
 —
 —
 —
 —
Pollution Control Revenue Bonds132
 121
 —
 —
 —
 —
 121
98
 98
 —
 —
 —
 —
 98
Total$2,693
 $2,361
 $150
 $—
 $300
 $—
 $1,911
$2,760
 $2,488
 $300
 $—
 $160
 $—
 $2,028

As of December 31, 2016, PGE’s unsecured term bank loans in the amount of $150 million were the only2018, PGE had no long-term debt instruments subject to interest rate risk exposures. As


59
Table of December 31, 2016, a change of 10% in the existing interest rates of these unsecured term bank loans would result in an immaterial change in interest rate risk exposure over the next twelve months.Contents


Credit Risk

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. The Company also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded 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, 20162018, PGE’s credit risk exposure is $4$20 million for commodity activities, of which $17 million is with externally-rated investment grade counterparties and matures in 2018.counterparties. The underlying transactions that make up the exposure will mature during 2019. 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 gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit, and may represent prepayment or credit exposure assurance.

Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon.Washington. These contracts currently provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2052. For additional information, see “Public Utility Districtsutility 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.

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

Report of Independent Registered Public Accounting Firm
 
6762
   
Consolidated Statements of Income for the years ended December 31, 2016, 2015,2018, 2017, and 20142016
 
6964
   
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015,2018, 2017, and 20142016
 
7065
   
Consolidated Balance Sheets as of December 31, 20162018 and 20152017
 
7166
   
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2016, 20152018, 2017, and 20142016
 
7368
   
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015,2018, 2017, and 20142016
 
7469
   
Notes to Consolidated Financial Statements
 
7671


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Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  

To the shareholders and the Board of Directors and Shareholders of
Portland General Electric Company
Portland, Oregon
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, 20162018 and 20152017, and 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, 20162018, 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, 20162018, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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’sManagement's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We 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 Public Company Accounting Oversight Board (United States).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 supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the financial statement presentation.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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our

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opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Portland, Oregon
February 16, 201714, 2019

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,
2016 2015 20142018 2017 2016
Revenues:     
Revenues, net$1,923
 $1,898
 $1,900
$1,988
 $2,009
 $1,923
Alternative revenue programs, net of amortization3
 —
 —
Total Revenues1,991
 2,009
 1,923
Operating expenses:          
Purchased power and fuel617
 661
 713
571
 592
 617
Generation, transmission and distribution286
 266
 257
292
 309
 286
Administrative and other247
 241
 227
271
 260
 240
Depreciation and amortization321
 305
 301
382
 345
 321
Taxes other than income taxes119
 116
 109
129
 123
 119
Total operating expenses1,590
 1,589
 1,607
1,645
 1,629
 1,583
Income from operations333
 309
 293
346
 380
 340
Interest expense, net112
 114
 96
124
 120
 112
Other income:          
Allowance for equity funds used during construction21
 21
 37
11
 12
 21
Miscellaneous income, net1
 1
 1
Miscellaneous income (expense), net(4) 1
 (6)
Other income, net22
 22
 38
7
 13
 15
Income before income taxes243
 217
 235
229
 273
 243
Income tax expense50
 45
 61
17
 86
 50
Net income193
 172
 174
$212
 $187
 $193
Less: net loss attributable to noncontrolling interests—
 —
 (1)
Net income attributable to Portland General Electric Company$193
 $172
 $175
          
Weighted-average shares outstanding (in thousands):          
Basic88,896
 84,180
 78,180
89,215
 89,056
 88,896
Diluted89,054
 84,341
 80,494
89,347
 89,176
 89,054
          
Earnings per share:          
Basic$2.17
 $2.05
 $2.24
$2.38
 $2.10
 $2.17
Diluted$2.16
 $2.04
 $2.18
$2.37
 $2.10
 $2.16
          
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,
 2016 2015 2014
Net income$193
 $172
 $174
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2016 and 2015, and $2 in 20141
 (1) (2)
Comprehensive income194
 171
 172
Less: comprehensive loss attributable to the noncontrolling interests—
 —
 (1)
Comprehensive income attributable to Portland General Electric Company$194
 $171
 $173
      
 Years Ended December 31,
 2018 2017 2016
Net income$212
 $187
 $193
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2018, 2017, and 20161
 (1) 1
Comprehensive income$213
 $186
 $194
      
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,
2016 20152018 2017
ASSETS      
Current assets:      
Cash and cash equivalents$6
 $4
$119
 $39
Accounts receivable, net155
 158
193
 168
Unbilled revenues107
 95
96
 106
Inventories, at average cost:      
Materials and supplies50
 44
53
 52
Fuel32
 39
31
 26
Regulatory assets—current36
 129
61
 62
Other current assets77
 88
90
 73
Total current assets463
 557
643
 526
Electric utility plant:      
Generation4,597
 3,898
4,600
 4,667
Transmission521
 451
580
 547
Distribution3,343
 3,192
3,838
 3,543
General501
 463
611
 550
Intangible572
 556
715
 607
Construction work-in-progress213
 545
346
 391
Total electric utility plant9,747
 9,105
10,690
 10,305
Accumulated depreciation and amortization(3,313) (3,093)(3,803) (3,564)
Electric utility plant, net6,434
 6,012
6,887
 6,741
Regulatory assets—noncurrent498
 524
401
 438
Nuclear decommissioning trust41
 40
42
 42
Non-qualified benefit plan trust34
 33
36
 37
Other noncurrent assets57
 44
101
 54
Total assets$7,527
 $7,210
$8,110
 $7,838
      
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,
2016 20152018 2017
LIABILITIES AND EQUITY   
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities:      
Accounts payable$129
 $98
$168
 $132
Liabilities from price risk management activities—current44
 130
55
 59
Short-term debt—
 6
Current portion of long-term debt150
 133
300
 —
Accrued expenses and other current liabilities254
 259
268
 241
Total current liabilities577
 626
791
 432
Long-term debt, net of current portion2,200
 2,060
2,178
 2,426
Regulatory liabilities—noncurrent958
 928
1,355
 1,288
Deferred income taxes669
 632
369
 376
Unfunded status of pension and postretirement plans281
 259
307
 284
Liabilities from price risk management activities—noncurrent125
 161
101
 151
Asset retirement obligations161
 151
197
 167
Non-qualified benefit plan liabilities105
 106
103
 106
Other noncurrent liabilities107
 29
203
 192
Total liabilities5,183
 4,952
5,604
 5,422
Commitments and contingencies (see notes)

 


 
Equity:   
Shareholders’ equity:   
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding—
 —
—
 —
Common stock, no par value, 160,000,000 shares authorized; 88,946,704 and 88,792,751 shares issued and outstanding as of December 31, 2016 and 2015, respectively1,201
 1,196
Common stock, no par value, 160,000,000 shares authorized; 89,267,959 and 89,114,265 shares issued and outstanding as of December 31, 2018 and 2017, respectively
1,212
 1,207
Accumulated other comprehensive loss(7) (8)(7) (8)
Retained earnings1,150
 1,070
1,301
 1,217
Total equity2,344
 2,258
Total liabilities and equity$7,527
 $7,210
Total shareholders’ equity2,506
 2,416
Total liabilities and shareholders’ equity$8,110
 $7,838
      
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)




Portland General Electric Company
Shareholders’ Equity
  Common Stock 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 Total
Common Stock 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 
Noncontrolling
Interests’
Equity
Shares Amount 
Shares Amount 
Balance as of December 31, 201378,085,559
 $911
 $(5) $913
  $1
Shares issued pursuant to equity-based plans142,780
 1
 —
 —
  —
Stock-based compensation—
 6
 —
 —
  —
Dividends declared ($1.115 per share)—
 —
 —
 (88)  —
Net income (loss)—
 —
 —
 175
  (1)
Other comprehensive (loss)—
 —
 (2) —
  —
Balance as of December 31, 201478,228,339
 918
 (7) 1,000
  —
Issuances of common stock, net of issuance costs of $1210,400,000
 271
       
Shares issued pursuant to equity-based plans164,412
 1
 —
 —
  —
Stock-based compensation—
 6
 —
 —
  —
Dividends declared ($1.18 per share)—
 —
 —
 (102)  —
Net income—
 —
 —
 172
  —
Other comprehensive (loss)—
 —
 (1) —
  —
Balance as of December 31, 201588,792,751
 1,196
 (8) 1,070
  —
88,792,751
 $1,196
 $(8) $1,070
 $2,258
Shares issued pursuant to equity-based plans153,953
 1
 —
 —
  —
153,953
 1
 —
 —
 1
Stock-based compensation—
 4
 —
 —
  —
—
 4
 —
 —
 4
Dividends declared ($1.26 per share)—
 —
 —
 (113)  —
—
 —
 —
 (113) (113)
Net income—
 —
 —
 193
  —
—
 —
 —
 193
 193
Other comprehensive income—
 —
 1
 —
  —
—
 —
 1
 —
 1
Balance as of December 31, 201688,946,704
 $1,201
 $(7) $1,150
  $—
88,946,704
 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
Shares issued pursuant to equity-based plans153,694
 1
 —
 —
 1
Stock-based compensation—
 4
 —
 —
 4
Dividends declared ($1.4275 per share)—
 —
 —
 (128) (128)
Net income—
 —
 —
 212
 212
Other comprehensive income—
 —
 1
 —
 1
Balance as of December 31, 201889,267,959
 $1,212
 $(7) $1,301
 $2,506
                  
See accompanying notes to consolidated financial statements.


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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)


 Years Ended December 31,
 2018 2017 2016
Cash flows from operating activities:     
Net income$212
 $187
 $193
Adjustments to reconcile net income to net cash provided by operating activities:     
Depreciation and amortization382
 345
 321
Deferred income taxes(17) 70
 37
Allowance for equity funds used during construction(11) (12) (21)
Pension and other postretirement benefits30
 24
 28
Decoupling mechanism deferrals, net of amortization(2) (22) (6)
Deferral of net benefits due to Tax Reform45
 —
 —
Other non-cash income and expenses, net21
 31
 12
Changes in working capital:     
(Increase) in receivables and unbilled revenues(29) (3) (9)
(Increase) decrease in margin deposits(5) (3) 25
Increase in payables and accrued liabilities51
 5
 15
Other working capital items, net(11) 1
 (4)
Contribution to non-qualified employee benefit trust(11) (8) (10)
Contribution to pension and other postretirement plans(12) (5) (2)
Other, net(13) (13) (17)
Net cash provided by operating activities630
 597
 562
Cash flows from investing activities:     
Capital expenditures(595) (514) (584)
Purchases of nuclear decommissioning trust securities(12) (18) (25)
Sales of nuclear decommissioning trust securities15
 21
 27
Proceeds from Carty Settlement120
 —
 —
Other, net1
 (3) (3)
Net cash used in investing activities(471) (514) (585)
      
See accompanying notes to consolidated financial statements.



 Years Ended December 31,
 2016 2015 2014
Cash flows from operating activities:     
Net income$193
 $172
 $174
Adjustments to reconcile net income to net cash provided by operating activities:     
Depreciation and amortization321
 305
 301
Deferred income taxes37
 40
 39
Allowance for equity funds used during construction(21) (21) (37)
Pension and other postretirement benefits28
 34
 33
Regulatory deferral of settled derivative instruments2
 2
 10
Unrealized losses on non-qualified benefit plan trust assets5
 6
 7
Decoupling mechanism deferrals, net of amortization(6) 14
 6
Other non-cash income and expenses, net5
 20
 14
Changes in working capital:     
(Increase) decrease in receivables and unbilled revenues(9) (11) 8
Decrease (increase) in margin deposits25
 (22) (2)
Increase (decrease) in payables and accrued liabilities15
 6
 (13)
Other working capital items, net(4) (4) (12)
Cash received to be returned to customers pursuant to the Residential Exchange Program, net of amortization

(6) (1) 13
Contribution to non-qualified employee benefit trust(10) (9) (8)
Contribution to voluntary employees’ benefit association trust(2) (4) (3)
Other, net(20) (7) (10)
Net cash provided by operating activities553
 520
 520
Cash flows from investing activities:     
Capital expenditures(584) (598) (1,007)
Purchases of nuclear decommissioning trust securities(25) (19) (19)
Sales of nuclear decommissioning trust securities27
 22
 17
Distribution from (contribution to) nuclear decommissioning trust—
 50
 (6)
Sales tax refund received - Tucannon River Wind Farm—
 23
 —
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid—
 —
 8
Other, net(3) —
 13
Net cash used in investing activities(585) (522) (994)
See accompanying notes to consolidated financial statements.


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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS, continued
(In millions)


Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Cash flows from financing activities:          
Proceeds from issuance of long-term debt$290
 $145
 $585
$75
 $225
 $290
Payments on long-term debt(133) (442) —
(24) (150) (133)
Proceeds from issuances of common stock, net of issuance costs—
 271
 —
(Maturities) issuances of commercial paper, net(6) 6
 —
—
 —
 (6)
Dividends paid(110) (97) (87)(125) (118) (110)
Other(7) (4) (4)(5) (7) (16)
Net cash provided by (used in) financing activities34
 (121) 494
Increase (decrease) in cash and cash equivalents2
 (123) 20
Net cash (used in) provided by financing activities(79) (50) 25
Increase in cash and cash equivalents80
 33
 2
Cash and cash equivalents, beginning of year4
 127
 107
39
 6
 4
Cash and cash equivalents, end of year$6
 $4
 $127
$119
 $39
 $6
          
Supplemental disclosures of cash flow information:          
Cash paid for:          
Interest, net of amounts capitalized$104
 $108
 $86
$117
 $110
 $104
Income taxes16
 3
 22
25
 18
 16
Non-cash investing and financing activities:          
Accrued capital additions50
 32
 70
61
 53
 50
Accrued dividends payable30
 28
 23
34
 31
 30
Accrued sales tax refund related to Tucannon River Wind Farm—
 —
 23
Assets obtained under leasing arrangements78
 —
 —
24
 87
 78
See accompanying notes to consolidated financial statements.

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NOTE 1: BASIS OF PRESENTATION

Nature of Operations

Portland General Electric Company (PGE or the Company) is a single, vertically integratedvertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State 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 approximately4,000 square mile, state-approved service area is located entirely within the State of Oregon. PGE’s allocated service area includes 51 incorporated cities, of which Portland and Salem are the largest. As of December 31, 20162018, PGE served approximately 863,000885,000 retail customers with a service area population of approximately 1.9 million, comprising approximately 46% of the population of the state.

As of December 31, 20162018, PGE had2,7522,967 employees, with 783802 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover730747 and 5355 employees and expire March 2020 and August 2017,2022, 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, and those variable interest entities (VIEs) in which PGE has determined it is the primary beneficiary.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 16,17, Jointly-Owned Plan.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 2016 or 2015.

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.

Reclassifications

To conform with the 2018 presentation, PGE has reclassified Unrealized losses on non-qualified benefit plan trust assets of $2 million and $5 million in 2017 and 2016, respectively, to Other non-cash income and expenses, net within the operating section of the Consolidated Statements of Cash Flows. PGE has also reclassified Contribution to pension and other postretirement plans of $5 million and $2 million in 2017 and 2016, respectively, from Other, net to its own line item within the operating section of the Consolidated Statements of Cash Flows.


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Reclassifications

To conform with the 2016 presentation, PGE has reclassified Proceeds received from Trojan spent fuel legal settlement of $6 million to Other, net within the operating activities section, and Proceeds received from insurance recoveries of $3 million and Proceeds from sale of properties of $5 million to Other, net within the investing activities section of the consolidated statement of cash flows for the year ended December 31, 2014.

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 $1$112 million as of December 31, 20162018 and none$30 million as of December 31, 20152017 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 16eight 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.

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

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2016, 2015, and 2014.2018, 2017, or 2016.

Price Risk Management

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

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

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


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

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets and were $8$16 million and $33$11 million as of December 31, 2016

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2018 and 2015,2017, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheetsheets and were $17$48 million and $63$31 million as of December 31, 20162018 and 2015,2017, 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, for use in its generating plants. Fuel inventories includewhich includes natural gas, coal, and oil.oil for use in the Company’s generating plants. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventoryit is recorded at the lower of average cost or market.net realizable value.

Electric Utility Plant

Capitalization Policy

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

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the CompanyPGE 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. 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% in 2018, 2016 and 20152017, and 7.4% in 20142016. AFDC from borrowed funds was $6 million in 2018 and 2017, and $11 million in 2016, $13 million in 2015, and $22 million in 2014 and is reflected as a reduction to Interest expense.expense, net. AFDC from equity funds, included in Other income, net, was $2111 million in 20162018 and, $12 million in 20152017, and $37$21 million in 2014.2016.

On July 29, 2016, PGE placed Carty into service, a baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to the Boardman coal-fired generating plant (Boardman). As of December 31, 2016, PGE had $634 million included in Electric utility plant for Carty. On November 3, 2015, the OPUC issued an order approving settlements reached in PGE’s 2016 GRC filing, including capital costs of up to $514 million, including AFDC, for Carty and that Carty would be included in customer prices when the plant was placed in service, provided that

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occurred by July 31, 2016. As Carty was placed in service on July 29, 2016, the Company has been authorized to include in customer prices, effective August 1, 2016, the revenue requirement necessary to allow for recovery of capital costs of up to $514 million, as well as Carty’s operating costs. See Note 17, Contingencies, for further information regarding Carty.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.5%3.6% in 20162018, and 3.6%2017, and 3.5% in 2015 and 2014.2016. 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 recent depreciation study was completed for 2013,2015, with an order received from the OPUC in September 20142017 authorizing new depreciation rates effective January 1, 2015. In December 2016, a depreciation2018. This study was completed, which will be incorporated into the Company’s planned 2018 general rate case to be filed with the OPUC by the endin 2017.


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Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’sPGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years):
Generation, excluding thermal: 
Hydro9599
Wind30
Transmission5759
Distribution4546
General12

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 $257302 million and $227296 million as of December 31, 20162018 and 20152017, respectively, with amortization expense of $4459 million in 20162018, and $38$46 million in 20152017 and $25$44 million in 20142016. Future estimated amortization expense as of December 31, 20162018 is as follows: $4560 million in 2017;2019;$52 million in 2020; $44 million in 20182021; $38 million in 20192022; and $3429 million in 2020; and $22 million in 20212023.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading.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 plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund

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assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold is based on the average cost 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 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 the Company’sPGE’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE The Company

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periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’sPGE’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 mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecastedbetween: i) net variable power costs (NVPC) forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income;income, and is net of ii) 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 thatthe 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 2016, 9.68%2018, and 9.6% for 2015,2017 and 9.75% for 2014.2016.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in the Company’sPGE’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the

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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 a market-risk premiumpremiums are not available. The present value of estimated future dismantlement and restorationdecommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

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


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The difference between the timing of the recognition of the AROs’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, 2018, PGE had a net regulatory liability related to Utility plant AROs in the amount of $49$53 million asand a net regulatory asset related to Trojan decommissioning ARO activities of $25 million. As of December 31, 20162017, PGE had a net regulatory liability related to Utility plant AROs in the amount of $52 million and $45 million asa net regulatory liability related to Trojan decommissioning ARO activities of December 31, 2015.$3 million. For additional information concerning the Company’s regulatory liability 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.

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, disclosuredetermined, then the Company: i) discloses an estimate of such loss or the range of such loss, contingency includes a statementif the Company is able to determine such an estimate; or ii) discloses that effectan 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.

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

For additional information concerning the Company’s contingencies, see Note 18, Contingencies.

Accumulated Other Comprehensive Loss

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

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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 goods and services provided, are regulated by the Public Utility Commission of Oregon (OPUC) or the Federal Energy Regulatory Commission (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 customers are subject to federal (FERC)the performance obligations; and v) recognizing revenue when or state (OPUC) regulation. 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 $4345 million in 2016 and 20152018, and $42$43 million in 20142017 and 2016.

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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 the time of the last meter read date through the last day of the month, a periodenergy deliveries that has not yet been billed to customers. This amount, which is classified as ofUnbilled revenues in 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 and renewable adjustment clause (RAC) mechanisms are considered earned under alternative revenue programs, in accordance with the new revenue standard. 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, as these amounts represent a contract with the regulator and not with customers. The activity within this line item is comprised of current period deferral 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 that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory assetsliabilities of $86$267 million and $277 million as of December 31, 20162018, and as of 20152017, respectively, and will 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

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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.


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Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively (full retrospective method) or as a cumulative-effect adjustment as of the effective date (modified retrospective method), which is January 1, 2018 for calendar year-end public entities. The Company is evaluating which transition method it will elect. The Company does not anticipate any material changes to its revenue policy for tariff-based revenues, which comprises a majority of PGE’s retail revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to evaluate the impacts the new guidance may have on its consolidated financial position, consolidated results of operations, and consolidated cash flows, particularly related to recognizing revenue for certain contracts where collectibility may be in question, the extent to which certain transactions such as contributions in aid of construction (CIAC) are within the scope of the standard, certain matters of presentation of alternative revenue programs (such as decoupling), wholesale, and other operating revenue contracts.

In February 2016, the FASBFinancial Accounting Standards Board (FASB) issued ASUAccounting Standards Update (ASU) 2016-02, Leases (Topic 842), which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. 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 (ROU) 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

The new standard provides optional practical expedients in transition. PGE does not expect to elect the ‘package of practical expedients’ that would allow the Company to carryforward the historical lease classification, but instead, PGE has elected to reassess all arrangements that may contain a lease and their resulting lease classification. PGE is substantially complete with this reassessment, and as a result, certain arrangements will no longer be considered a lease under Topic 842. PGE does not expect to elect the use-of-hindsight practical expedient. The new standard also provides practical expedients for an entity’s ongoing accounting. PGE currently expects to elect the short-term lease recognition exemption for all leases that qualify, which means leases with initial terms of 12 months or less will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expensenot be recorded 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 and must be applied onbalance sheet.

As issued, ASU 2016-02 requires transition under a modified retrospective basis as of the beginning of the earliest comparative period presented. Thepresented; however in July 2018, the FASB issued ASU 2018-11, Leases (Topic 842) Targeted Improvements, which amends ASU 2016-02 to provide entities an optional transition practical expedient that allows companies to adopt the new standard also provides reporting entitieswith a cumulative effect adjustment as of the optionbeginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. PGE plans to elect this practical expedient and does not expect a packagematerial adjustment to beginning retained earnings. 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 840. PGE plans to elect this practical expedient, and after adoption will evaluate new or modified land easements under Topic 842. The provisions of practical expedientsthese pronouncements are effective for existing leases that commenced before the effective date.calendar year-end, public entities on January 1, 2019. Early adoption is permitted. permitted, but the Company does not plan to early adopt.

The Company does not expect this standard to have a material effect on the Company’s financial position. While PGE continues to assess all of the effects of adoption, PGE currently anticipates the most significant effects as a lessee relate to: i) the recognition of new ROU assets and lease liabilities on its balance sheet, which are expected to range from $40 million to $50 million; ii) the derecognition of existing build-to-suit assets and liabilities of approximately $131 million that are no longer considered to meet build-to-suit criteria under Topic 842 and will not be recognized on the Company’s balance sheet until commencement, which is expected in the spring of 2019; iii) the derecognition of approximately $50 million in net lease assets and liabilities related to existing capital leases that do not meet the definition of a lease under the new standard; and iv) providing new disclosures regarding key information about leasing arrangements. The Company does not expect this standard to have a material impact to its results of operations, cash flows, or liquidity measures, such as debt covenant ratios.

In February 2018, the FASB issued ASU 2018-02 Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). ASU

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2018-02 allows for a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects resulting from the United States Tax Cuts and Jobs Act of 2017 (TCJA). The amendments only relate to the reclassification of the income tax effects of the TCJA, and therefore the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2019, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. PGE has determined that ASU 2018-02 will not have a material impact on its financial position and does not plan to early adopt the standard.

In August 2018, the FASB issued 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 disclosure. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2020, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in an interim period. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the consolidated financial statements and is still evaluating if it will early adopt.

In August 2018, the FASB issued 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. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2021, early adoption is permitted. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the consolidated financial statements and is still evaluating whether it will early adopt.

In August 2018, the FASB issued ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2020, early adoption is permitted, including adoption in an interim period. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PGE is in the process of evaluating potential impacts of these amendments, and whether it will early adopt.

Recently Adopted Accounting Pronouncements

On January 1, 2018, PGE adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which created Topic 606 and superseded the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The Company applied the modified retrospective transition method to its revenue contracts not yet completed as of January 1, 2018. As a result, amounts previously recorded prior to January 1, 2018 have not been retrospectively restated and are reported in accordance with historical accounting under Topic 605, while revenues for 2018 have been presented under Topic 606.

PGE’s transition to the new revenue standard did not result in a material adjustment to opening retained earnings and the Company expects the adoption of the new standard to have an immaterial impact to its results of operations on an ongoing basis. In accordance with the new provisions of Topic 606, PGE has included enhanced quantitative and qualitative disclosures, such as disaggregated revenues by customer class. Adoption of the new standard also resulted in a change to PGE’s presentation and classification of its alternative revenue programs, which are predominately comprised of the decoupling and RAC mechanisms. Pursuant to the new standard, such revenues should be presented separately from revenues from contracts with customers as these amounts represent a contract

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with the regulator and not with customers. As a result, $3 million, net of amortization, primarily related to PGE’s decoupling mechanism, has been classified as Alternative revenue programs, net of amortization in the consolidated statements of income as of December 31, 2018. If PGE had not applied the new provisions of Topic 606, then PGE would have reported Revenues, net of $1,991 million under Topic 605 for the year ended December 31, 2018, with the difference attributable to the presentation and classification of alternative revenue programs. For further information regarding changes to the Company’s revenue recognition accounting policies, see Note 3, Revenue Recognition.

On January 1, 2018, PGE adopted ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. On a prospective basis, only the service cost component of net periodic pension and postretirement benefit costs is eligible for capitalization to Electric utility plant, net. However, for ratemaking purposes the Company will continue to be allowed to recover its non-service costs related to capital projects as a component of rate base. Instead of recording such amounts to Electric utility plant, net, the Company will record a Regulatory asset on the consolidated balance sheet that will be amortized in a systematic and rational manner. As of December 31, 2018, the Company has recorded $3 million of the non-service costs component of net periodic pension and postretirement benefit costs as a Regulatory asset. The new pronouncement also requires, on a retrospective basis, that the non-service cost component of net periodic pension and postretirement benefit costs attributable to expense be presented separately from the service cost component and outside the subtotal of income from operations on the consolidated statements of income. As of December 31, 2018, the portion of non-service costs attributable to expense is $5 million, classified as Miscellaneous income (expense), net within Other income on the Company’s consolidated statements of income. To conform to the 2018 presentation, PGE has retrospectively reclassified $4 million and $7 million, respectively, of the non-service costs component for the years ended December 31, 2017 and December 31, 2016 from Administrative and other within Operating expenses to Miscellaneous income (expense), net within Other income. The implementation of ASU 2017-07 has had an immaterial impact on PGE’s consolidated financial position and consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02.operations.

In August 2016, the FASB issuedOn January 1, 2018, PGE adopted ASU 2016-15, Statement of Cash Flows (Topic 230),: Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15), with the intention to reducewhich provided guidance for eight specific cash flow issues where there had historically been diversity in practice, as well as simplify elementspractice. The eight areas of classification within the statement of cash flows for certain transactions. The new ASU prescribes specific clarification guidance for the following eight classes of transactions:flow impacted were debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance (COLI) policies, distributions received from equity method investments, beneficial interest in securitization transactions, and separately identifiable cash flows and application of the predominance principal. The standard required a retrospective transition approach, and as such, PGE has reclassified $9 million from Other, net within the Cash flows from operating activities to Other, net within the Cash flows from financing activities on the consolidated statements of cash flows for the year ended December 31, 2016. The standard did not have a material impact to PGE for any other area for which guidance was provided on the statement of cash flows. The implementation of ASU 2016-15 has had an immaterial impact on PGE’s consolidated financial position and consolidated results of operations.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The ASU is intended to simplify the application of hedge accounting and provide increased transparency as to the scope and results of hedging programs. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2019, and interim periods within those fiscal years. PGE early adopted the standard in April 2018 and requires application using a retrospective transition method. Earlyapplied its provisions to the Company’s interest rate swaps that were entered into in 2018 and are designated as cash flow hedges to hedge portions of consolidated interest rate risk associated with anticipated issues of fixed-rate, long-term debt securities. The current impact of this adoption is permitted. The Company is inimmaterial to PGE’s consolidated financial statements as the processmajority of evaluating the impacts of adoption of ASU 2016-15PGE’s price risk management derivatives are related to the presentation of consolidated cash flows.electric and natural gas commodity price economic hedges that are deferred for ratemaking purposes.

Recently Adopted Accounting Standard
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In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (ASU 2015-03), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as aNOTE 3: REVENUE RECOGNITION

Disaggregated Revenue

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

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 Year Ended
December 31, 2018
Retail: 
Residential$948
Commercial647
Industrial185
Direct access customers43
Subtotal1,823
Alternative revenue programs, net of amortization3
Other accrued (deferred) revenues, net(1)
(45)
Total retail revenues1,781
Wholesale revenues(2)
159
Other operating revenues51
Total revenues$1,991

direct deduction from(1) Amount primarily related to the carrying amountregulatory liability deferral of that debt liability, consistent with debt discounts. The Company has retrospectively adopted the provisions of ASU 2015-03 as of January 1, 2016, which was2018 net tax benefits due to the original effective datechange in corporate tax rate under the TCJA. For further information, see Note 12, Income Taxes.
(2) Wholesale revenues include $42 million related to electricity commodity contract derivative settlements for calendar year-end, public entities. As a result, unamortized debt expense of $11 million atthe year ended December 31, 2015 has been reclassified2018. Price risk management derivative activities are included within Total revenues but do not represent revenues from Other noncurrent assetscontracts with customers pursuant to a deductionTopic 606. For further information, see Note 6, Risk Management.

Retail Revenues

The Company’s primary revenue source is generated through the sale of Long-term debt, netelectricity to customers based on 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), manufactured homes, and small farms. Residential demand is sensitive to the effects of current portionweather, with demand highest during the winter heating season and summer cooling season. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. Commercial customers include most businesses, small industrial companies, and public street 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 the consolidated balance sheets. Unamortized debt expense at December 31, 2016 is also $11 million. Adoption ofenergy use by this guidance had no impactcustomer class.
In accordance with state regulations, PGE’s retail customer prices are based on the Company’s consolidated resultscost of operations or consolidated cash flows. In August 2015,service and are determined through general rate case proceedings and various tariff filings with the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation of Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (ASU 2015-15), which clarifies that the SEC staff would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement” given the lack of guidance on this topic in ASU 2015-03. Therefore, as allowed under this update,OPUC. Additionally, the Company records debt issuance costs associated withoffers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options for residential and small commercial customers.
PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct goods 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 line-of-credit arrangements as an asset within Other current assets, and amortizesprogress towards satisfactorily completing its performance obligations to transfer each distinct delivery of electricity in the costs overseries to the term of the agreement.customer.

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Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for the benefit of 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 May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), which removes the requirement to categorize within the fair value hierarchy investments for which fair valuethese arrangements, PGE is measured using the net asset value per share as a practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligibleconsidered to be measured at fair value usingan 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 asset value per share as a practical expedient. Instead, such disclosuresbasis and are restricted only to investments that the entity has decided to measure using the practical expedient. The Company has retrospectively adopted the provisions of this update as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, certain investments have been retrospectively reclassified within the Company’s fair value disclosures of its Nuclear decommissioning trust and Non-qualified benefit plan trust. See Note 4, Fair Value of Financial Instruments for more information. Also, certain benefit plan assets have been reclassified by the Company as seennot reflected in Note 10, Employee Benefits. The adoption of this guidance had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is designed to simplify the presentation and accounting for certain income tax effects, employer tax withholding requirements, forfeiture assumptions, and statement of cash flows presentation related to share-based payment awards. PGE has early adopted the provisions of this ASU effective January 1, 2016. The main provisions include the following:
On a prospective basis, all excess tax benefits and deficiencies are recognizedRevenues, net within the consolidated statements of incomeincome.
Wholesale Revenues
PGE participates in the year incurred, as opposedwholesale electricity marketplace in order to equity, and shall be classified as operating activitiesbalance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the consolidated statements of cash flows. As a result of adoption, PGE recognized less than $1 million of excess tax benefits relatedwestern United States serve utilities with diverse load requirements and allow the Company to its share-based payment awards, which was recorded as a reduction of Income tax expense in the consolidated statements of income for the period ended December 31, 2016.
Reporting entities are now allowed to make a policy election regarding its accounting for forfeitures either by estimating the number of awards that are expected to vest or account for forfeitures when they occur. PGE’s stock compensation expense will continue to reflect estimated forfeitures.
On a retrospective basis, cash paid on behalf of employees related to restricted shares withheld for tax purposes shall now be classified as a financing activity in the statement of cash flows. In the consolidated statements of cash flows for the twelve months ended December 31, 2015purchase and 2014, PGE has retrospectively reclassified $3 million and $2 million, respectively, from Other non-cash income and expenses, net within operating activities to Other financing outflow activities. For the twelve months ended December 31, 2016, $3 million is reflected as an outflowsell electricity within the financing activities section.region depending upon the relative price and availability of power, hydro and wind conditions, and daily and seasonal retail demand.
The majority of PGE’s wholesale electricity sales is to utilities and power marketers, is predominantly short-term, and consists of a single performance obligation 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 resales, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.


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NOTE 3:4: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $615 million as of December 31, 20162018 and 2015.$6 million as of December 31, 2017. The following is the activity in the allowance for uncollectible accounts (in millions):
 
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Balance as of beginning of year$6
 $6
 $6
$6
 $6
 $6
Increase in provision5
 6
 6
14
 6
 5
Amounts written off, less recoveries(5) (6) (6)(5) (6) (5)
Balance as of end of year$6
 $6
 $6
$15
 $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 (NDT) 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 (NQBP) and represents contributions made by the Company, less qualified expenditures, plus any realized and unrealized gains and losses on the investment held therein.


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The trusts are comprised of the following investments as of December 31 (in millions):
 
Nuclear
    Decommissioning Trust    
 
    Non-Qualified Benefit    
Plan Trust
Nuclear
    Decommissioning Trust    
 
    Non-Qualified Benefit    
Plan Trust
2016 2015 2016 20152018 2017 2018 2017
Cash equivalents$21
 $18
 $1
 $1
$7
 $25
 $2
 $1
Marketable securities, at fair value:              
Equity securities—
 —
 6
 5
—
 —
 6
 7
Debt securities20
 22
 1
 1
35
 17
 1
 1
Insurance contracts, at cash surrender value—
 —
 26
 26
—
 —
 27
 28
$41
 $40
 $34
 $33
$42
 $42
 $36
 $37
              

For information concerning the fair value measurement of those assets recorded at fair value held in the trusts, see Note 4,5, Fair Value of Financial Instruments.


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Other Current Assets and Accrued Expenses and Other Current Liabilities

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

As of December 31,As of December 31,
2016 20152018 2017
Other current assets:      
Prepaid expenses$48
 $43
$54
 $50
Margin deposits8
 33
16
 11
Assets from price risk management activities18
 10
20
 6
Other3
 2
—
 6
$77
 $88
$90
 $73
Accrued expenses and other current liabilities:      
Regulatory liabilities—current$51
 $55
$36
 $31
Accrued employee compensation and benefits52
 51
66
 60
Accrued dividends payable34
 31
Accrued interest payable25
 25
27
 27
Accrued dividends payable30
 28
Accrued taxes payable25
 25
34
 31
Other71
 75
71
 61
$254
 $259
$268
 $241
      

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, 20162018 and 20152017, and. 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 2Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date.

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 2, Summary of Significant Accounting Policies, assetsAssets 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, and prior period amounts have been retrospectively reclassified to conform to current presentation.


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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 no significant transfers between levels during the years ended December 31, 20162018 and 20152017, 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, 2016As of December 31, 2018
Level 1 Level 2 Level 3 
Other(2)
 TotalLevel 1 Level 2 Level 3 
Other(2)
 Total
Assets:                  
Cash equivalents$112
 $—
 $—
 $—
 $112
Nuclear decommissioning trust: (1)
                  
Debt securities:                  
Domestic government$2
 $10
 $—
 $—
 $12
7
 18
 —
 —
 25
Corporate credit—
 8
 —
 —
 8
—
 10
 —
 —
 10
Money market funds measured at NAV(2)
—
 —
 —
 21
 21
—
 —
 —
 7
 7
Non-qualified benefit plan trust: (3)
                  
Money market funds1
 —
 —
 —
 1
2
 —
 —
 —
 2
Equity securities—domestic4
 —
 —
 —
 4
6
 —
 —
 —
 6
Debt securities—domestic government1
 —
 —
 —
 1
1
 —
 —
 —
 1
Investments measured at NAV:(2)
         
Money market funds—
 —
 —
 —
 —
Collective trust—domestic equity—
 —
 —
 2
 2
Assets from price risk management activities: (1) (4)
         
Price risk management activities: (1) (4)
         
Electricity—
 6
 1
 —
 7
—
 9
 3
 —
 12
Natural gas—
 15
 1
 —
 16
—
 8
 —
 —
��8
$8
 $39
 $2
 $23
 $72
$128
 $45
 $3
 $7
 $183
Liabilities - Liabilities from price risk management activities: (1) (4)
         
Liabilities:         
Interest rate swap derivatives$—
 $4
 $—
 $—
 4
Price risk management activities: (1) (4)
         
Electricity$—
 $6
 $112
 $—
 $118
—
 10
 84
 —
 94
Natural gas—
 42
 9
 —
 51
—
 51
 7
 —
 58
$—
 $48
 $121
 $—
 $169
$—
 $65
 $91
 $—
 $156
                  
     
(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 $2627 million, which are recorded at cash surrender value.
(4)For further information regarding price risk management derivatives, see Note 5, Price6, Risk Management.


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As of December 31, 2015As of December 31, 2017
Level 1 Level 2 Level 3 
Other(2)
 TotalLevel 1 Level 2 Level 3 
Other(2)
 Total
Assets:                  
Cash equivalents$30
 $—
 $—
 $—
 $30
Nuclear decommissioning trust: (1)
                  
Debt securities:                  
Domestic government$6
 $8
 $—
 $—
 $14
$4
 $7
 $—
 $—
 $11
Corporate credit—
 8
 —
 —
 8
—
 6
 —
 —
 6
Money market funds measured at NAV(2)
—
 —
 —
 18
 18
—
 —
 —
 25
 25
Non-qualified benefit plan trust: (3)
                  
Money market funds—
 —
 —
 —
 —
1
 —
 —
 —
 1
Equity securities—domestic3
 —
 —
 —
 3
7
 —
 —
 —
 7
Debt securities—domestic government1
 —
 —
 —
 1
1
 —
 —
 —
 1
Investments measured at NAV:(2)
         
Money market funds—
 —
 —
 1
 1
Collective trust—domestic equity—
 —
 —
 2
 2
Assets from price risk management activities: (1) (4)
         
Price risk management activities: (1) (4)
         
Electricity—
 7
 —
 —
 7
—
 3
 —
 —
 3
Natural gas—
 3
 —
 —
 3
—
 3
 —
 —
 3
$10
 $26
 $—
 $21
 $57
$43
 $19
 $—
 $25
 $87
Liabilities - Liabilities from price risk management activities: (1) (4)
         
Liabilities:         
Price risk management activities: (1) (4)

         
Electricity$—
 $28
 $105
 $—
 $133
$—
 $5
 $130
 $—
 $135
Natural gas—
 144
 14
 —
 158
—
 66
 9
 —
 75
$—
 $172
 $119
 $—
 $291
$—
 $71
 $139
 $—
 $210
                  
     
(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, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.disclosure.
(3)
Excludes insurance policies of $2628 million, which are recorded at cash surrender value.
(4)For further information regarding price risk management derivatives, see Note 5, Price6, Risk Management.

TrustCash 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 the fund’s securities holdings do not exceed 90 days and investors have the ability to redeem the fund’s shares daily at its respective net asset value. These 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 NASDAQ and the New York Stock Exchange.

Assets held in the Nuclear decommissioningNDT and Non-qualified benefit planNQBP 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 treasuryTreasury 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.

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

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broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.


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Equity securities—Equity mutual fund and common stock securities are 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 equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (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.

For 2015 and most of 2016 money market fundsThe NQBP trust is invested in the NQ Plan were valued at NAV as a practical expedient and not included in the fair value hierarchy. As of December 31, 2016 the NQ Plan transitioned to exchange traded government money market funds and areis 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 Plan continues to beis valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Common and collective trust fundsLiabilities from interest rate swap derivatives—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 are recorded at fair value whichin PGE’s consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is representedcalculated by third party brokers according to the terms of the swap derivatives and evaluated by the net asset value as a practical expedient. A majorityCompany for reasonableness. Future cash flows of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as ofinterest rate swap derivatives are equal to the last day on each calendar month, with at least ten days prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classifiedfixed interest rate in the fair value hierarchy as they are valued at NAV as a practical expedient.swap compared to the floating market interest rate multiplied by the notional amount for each period.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk and to reduce volatility in NVPC for the Company’s retail customers. 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 term commodity forwards, futures, and swaps.


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

     Significant Price per Unit     Significant Price per Unit
 Fair Value Valuation Unobservable     Weighted Fair Value Valuation Unobservable     Weighted
Commodity Contracts Assets Liabilities Technique Input Low High Average Assets Liabilities Technique Input Low High Average
 (in millions)       (in millions)      
As of December 31, 2016:        
As of December 31, 2018:As of December 31, 2018:        
Electricity physical forward $—
 $112
 Discounted cash flow Electricity forward price (per MWh) $14.25
 $54.73
 $38.18
 $3
 $84
 Discounted cash flow Electricity forward price (per MWh) $14.60
 $69.00
 $45.00
Natural gas financial swaps 1
 9
 Discounted cash flow Natural gas forward price (per Dth) 1.85
 4.92
 2.64
 —
 7
 Discounted cash flow Natural gas forward price (per Dth) 0.95
 4.64
 1.82
Electricity financial futures 1
 —
 Discounted cash flow Electricity forward price (per MWh) 8.57
 33.60
 25.10
 —
 —
 Discounted cash flow Electricity forward price (per MWh) 20.75
 35.46
 28.63
 $2
 $121
       $3
 $91
      
As of December 31, 2015:        
As of December 31, 2017:As of December 31, 2017:        
Electricity physical forward $—
 $105
 Discounted cash flow Electricity forward price (per MWh) $8.50
 $84.47
 $30.69
 $—
 $130
 Discounted cash flow Electricity forward price (per MWh) $7.79
 $41.23
 $30.95
Natural gas financial swaps —
 14
 Discounted cash flow Natural gas forward price (per Dth) 2.06
 3.70
 2.54
 —
 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) 9.98
 27.36
 19.26
 —
 —
 Discounted cash flow Electricity forward price (per MWh) 7.79
 29.74
 21.74
 $—
 $119
       $—
 $139
      
                    

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, 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 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 Input Position Change to Input Impact on Fair Value Measurement
Market price Buy Increase (decrease) Gain (loss)
Market price Sell Increase (decrease) Loss (gain)


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

Years Ended December 31,Years Ended December 31,
2016 20152018 2017
Net liabilities from price risk management activities as of beginning of year$119
 $100
$139
 $119
Net realized and unrealized losses *
11
 80
(40) 35
Net transfers in to Level 3 from Level 2(1) —
Net transfers out of Level 3 to Level 2(10) (61)(11) (15)
Net liabilities from price risk management activities as of end of year$119
 $119
$88
 $139
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting$11
 $80
$32
 $41
   
     
* Includes nominal $8 million innet realized losses in 20162018 and 2015, respectively.$6 million in 2017.

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, 2016,2018 and 2017, there were $1 million ofno transfers into Level 3 from Level 2, as reflected in the table above. During 2015, there were no significant amounts 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 in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments.

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

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCBs) 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, 20162018, the carrying amount of PGE’s long-term debt was $2,350$2,478 million, net of $11$10 million of unamortized debt expense, and its estimated aggregate fair value was $2,693$2,760 million, consistingall of $2,543 million and $150 millionwhich is classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 20152017, the carrying amount of PGE’s long-term debt was $2,193$2,426 million, net of $11$10 million of unamortized debt expense, and itswith an estimated aggregate fair value of $2,829 million, all of which was $2,455 million, classified as Level 2 in the fair value hierarchy.

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 existing long-term wholesale contracts. Such activitiesWholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions for 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.


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PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in net variable power costsNVPC for its retail customers. Such derivative instruments, recorded at fair value on the consolidated balance sheets, may include forward, futures, swap, and option contracts which are recorded at fair value on the consolidated balance sheet, for electricity, natural gas, oil, 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 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, As of December 31, 
2016 2015 2018 2017 
Current assets:        
Commodity contracts:        
Electricity$6
 $7
 $11
 $3
 
Natural gas12
 3
 7
 3
 
Total current derivative assets18
(1) 
10
(1) 
18
(1) 
6
(1) 
Noncurrent assets:        
Commodity contracts:        
Electricity1
 —
 1
 —
 
Natural gas4
 —
 1
 —
 
Total noncurrent derivative assets5
(2) 
—
(2) 
2
(2) 
—
(2) 
Total derivative assets not designated as hedging instruments$23
 $10
 $20
 $6
 
Total derivative assets$23
 $10
 $20
 $6
 
Current liabilities:        
Commodity contracts:        
Electricity$12
 $36
 $16
 $13
 
Natural gas32
 94
 35
 46
 
Total current derivative liabilities44
 130
 51
 59
 
Noncurrent liabilities:        
Commodity contracts:        
Electricity106
 97
 78
 122
 
Natural gas19
 64
 23
 29
 
Total noncurrent derivative liabilities125
 161
 101
 151
 
Total derivative liabilities not designated as hedging instruments$169
 $291
 $152
 $210
 
Total derivative liabilities$169
 $291
 $152
 $210
 
     
(1)Included in Other current assets on the consolidated balance sheets.
(2)Included in Other noncurrent assets on the consolidated balance sheets.


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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,As of December 31,
2016 20152018 2017
Commodity contracts:        
Electricity8
 MWh 12
 MWh5
 MWh 7
 MWh
Natural gas107
 Dth 124
 Dth123
 Dth 114
 Dth
Foreign currency exchange$22
 Canadian $7
 Canadian$18
 Canadian $21
 Canadian

PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, 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, 20162018, and 2015,2017, gross amounts included as Price risk management liabilities subject to master netting agreements were $115$88 million and $111$136 million, respectively, for which PGE posted collateral of $11 million for 2018 and $14 million,2017, which consisted entirely of letters of credit. As of December 31, 2016,2018, of the gross amounts included, $112$84 million was for electricity and $3$4 million was for natural gas compared to $104$130 million for electricity and $7$6 million for natural gas recognized as of December 31, 2015.2017.

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,Years Ended December 31,
2016 2015 20142018 2017 2016
Commodity contracts:          
Electricity$34
 $72
 $13
$(34) $41
 $34
Natural Gas(56) 103
 72
21
 85
 (56)
Foreign currency exchange—
 1
 —
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 (gains)income, net gains of $1318 million and, net losses of $16082 million, and net gains of $8313 million for the years ended December 31, 2016,2018, 20152017, and 20142016, respectively, have been offset in Net income.offset.

Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 20162018 related to PGE’s derivative activities would bebecome realized as a result of the settlement of the underlying derivative instrument (in millions):
 
2017 2018 2019 2020 2021 Thereafter Total2019 2020 2021 2022 2023 Thereafter Total
Commodity contracts:                          
Electricity$6
 $7
 $7
 $7
 $7
 $77
 $111
$4
 $6
 $6
 $6
 $6
 $55
 $83
Natural gas20
 7
 6
 2
 —
 —
 35
28
 14
 6
 1
 —
 —
 49
Net unrealized loss$26
 $14
 $13
 $9
 $7
 $77
 $146
$32
 $20
 $12
 $7
 $6
 $55
 $132
                          

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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, 20162018 was $164144 million, for which the Company had posted$1448 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 20162018, the cash requirement to either post as collateral or settle the instruments immediately would have been $149$136 million. As of December 31, 20162018, PGE had no posted a nominal amount of cash collateral for derivative instruments with no credit-risk-related contingent features. Cash 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,
2016 20152018 2017
Assets from price risk management activities:      
Counterparty A22% 5%42% 39%
Counterparty B17
 8
15
 —
Counterparty C12
 8
5
 12
Counterparty D8
 10
Counterparty E1
 59
60% 90%62% 51%
Liabilities from price risk management activities:      
Counterparty F66% 36%
Counterparty C7% 10%
Counterparty B5% 10%
Counterparty D56% 62%
78% 56%56% 62%
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.

Interest Rate Risk

PGE has used two forward starting interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance.
The notional amount of the interest rate swaps is $170 million with a mandatory cash settlement date in January 2019.Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. Such amounts are also included as a component of cost of debt for ratemaking purposes.

PGE is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, PGE receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates. Until settlement, the interest rate swaps are carried at fair value as a derivative asset or liability with the corresponding offset recorded as either a regulatory liability or regulatory asset, respectively. The fair value of outstanding interest rate swap

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derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. As of December 31, 2018, the fair value of the interest rate swaps was a $4 million loss, which is recorded in Liabilities from price risk management activities—current on the Company’s consolidated balance sheets.

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):

 
Weighted Average Remaining
Life (1)
 As of December 31,
 2016 2015
 Current Noncurrent Current Noncurrent
Regulatory assets:         
Price risk management (2)
6 years $26
 $120
 $120
 $161
Pension and other postretirement plans (2)
(3) 
 —
 235
 —
 239
Deferred income taxes (2)
(4) 
 —
 86
 —
 86
Debt issuance costs (2)
6 years —
 22
 —
 16
Other (5)
Various 10
 35
 9
 22
Total regulatory assets  $36
 $498
 $129
 $524
Regulatory liabilities:         
Asset retirement removal costs (6)
(4) 
 $—
 $887
 $—
 $837
Trojan decommissioning activities3 years 18
 —
 17
 15
Asset retirement obligations (6)
(4) 
 —
 49
 —
 45
OtherVarious 33
 22
 38
 31
Total regulatory liabilities  $51
(7) 
$958
 $55
(7) 
$928
 Remaining Amortization Period As of December 31,
 2018 2017
 
Earning a Return (1)
 Not Earning a Return Total Total
Regulatory assets:         
Price risk management2035 $—
 $131
 $131
 $204
Pension and other postretirement plans
(2) 
 —
 222
 222
 218
Debt issuance costs2036 —
 16
 16
 19
Trojan decommissioning activities2039 26
 —
 26
 —
OtherVarious 53
 14
 67
 59
Total regulatory assets  $79
 $383
 $462
 $500
Regulatory liabilities:         
Asset retirement removal costs
(3) 
 $979
 $—
 $979
 $933
Deferred income taxes
(4) 
 267
 —
 267
 277
Trojan decommissioning activities2019 1
 —
 1
 3
Asset retirement obligations
(3) 
 53
 —
 53
 52
Tax Reform Deferral (5)
2020 45
 —
 45
 —
OtherVarious 39
 7
 46
 54
Total regulatory liabilities  $1,384
 $7
 $1,391
 $1,319
(1)
AsEarning a return includes either interest on the regulatory asset or liability, or inclusion of December 31, 2016.
the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return.
(2)Does not include a return on investment.
(3)Recovery expected over the average service life of employees.
(4)(3)Recovery or refund expected over the estimated lives of the assets.net balance and treated as a reduction to rate base.
(4)Will be returned to customers using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base.
(5)
OfRelated to the total other unamortized regulatory asset balances, a return is recorded on $44 million and $29 million asdeferral of December 31, 2016 and 2015, respectively.
the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest.
(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, 2016, PGE had regulatory assets of $44 million earning a return on investment at the following rates: i) $22 million earning a return by inclusion in rate base; ii) $3 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 2.20%, depending on the year of approval; and iii) $19 million at PGE’s 2016 cost of capital of 7.56%.

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.costs. For further information, see Note 10,11, Employee Benefits.

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Deferred income taxes represents income tax benefits resultingprimarily 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 remeasuring accumulated deferred income taxes (ADIT) pursuant to the enactment of the Tax Cuts and Jobs Act (the TCJA) on December 22, 2017. 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 would have occurred before the change in tax law. The Company uses the average rate assumption method to account for the refund to customers. For further information, see Note 11,12, Income Taxes. On December 4, 2018, the OPUC approved PGE’s application for deferral of 2018 net benefits associated with the U.S. Tax Reconciliation Act, docketed in UM 1920, for the 12-month period beginning December 31, 2017, at an amount of $45 million.

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

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 activities represents proceeds received for the settlement of a legal matter concerning the reimbursement from the United States Department of Energy (USDOE) of certain monitoring costs incurred related to spent nuclear fuel at Trojan, as well as ongoing costs and collections associated with decommissioning activities. The USDOE settlement proceeds will be returned to customers over a three-year period that began January 1, 2015 and offset amounts previously collected from customers in relation to Trojan decommissioning activities.

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.

NOTE 7:8: ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):
As of December 31,As of December 31,
2016 20152018 2017
Trojan decommissioning activities$44
 $43
$68
 $45
Utility plant105
 97
112
 109
Non-utility property12
 11
17
 13
Asset retirement obligations$161
 $151
$197
 $167
   

Trojan decommissioning activities represents the present value of future decommissioning costs for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the ISFSI, an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI is to house the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a USDOE facility is complete, which is not expected prior to 2034. The NRC has mandated an increase in staffing for the next 16 years that has led to an increase in the Trojan ARO by $23 million in the first

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quarter of 2018. The Company also recorded accretion of $4 million and a reduction of $4 million due to settled liabilities.

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE, which holds a 67.5% ownership interest in Trojan, had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs 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 agreed to reimbursehas reimbursed the Plaintiffs $81$89 million for costs incurred through 20152017 resulting

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from USDOE delays in accepting spent nuclear fuel. The Plaintiffs have received cumulative cash reimbursements of $79 million and expect to receive $2 million in 2017.

PGE has received proceeds of $50 million related to its share in this legal matter and expects to receive $1 million in 2017. 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.

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 2016,2018, the Company recorded an overall increase in utility AROs including Trojan, of $9$3 million, with the change comprised of an increase to revisions in estimated cash flows and incurred liabilities of $6 million, accretion of $6$4 million, and a reduction of $3$1 million due to settled liabilities.

In 2016, PGE decreased its ARO related to Boardman by $3 million due to changes in the timing of estimated settlement, with corresponding decreases in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. In 2015, PGE increased its ARO related to Boardman by $9 million, due primarily to changes in timing of estimated settlements and due to the acquisition of additional interests in Boardman. For additional information regarding the Company’s interests in Boardman, see Note 16, Jointly-owned Plant.

The United States Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCRs) under the Resource Conservation and Recovery Act, Subtitle D. The rule imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plant sites and not closed. The requirements for covered CCR impoundments and landfills under the final rule include commencement or completion of closure activities generally between three and ten years from certain triggering events.

The Boardman coal-fired generating plant (Boardman) produces dry CCRs as a by-product. Disposal of the dry CCRs has historically occurred at an on-site landfill that is permitted and regulated by the State of Oregon under requirements similar to the final EPA rule. PGE has determined that it will continue use of the on-site landfill in compliance with the new rule, and the Company believes the final EPA rule will not have a material effect on operations at Boardman.

In 2016, the Company recorded an increase in the ARO related to Colstrip of $6 million related to updated decommissioning estimates, with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet new regulatory requirements. As a result, in 2015, the Company recorded an increase to the Colstrip AROs in the amount of $17 million. PGE plans to seek recovery in customer prices of the incremental costs associated with the final EPA rule.

In 2016 and 2015, PGE also recorded an increase in AROs totaling $3 million and $4 million, respectively, related to the Company’s Beaver natural gas-fired generating plant (Beaver) and Carty.

Non-utility property primarily represents AROs which have been recognized for portions of unregulated properties leased to third parties. The Company recorded a revision in non-utility AROs of $4 million.

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The following is a summary of the changes in the Company’s AROs (in millions):
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Balance as of beginning of year$151
 $116
 $100
$167
 $161
 $151
Liabilities incurred1
 2
 15
—
 2
 1
Liabilities settled(3) (4) (3)(5) (3) (3)
Accretion expense7
 7
 6
8
 7
 7
Revisions in estimated cash flows5
 30
 (2)27
 —
 5
Balance as of end of year$161
 $151
 $116
$197
 $167
 $161

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

PGE maintains a separate trust account, Nuclear decommissioning trust in the consolidated balance sheet, for funds collected from customers through prices to cover the cost of Trojan decommissioning activities. See “Trust Accounts” in Note 3,4, Balance Sheet Components, for additional information on the Nuclear decommissioning trust.NDT.


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

NOTE 8:9: CREDIT FACILITIES

As of December 31, 2016,2018, PGE had a $500 million revolving credit facility scheduled to expire inNovember 2019.

2021. On January 16, 2019 PGE executed an amendment to the credit facility extending the termination date to November 14, 2022 and allowing 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, 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 allows for two, one-year extensions subject to approval by the banks, 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, 20162018, PGE was in compliance with this covenant with a 51.0%51.5% debt to total capital ratio.

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.

PGE 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, 2016,2018, PGE had no borrowings outstanding and there waswere no commercial paper or letters of credit issued. As a result, as of December 31, 2016,2018, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

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In addition, PGE hasfour letter of credit facilities that provide capacity up to a total of $160$220 million capacity 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, $56$84 million of letters of credit was outstanding,were issued, as of December 31, 2016.2018. Letters of credit issued are not reflected on the Company’s consolidated balance sheets.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount up to $900 million through February 6, 20182020.

Short-term borrowings under these credit facilities and related interest rates were as followsare reflected in the following table (dollars in millions):. The Company had no short-term borrowings during 2018.
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Average daily amount of short-term debt outstanding$1
 $—
 $—
$—
 $—
 $1
Weighted daily average interest rate *0.7% 0.6% —%—% —% 0.7%
Maximum amount outstanding during the year$23
 $11
 $—
$—
 $—
 $23
     
*Excludes the effect of commitment fees, facility fees and other financing fees.


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NOTE 9:10: LONG-TERM DEBT
Long-term debt consists of the following (in millions):
As of December 31,As of December 31,
2016 20152018 2017
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 4.86% in 2016 and 5.29% in 2015, due at various dates through 2048
$2,090
 $2,083
Unsecured term bank loans, variable rates of approximately 1.37% due 2017
150
 —
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 5.01% in 2018 and 5.03% in 2017, due at various dates through 2048
$2,390
 $2,315
Pollution Control Revenue Bonds, 5% rate, due 2033
142

142
119

142
Pollution Control Revenue Bonds owned by PGE(21) (21)(21) (21)
Total long-term debt2,361
 2,204
2,488
 2,436
Less: Unamortized debt expense(11) (11)(10) (10)
Less: Current portion of long-term debt(150) (133)(300) —
Long-term debt, net of current portion$2,200
 $2,060
$2,178
 $2,426
   

First Mortgage Bonds and Unsecured term bank loans—During 2016, PGEDecember 2018, the Company issued a total of $140 million of FMBs and repaid long-term debt, in an aggregate amount of $133 million.

In January 2016, the Company issued $140 million of 2.51% Series FMBs due 2021 and repaid $58 million of 3.81% Series FMBs, due in 2017 and $75 million at an interest rate of 5.80% Series FMBs due in 2018. Due to the anticipated repayment4.47%, and a maturity of this $133 million in early January 2016, this amount of long-term debt was classified as current on the Company’s consolidated balance sheets as of December 31, 2015.2048.

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.


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In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained the following term loans:

$50 million on May 4, 2016;

$75 million on June 15, 2016; and

$25 million on October 31, 2016.

The term loan interest rates are 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, approximately 1.37% as of December 31, 2016, with no other fees.

The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults and other customary defaults for financings of this type.

Pollution Control Revenue Bonds—The Company has the option to remarket through 2033 the $21 million of PCBsPollution Control Revenue Bonds (PCBs) held by PGE as of December 31, 20162018. At the time of any remarketing, the Company can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing. The PCBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on PCBs. The Company repaid $24 million of Pollution Control Revenue Bondsthat were early redeemed in October 2018.

As of December 31, 20162018, the future minimum principal payments on long-term debt are as follows (in millions):
Years ending December 31:    
2017 $150
2018 —
2019 300
 $300
2020 —
 —
2021 160
 160
2022 —
2023 —
Thereafter 1,751
 2,028
 $2,361
 $2,488
  

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 was closed to new employees.

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

PGE made no contributions to the pension plan in 2016, 2015, and 2014. PGE expects to contribute $3 million to the pension plan in 2017.

appropriate.

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In 2014, the Company offered certain eligible participants in
PGE contributed $9 million to the pension plan in 2018, $2 million in 2017, and nothing in 2016. PGE does not expect to contribute to the option to select a lump sum distribution. As a result of this offering, PGE made lump sum distributions totaling $16 million on July 1, 2014.pension plan in 2019.

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

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

Contributions to the HRAs provide for claims by retirees for qualified medical costs. For bargaining employees employed as of April 9, 2004, the participants’ accounts are credited with 58% of the value of the employee’s accumulated sick time, a stated amount per compensable hour worked, plus 100% of their earned time off accumulated at the time of retirement. For active non-bargaining employees, the Company grants a fixed dollar amount that will become available for qualified medical expenses upon their retirement.

Non-Qualified Benefit PlansPlan—The non-qualified benefit plans (NQBP)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 includeincludes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit planthe 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, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the non-qualified benefit plansNQBP is December 31.

Other NQBP—In addition to the non-qualified benefit plansNQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit planNQBP 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):
2016 20152018 2017
NQBP Other NQBP Total NQBP Other NQBP TotalNQBP Other NQBP Total NQBP Other NQBP Total
Non-qualified benefit plan trust$16
 $18
 $34
 $15
 $18
 $33
$16
 $20
 $36
 $17
 $20
 $37
Non-qualified benefit plan liabilities *25
 80
 105
 25
 81
 106
22
 81
 103
 25
 81
 106
     
*
For the NQBP, excludes the current portion of $2$2 million in 20162018 and in 20152017, which are classified in Other current liabilities in the consolidated balance sheets.

See “Trust Accounts” in Note 3,4, Balance Sheet Components, for information on the Non-qualified benefit planNQBP trust.


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Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of officerscertain members of management from the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation of the asset allocation and oversight of the asset allocation.benefit plan investments. The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities, and other

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alternative investments. The commitmentsAsset classes are regularly rebalanced to each class are controlled by anensure asset deployment and cash management strategy that takes profits from asset classes whose allocations have shifted above their target ranges to fund benefit payments and investments in asset classes whose allocations have shifted below their target ranges.remain within prescribed parameters.
 
The asset allocations for the plans, and the target allocation, are as follows: 
As of December 31,As of December 31,
2016 20152018 2017
Actual Target * Actual Target *Actual Target * Actual Target *
Defined Benefit Pension Plan:              
Equity securities68% 67% 67% 67%65% 67% 68% 67%
Debt securities32
 33
 33
 33
35
 33
 32
 33
Total100% 100% 100% 100%100% 100% 100% 100%
Other Postretirement Benefit Plans:              
Equity securities60% 62% 60% 64%58% 59% 63% 62%
Debt securities40
 38
 40
 36
42
 41
 37
 38
Total100% 100% 100% 100%100% 100% 100% 100%
Non-Qualified Benefits Plans:              
Equity securities15% 11% 15% 14%16% 13% 18% 12%
Debt securities7
 11
 7
 8
10
 13
 6
 12
Insurance contracts78
 78
 78
 78
74
 74
 76
 76
Total100% 100% 100% 100%100% 100% 100% 100%
     
*The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans,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 Non-Qualified Benefit Plans,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 the capitalization ranges and style biases, both domestically and internationally. Fixed income securities include, but are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.

Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 2, Summary of Significant Accounting Policies, assetsAssets measured at fair value using net asset value (NAV)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. As required by this ASU, prior period amounts have been retrospectively reclassified to conform to current presentation, including all of the investments previously classified as Level 3. As a result, the Level 3 reconciliation is no longer applicable for such investments and has been excluded from this footnote.


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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 * TotalLevel 1 Level 2 Level 3 Other * Total
As of December 31, 2016:         
As of December 31, 2018:         
Defined Benefit Pension Plan assets:                  
Equity securities—Domestic$52
 $—
 $—
 $—
 $52
$67
 $—
 $—
 $—
 $67
Investments measured at NAV:                  
Money market funds—
 —
 —
 6
 6
—
 —
 —
 5
 5
Collective trust funds—
 —
 —
 483
 483
—
 —
 —
 463
 463
Private equity funds—
 —
 —
 18
 18
—
 —
 —
 11
 11
$52
 $—
 $—
 $507
 $559
$67
 $—
 $—
 $479
 $546
Other Postretirement Benefit Plans assets:                  
Money market funds$4
 $—
 $—
 $—
 $4
$3
 $—
 $—
 $—
 $3
Equity securities:                  
Domestic—
 3
 —
 —
 3
—
 3
 —
 —
 3
International8
 —
 —
 —
 8
8
 —
 —
 —
 8
Debt securities—Domestic government—
 4
 —
 —
 4
—
 5
 —
 —
 5
Investments measured at NAV:                  
Money market funds—
 —
 —
 4
 4
—
 —
 —
 4
 4
Collective trust funds—
 —
 —
 7
 7
—
 —
 —
 7
 7
$12
 $7
 $—
 $11
 $30
$11
 $8
 $—
 $11
 $30
As of December 31, 2015:         
As of December 31, 2017:         
Defined Benefit Pension Plan assets:                  
Equity securities—Domestic$44
 $—
 $—
 $—
 $44
$83
 $—
 $—
 $—
 $83
Investments measured at NAV:                  
Money market funds—
 —
 —
 5
 5
—
 —
 —
 5
 5
Collective trust funds—
 —
 —
 479
 479
—
 —
 —
 528
 528
Private equity funds—
 —
 —
 22
 22
—
 —
 —
 13
 13
$44
 $—
 $—
 $506
 $550
$83
 $—
 $—
 $546
 $629
Other Postretirement Benefit Plans assets:                  
Money market funds$—
 $—
 $—
 $—
 $—
$3
 $—
 $—
 $—
 $3
Equity securities:                  
Domestic—
 3
 —
 —
 3
—
 3
 —
 —
 3
International8
 —
 —
 —
 8
10
 —
 —
 —
 10
Debt securities—Domestic government—
 5
 —
 —
 5
—
 5
 —
 —
 5
Investments measured at NAV:                  
Money market funds—
 —
 —
 7
 7
—
 —
 —
 4
 4
Collective trust funds—
 —
 —
 7
 7
—
 —
 —
 8
 8
$8
 $8
 $—
 $14
 $30
$13
 $8
 $—
 $12
 $33
                  
     
*Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.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.


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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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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 not directly or indirectly observable in the marketplace.

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, including municipal debt and corporate credit securities, mortgage-backed securities, and asset-backed securities included in commingled trusts are valued at NAV as a practical expedient and not included 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.

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The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plansNQBP as of and for the years ended December 31, 20162018 and 20152017. Information related to the Other NQBP is not included in the following tables (dollars in millions):

Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
2016 2015 2016  2015  2016 20152018 2017 2018  2017  2018 2017
Benefit obligation:                      
As of January 1$758
 $777
 $81
 $83
 $27
 $27
$869
 $797
 $78
 $73
 $27
 $27
Service cost16
 18
 2
 2
 —
 —
19
 17
 2
 2
 —
 —
Interest cost33
 31
 4
 3
 1
 1
32
 33
 3
 3
 1
 1
Participants’ contributions—
 —
 2
 2
 —
 —
—
 —
 2
 2
 —
 —
Actuarial (gain) loss26
 (31) (11) (4) 1
 1
Actuarial loss (gain)(67) 60
 (7) 3
 (1) 1
Contractual termination benefits—
 —
 —
 1
 —
 —
—
 —
 —
 1
 —
 —
Benefit payments(34) (35) (5) (6) (2) (2)(39) (36) (6) (6) (3) (2)
Administrative expenses(2) (2) —
 —
 —
 —
(3) (2) —
 —
 —
 —
As of December 31$797
 $758
 $73
 $81
 $27
 $27
$811
 $869
 $72
 $78
 $24
 $27
Fair value of plan assets:                      
As of January 1$550
 $591
 $30
 $32
 $15
 $15
$629
 $559
 $33
 $30
 $17
 $16
Actual return on plan assets45
 (4) 1
 (2) 1
 —
(50) 106
 (2) 4
 (1) 1
Company contributions—
 —
 2
 4
 2
 2
9
 2
 3
 3
 3
 2
Participants’ contributions—
 —
 2
 2
 —
 —
—
 —
 2
 2
 —
 —
Benefit payments(34) (35) (5) (6) (2) (2)(39) (36) (6) (6) (3) (2)
Administrative expenses(2) (2) —
 —
 —
 —
(3) (2) —
 —
 —
 —
As of December 31$559
 $550
 $30
 $30
 $16
 $15
$546
 $629
 $30
 $33
 $16
 $17
Unfunded position as of December 31$(238) $(208) $(43) $(51) $(11) $(12)$(265) $(240) $(42) $(45) $(8) $(10)
Accumulated benefit plan obligation as of December 31$714
 $681
 N/A N/A $27
 $27
$734
 $778
 N/A N/A $24
 $27
Classification in consolidated balance sheet:                      
Noncurrent asset$—
 $—
 $—
 $—
 $16
 $15
$—
 $—
 $—
 $—
 $16
 $17
Current liability—
 —
 —
 —
 (2) (2)—
 —
 —
 —
 (2) (2)
Noncurrent liability(238) (208) (43) (51) (25) (25)(265) (240) (42) (45) (22) (25)
Net liability$(238) $(208) $(43)  $(51)  $(11) $(12)$(265) $(240) $(42)  $(45)  $(8) $(10)
Amounts included in comprehensive income:                      
Net actuarial loss (gain)$21
 $13
 $(10) $—
 $1
 $1
$25
 $(4) $(4) $—
 $(1) $1
Amortization of net actuarial loss(14) (20) —
 (1) (1) (1)(17) (13) —
 —
 (1) (1)
Amortization of prior service cost—
 —
 (1) (1) —
 —
$7
 $(7) $(11) $(2) $—
 $—
$8
 $(17) $(4) $—
 $(2) $—
Amounts included in AOCL*:                      
Net actuarial loss (gain)$236
 $228
 $(2) $9
 $13
 $13
$226
 $218
 $(4) $(1) $11
 $13
Prior service cost—
 —
 1
 1
 —
 —
—
 —
 —
 —
 —
 —
$236
 $228
 $(1) $10
 $13
 $13
$226
 $218
 $(4) $(1) $11
 $13
                      

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Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
Defined Benefit Pension Plan 
  Other Postretirement  
Benefits
  
Non-Qualified
Benefit Plans
2016 2015 2016  2015  2016 20152018 2017 2018  2017  2018 2017
Assumptions used:                      
Discount rate for benefit obligation4.17% 4.36% 3.75%- 3.90%- 4.17% 4.36%4.25% 3.65% 4.10%- 3.42%- 4.25% 3.65%
    4.23% 4.45%        4.26% 3.70%    
Discount rate for benefit cost4.36% 4.02% 3.90%- 3.07%- 4.36% 4.02%3.65% 4.17% 3.42%- 3.75%- 3.65% 4.17%
    4.45% 4.10%        3.70% 4.23%    
Weighted average rate of compensation increase for benefit obligation3.65% 3.65% 4.58% 4.58% N/A
 N/A
3.65% 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
3.65% 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% 6.29% N/A
 N/A
Long-term rate of return on plan assets for benefit cost7.50% 7.50% 6.29% 6.37% N/A
 N/A
7.00% 7.50% 6.20% 6.26% N/A
 N/A
                      
     
* Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets.

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

Defined Benefit
Pension Plan
 
Other Postretirement
Benefits
 
Non-Qualified
Benefit Plans
Defined Benefit
Pension Plan
 
Other Postretirement
Benefits
 
Non-Qualified
Benefit Plans
2016 2015 2014 2016 2015 2014 2016 2015 20142018 2017 2016 2018 2017 2016 2018 2017 2016
Service cost$16
 $18
 $15
 $2
 $2
 $2
 $—
 $—
 $—
$19
 $17
 $16
 $2
 $2
 $2
 $—
 $—
 $—
Interest cost on benefit obligation33
 31
 34
 4
 3
 4
 1
 1
 1
32
 33
 33
 3
 3
 4
 1
 1
 1
Expected return on plan assets(40) (40) (39) (2) (2) (2) —
 —
 —
(42) (42) (40) (1) (2) (2) —
 —
 —
Amortization of prior service cost—
 —
 —
 1
 1
 1
 —
 —
 —
—
 —
 —
 —
 —
 1
 —
 —
 —
Amortization of net actuarial loss14
 20
 17
 —
 1
 1
 1
 1
 1
17
 13
 14
 —
 —
 —
 1
 1
 1
Net periodic benefit cost$23
 $29
 $27
 $5
 $5
 $6
 $2
 $2
 $2
$26
 $21
 $23
 $4
 $3
 $5
 $2
 $2
 $2
                                  
The portion of non-service costs attributable to expense related to the pension and other postretirement benefit plans, is classified as Miscellaneous income (expense), net within Other income on the Company’s consolidated statements of income. PGE estimates that $1511 million will be amortized from AOCL into net periodic benefit cost in 2017,2019, consisting of a net actuarial loss of $1310 million for pension benefits, $1 million for non-qualified benefits and $1 million for prior service costs for other postretirementnon-qualified benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset.

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):
Payments DuePayments Due
2017 2018 2019 2020 2021 2022 - 20262019 2020 2021 2022 2023 2024 - 2028
Defined benefit pension plan$37
 $39
 $40
 $42
 $43
 $229
$41
 $42
 $44
 $45
 $45
 $238
Other postretirement benefits5
 5
 5
 4
 5
 22
5
 5
 5
 5
 6
 22
Non-qualified benefit plans3
 2
 3
 2
 2
 10
2
 2
 2
 2
 2
 10
Total$45
 $46
 $48
 $48
 $50
 $261
$48
 $49
 $51
 $52
 $53
 $270

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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 2018, 6.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 and 2020, then decreasing 0.25% per year thereafter, reaching5.0% in 2026;

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, reaching 5.0% in 2023; and

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, 6.0% in 2019, then decreasing 0.25% per year thereafter, reaching5% 5.0% in 2023;

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% in 2021; and

For 2014, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019.2023.

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

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company 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 additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees��employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $1923 million in 20162018, $17$21 million in 2015,2017, and $16$19 million in 2014.2016.

NOTE 12: INCOME TAXES

On December 22, 2017, the TCJA was enacted and signed into law with substantially all of the provisions of the TCJA having an effective date of January 1, 2018. The most significant change to PGE’s financial condition was the federal corporate tax rate decrease from 35% to 21%.

PGE proposed to defer and refund the expected net benefits from 2017 and 2018 related to the TCJA under a deferral application filed with the OPUC on December 29, 2017. On December 4, 2018, PGE received OPUC approval to refund a total of $45 million dollars to customers for the 2017-2018 net benefits associated with the TCJA. The refund will begin amortizing in customer prices on January 1, 2019 over a two-year period.

The protected excess deferred income tax is amortized using the average rate assumption method and is included in the 2019 General Rate Case as a refund to customers.

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NOTE 11: INCOME TAXES

Income tax expense consists of the following (in millions):
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Current:          
Federal$10
 $4
 $20
$12
 $4
 $10
State and local3
 1
 2
22
 12
 3
13
 5
 22
34
 16
 13
Deferred:          
Federal23
 26
 26
(15) 61
 23
State and local14
 14
 13
(2) 9
 14
37
 40
 39
(17) 70
 37
Income tax expense$50
 $45
 $61
$17
 $86
 $50
          

The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows:
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Federal statutory tax rate35.0 % 35.0 % 35.0 %21.0 % 35.0 % 35.0 %
Federal tax credits *(18.2) (19.0) (11.4)
Federal tax credits(1)
(16.7) (14.0) (18.2)
Change in federal tax law(2)
—
 6.1
 —
State and local taxes, net of federal tax benefit4.8
 4.2
 3.9
6.5
 5.0
 4.8
Flow through depreciation and cost basis differences0.2
 —
 (2.3)1.5
 1.5
 0.2
Excess deferred tax amortization(3)
(4.1) —
 —
Other(1.2) 0.5
 0.8
(0.8) (2.1) (1.2)
Effective tax rate20.6 % 20.7 % 26.0 %7.4 % 31.5 % 20.6 %
          
     
*(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.conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facility’s in service date.facilities’ in-service dates. PGE’s PTCsPTC generation ended or will endat various dates between 2017 and 2024.

(2) For the year ended December 31, 2017, includes a $17 million increase to Income tax expense related to the remeasurement of deferred income taxes as a result of the enacted tax rate change under the TCJA.
(3) The majority of excess ADIT related to remeasurement under the TCJA is subject to IRS normalization rules and will be amortized over the remaining regulatory life of the assets using the average rate assumption method.

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Deferred income tax assets and liabilities consist of the following (in millions):
As of December 31,  As of December 31,  
2016 20152018 2017
Deferred income tax assets:      
Employee benefits$181
 $170
$134
 $128
Price risk management59
 112
36
 56
Regulatory liabilities29
 42
26
 14
Tax credits56
 46
52
 50
Other5
 —
9
 4
Total deferred income tax assets330
 370
257
 252
Deferred income tax liabilities:      
Depreciation and amortization829
 781
511
 496
Regulatory assets170
 220
115
 132
Other—
 1
Total deferred income tax liabilities999
 1,002
626
 628
Deferred income tax liability, net$(669) $(632)$369
 $376

As of December 31, 2016,2018, PGE has federal credit carryforwards of $56$52 million, consisting of PTCs, which will expire at various dates through 20362038.

PGE has analyzed the provisions of the TCJA and its effects on the Company’s deferred income tax assets, and PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 20162018 and 20152017 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 20162018, and 20152017, PGE had no 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

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).
Employee Stock Purchase Plan

PGE has an employee stock purchase plan (ESPP) under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. 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 stockstock. 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, the last day of the offering period.date. As of December 31, 20162018, there were 369,419306,175 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, 20162018, there were 2,474,1642,467,956 shares available for future issuance pursuant to the DRIP.

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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, andor certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table:
Units 
Weighted Average
Grant Date
Fair Value
Units 
Weighted Average
Grant Date
Fair Value
Outstanding as of December 31, 2013431,090
 $26.31
Granted203,410
 31.49
Forfeited(12,278) 29.90
Vested(158,329) 24.95
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
442,993
 $32.84
Granted193,734
 35.89
193,734
 35.89
Forfeited(3,044) 28.62
(3,044) 28.62
Vested(174,891) 31.47
(174,891) 31.47
Outstanding as of December 31, 2016458,792
 34.68
458,792
 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
Granted198,864
 37.99
Forfeited(8,556) 39.73
Vested(160,771) 36.77
Outstanding as of December 31, 2018428,913
 38.43

A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 3,305,9203,075,440 shares remain available for future issuance as of December 31, 2016.2018.

Outstanding RSUs provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. DERs represent an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vest on the same schedule as the RSUs. The DERs are settled in cash (for grants to non-employee directors) or shares of PGE common stock valued either at the closing stock price on the vesting date (for performance-based RSUs) or

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dividend payment date (for all other grants). The cash from the settlement of the DERs for non-employee directors may be deferred under the terms of the Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan.

Time-based RSUs vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was less than $1 million for the years ended December 31, 20162018, 20152017, and 20142016.

Performance-based RSUs vest if performance goals are met at the end of a three-year performance period. Grants are based on three equally-weighted metrics: i) return on equity relative to allowed return on equity; ii) regulated asset base growth;growth (applicable only for those grants made prior to 2017); and iii) a relative total shareholder return (TSR) of PGE’s common stock as compared to the Edison Electric Institute Regulated Index (EEI Index)an index of peer companies during the performance period. Vesting

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of performance-based RSUs is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors.Directors (Committee). The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committeeCommittee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

For the return on equity and regulated asset base growth portions of the performance-based RSUs, fair value is measured based on the closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions:
2016 20152018 2017 2016
Risk-free interest rate  0.9%   1.0%  2.4%   1.5%   0.9%
Expected dividend yield  —%   —%  —%   —%   —%
Expected term (in years)  3.0
   3.0
  3.0
   3.0
   3.0
Volatility14.5%-25.9% 13.2%-19.2%14.7%-21.8% 15.6%-22.9% 14.5%-25.9%

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 121.2%89.9%, 117.3%97.8%, and 111.2%106.6% of awarded performance-based RSUs for the respective 20162018, 20152017, and 20142016 grants, with an estimated 5% forfeiture rate.

The total value of performance-based RSUs vested was $54 million for the year ended December 31, 20162018, $4$6 million for 20152017, and $3$5 million for 20142016.

Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $6$5 million for the yearsyear ended December 31, 20162018, 2015,$7 million for 2017, and $6 million in 20142016. 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

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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 $2 million in 2016 and 20152018, and $1$3 million in 20142017 and $2 million in 2016.

As of December 31, 20162018, unrecognized stock-based compensation expense was $6 million, of which approximately $4 million and $2 million is expected to be expensed in 20172019 and 20182020, respectively. No stock-based compensation costs have been capitalized and the Plan had no material impact on cash flows for the years ended December 31, 20162018, 20152017, or 20142016.

NOTE 14:15: EARNINGS PER SHARE

Basic earnings per share isare computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share isare 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)of employee stock purchase plan shares; ii)shares and contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the EFSA. During the second quarter 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 per share.rights.

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Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computation. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):
Years Ended December 31,Years Ended December 31,
2016 2015 20142018 2017 2016
Weighted average common shares outstanding—basic88,896
 84,180
 78,180
89,215
 89,056
 88,896
Dilutive effect of potential common shares158
 161
 2,314
132
 120
 158
Weighted average common shares outstanding—diluted89,054
 84,341
 80,494
89,347
 89,176
 89,054

NOTE 15:16: COMMITMENTS AND GUARANTEES

Purchase Commitments

As of December 31, 20162018, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):
 Payments Due
 2017 2018 2019 2020 2021 Thereafter Total
Capital and other purchase commitments$176
 $8
 $2
 $9
 $1
 $60
 $256
Purchased power and fuel:             
Electricity purchases221
 157
 181
 256
 239
 1,750
 2,804
Capacity contracts7
 6
 5
 4
 4
 12
 38
Public utility districts4
 4
 1
 —
 1
 11
 21
Natural gas53
 39
 32
 27
 24
 158
 333
Coal and transportation17
 9
 5
 —
 —
 —
 31
Total$478
 $223
 $226
 $296
 $269
 $1,991
 $3,483


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 Payments Due
 2019 2020 2021 2022 2023 Thereafter Total
Capital and other purchase commitments$143
 $9
 $1
 $1
 $1
 $58
 $213
Purchased power and fuel:             
Electricity purchases167
 190
 186
 194
 193
 1,853
 2,783
Capacity contracts1
 —
 9
 9
 9
 18
 46
Public utility districts12
 11
 9
 8
 8
 35
 83
Natural gas54
 42
 31
 31
 30
 208
 396
Coal and transportation6
 —
 —
 —
 —
 —
 6
Total$383
 $252
 $236
 $243
 $241
 $2,172
 $3,527

Capital and other purchase commitments—Certain commitments have been made for 20172019 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 2049,2041, and power capacity contracts through 2024.2028.

Public utility districts—PGE has long-term power purchase agreements with certain public utility districts (PUDs) in the state of WashingtonWashington:
Grant County PUD for the Priest Rapids and withWanapum projects, and
Douglas County PUD for the City of Portland, Oregon. Wells project.

Under the agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable.operable or not. In addition, although PGE’s old agreement with Douglas County ended on August 31, 2018, a new contract became effective on September 1, 2018 that does not require contributions to Douglas County debt obligation or other costs, including the operation and maintenance costs of the projects. The new contract requires 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’ loads, and included the estimated amounts in the table above. The future minimum payments for the public utility districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses.


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payments for the PUDs in the preceding table reflect the principal and capacity payments only and do not include interest, operation, or maintenance expenses.

Selected information regarding these projects is summarized as follows (dollars in millions):
 
Revenue Bonds as of December 31, 2016 PGE’s Share as of December 31, 2016 
Contract
Expiration
 
PGE Cost,
including Debt Service
Capacity Charges and Revenue Bonds as of December 31, 2018 PGE’s Share as of December 31, 2018 
Contract
Expiration
 PGE Capacity Charges and Debt Service Costs
Output Capacity 2016 2015 2014 Output Capacity 2018 2017 2016
    (in MW)            (in MW)        
Priest Rapids and Wanapum$1,190
 8.6% 163
 2052 $16
 $18
 $14
$1,236
 8.6% 163
 2052 $17
 $16
 $16
Wells177
 19.4
 150
 2018 10
 10
 10
757
 9.0
 135
 2028 11
 11
 10
Portland Hydro—
 100.0
 36
 2017 1
 2
 4
                      

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 rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up toresponsible for a cumulative maximum of 25%pro rata portion of the defaulting purchaser’s percentage.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 has coal and related rail transportation agreements with take-or-pay provisions related to Boardman that expire at various dates through 2020.

Lease Obligations

As of December 31, 2016,2018, 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
2019$6
 $11
 $4
20206
 14
 5
20216
 13
 5
20226
 13
 6
20235
 13
 7
Thereafter67
 225
 97
Total minimum lease payments96
 $289
 $124
Less imputed interest47
    
Present value of net minimum lease payments49
    
Less current portion2
    
Non-current portion$47
    

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 Future Minimum Lease Payments
 Capital Leases Build-to-Suit Operating Leases
2017$7
 $—
 $10
20187
 4
 9
20196
 14
 6
20206
 13
 6
20216
 13
 7
Thereafter77
 237
 177
Total minimum lease payments$109
 $281
 $215
Less imputed interest55
    
Present value of net minimum lease payments$54
    
Less current portion3
    
Non-current portion$51
    


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. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000

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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, 2016,2018, a capital lease asset of $57 million was reflected within Electric utility plant and accumulated amortization of such assets of $3$8 million was reflected within Accumulated depreciation and amortization in the table above.consolidated balance sheets. The present value of the future minimum lease payments due under the agreement included $3$2 million within Accrued expenses and other current liabilities and $51$47 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, amortizationAmortization of the leased asset of $2$3 million and interest expense of $3$4 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, 2016.2018 and 2017.

Build-to-suit—PGE has entered into a 30-year lease agreement with a local natural gas company, NW Natural,to expand their current natural gas storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-mile13-miles of pipeline, which will beare collectively 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, onin September 30, 2016, PGE issued NW Natural a Notice To Proceed with construction of the expansion project, which the gas company estimates construction will be completed during the winterspring of 2018-2019,2019, at a cost of approximately $128$144 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 $21$131 million and $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, 2016. Upon completion2018 and 2017, respectively. Pursuant to the adoption of the facility,new lease accounting standard, Topic 842, PGE will assess whetherplans to derecognize the existing build-to-suit assets and liabilities qualify as they are no longer considered to meet the build-to-suit criteria under the new standard. As a successful sale-leaseback transaction in which theresult, a ROU asset and lease liability are removed and accounted for as either a capital or operating lease. will not be recognized on the Company’s balance sheet until the lease commences, which is expected in the spring of 2019. For additional information regarding the new lease accounting standard, see Note 2, Summary of Significant Accounting Policies.

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.costs.

Operating leases—PGE has various operating leases associated with its headquartersleases of land, support facilities, and certain of its production, transmission, and support facilitiespower purchase agreements that rely on identified plant 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.extending through 2096. Rent expense was $7 million in 2018, $9 million in 2017, and $10 million in 2016 and 2015, and $112016. Contingent rents related to power purchase agreements was $14 millionin 2014.2018.

The future minimum operating lease payments presented is net of subleaseSublease income ofwas $4 million in each of 2017, 2018, 2019,2017, and 2020; and $3 million in 2021. Sublease income was $4 million in 2016, and $3 million in 2015 and 2014.2016.

Guarantees

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 20162018, management believes the likelihood is remote that PGE would be required to perform under such indemnification

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provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.

NOTE 16:17: JOINTLY-OWNED PLANT

As of December 31, 2016,2018, 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
PGE
Share
 In-service Date 
Plant
In-service
 
Accumulated
Depreciation*
 
Construction
Work In
Progress
Boardman90.00% 1980 $514
 $400
 $—
90.00% 1980 $516
 $451
 $—
Colstrip20.00
 1986 528
 342
 9
20.00
 1986 549
 363
 10
Pelton/Round Butte66.67
 1958/1964 255
 63
 5
66.67
 1958/1964 270
 73
 2
Total  $1,297
 $805
 $14
  $1,335
 $887
 $12
     
*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, operating, and leasing costs. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.

NOTE 17:18: CONTINGENCIES

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

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

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the 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 in dispute; vi) there are a large number of parties (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there is a wide range of potential outcomes. In such cases,

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dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential 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

Construction Litigation—In 2013, the CompanyPGE entered into ana turnkey engineering, procurement, and construction agreement (Construction Agreement) with its engineering, procurement and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership an affiliate(collectively, the Contractor), affiliates of Abengoa S.A. (collectively, the “Contractor”) - for the construction of the Carty a baseload natural gas-fired generating plant (Carty) located in Eastern Oregon, located adjacent to Boardman.Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as(together, the “Sureties”)Sureties) provided a performance bond of $145.6 million (Performance Bond) underin connection with the Construction Agreement. PGE, the Contractor, Abengoa S.A., and the Sureties are hereinafter collectively referred to as the Parties.

OnIn December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015.resumed.

On January 28,Carty was placed into service on July 29, 2016 and the Company received noticebegan 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 June 30, 2018, PGE had capitalized $640 million to Electric utility plant.

The excess costs resulted from various matters relating to the International Chamberresumption of Commerce (ICC) International Court of Arbitration that Abengoa S.A. had submitted a request for arbitration. Inconstruction activities following the request, Abengoa S.A. alleged that the Company’s termination of the Construction Agreement was wrongfulAgreement.

The Company sought recovery of excess construction costs and inother damages pursuant to breach of contract claims against the agreement termsContractor and does not give riseclaims against the Sureties pursuant to anythe Performance Bond. The Sureties denied liability of Abengoa S.A.in whole under the terms of a guaranty in favor of PGEPerformance Bond, and pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor underfiled claims against the Construction Agreement. PGE disagrees with the assertions in the request for arbitrationCompany alleging wrongful termination of contract and on February 29, 2016related damages.

Various actions relating to this matter were filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon, seekingin the Ninth Circuit Court of Appeals, and in the International Chamber of Commerce’s Court of Arbitration.

As a result of the foregoing events, PGE incurred a higher cost of service than what is reflected in the current authorized revenue requirement amount, primarily due to havehigher depreciation, interest, and legal expenses. These incremental expenses are recognized in the arbitration claim dismissed onCompany’s current results of operations. Such incremental expenses were $8 million and $14 million for the grounds that the Company has not made a demand under the Abengoa S.A. guaranty,years ended December 31, 2018 and therefore the matter is not ripe for arbitration.2017, respectively.

On March 28, 2016, Abengoa S.A.July 16, 2018, the Parties reached a settlement to resolve all claims relating to Carty construction between the Company and several of its foreign affiliates filed petitions for recognition under Chapter 15each of the U.S. Bankruptcy Code requesting interim relief, including an injunction precludingContractor, Abengoa S.A., and the prosecutionSureties. Under the terms of any proceedingsthe settlement: i) the Sureties paid $130 million to PGE; and ii) the Contractor, Abengoa S.A., and the Sureties released all claims against the Chapter 15 debtors. On March 29, 2016, a numberCompany arising out of Abengoa S.A.’s U.S. subsidiaries, including the four entities that collectively compriseCarty construction, and in return, PGE released all such claims against the Contractor, filed voluntary petitionsAbengoa S.A., and the Sureties.

The Company applied $120 million to reduce Electric utility plant, net for relief under Chapter 11undepreciated incremental construction costs, thus eliminating ongoing excess depreciation and amortization and interest expense with the remaining proceeds of $10 million from the cash settlement applied as a reduction of Administrative and other expenses.

In July 2016, PGE requested from the OPUC a regulatory deferral for the recovery of the U.S. Bankruptcy Code. As a result, on April 5, 2016,revenue requirement associated with the U.S. District Court issued an order statingexcess capital costs for Carty. The Company requested that the Company’s District Court action against Abengoa S.A. was stayed. In early October 2016, the bankruptcy court in the Chapter 11 proceeding granted the Company’s motion for relief from stay with respect to the four entities that collectively comprise the Contractor, which allows the Company to bring claims against such entities in the U.S. District Court. On October 21, 2016, PGE filed a complaint in the U.S. District Court for the DistrictOPUC delay its review of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa 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.this

On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:

1.that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and

2.that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

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The Company disagreesdeferral request until all legal actions with the foregoing assertions and, on March 23, 2016, filed a breach of contract actionrespect to this matter, including PGE’s actions against the Sureties, in the U.S. District Court for the District of Oregon. 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 aswere resolved. As a result of the Sureties' breach of contract, including damages in excess ofsettlement described above, the $145.6 million stated amount ofCompany withdrew the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.

On April 15, 2016, the Sureties filed a motion to stay this U.S. District Court proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE opposed the motion and filed a motion to enjoin the Sureties from pursuing, in the ICC arbitration proceeding, claims relating to the Performance Bond. On July 27, 2016, the court denied the Sureties’ motion to stay and granted PGE’s motion for a preliminary injunction. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals. On December 13, 2016, the Ninth Circuit issued an Order staying the district court proceeding, pending a decision on the Sureties’ appeal.Oral argument on the Sureties’ appeal is scheduled for May 2017.deferral application.

RecoveryA de minimis amount of Capital Costs in Excess of $514 million—Following termination of the Construction Agreement, PGE brought on new contractorsliens and resumed construction. Carty was placed into service on July 29, 2016 and the Company began including its revenue requirement, based on the approved cost of $514 million, in customer prices on August 1. Costs for Carty have exceeded the $514 millionapproved for inclusion in customer prices by the OPUC. 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, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials. Costs also increased as a result of PGE’s discovery through the construction process of latent defects in work performed by the former Contractor and the corresponding labor and materials required to correct the work. Other items contributing to the increase include costs relating to the removal of certain liensclaims filed on the property for goods and services provided under third-party contracts with the former Contractor and costs to repair equipment damage resulting from poor storage and maintenance on the part of the former Contractor.

As of December 31, 2016, PGE has capitalized $634 million for Carty classified as Electric utility plant. PGE currently estimates the total cost of Carty will be approximately $640 million. This cost estimate does not reflect any offsetting amounts that may be received from the Sureties pursuant to the Performance Bond. This estimate also excludes approximately $17 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor.remain in dispute. The Company believes these liensthe remaining claims by subcontractors are invalidnot owed by the Company and is contesting the liens and claims in the courts.

In the event the total project costs incurred by PGE, net of offsetting amounts that may be received from the Sureties, Abengoa S.A., or the Contractor, exceed the $514 million amount approved by the OPUC for inclusion in customer prices, the Company intends to seek approval to recover the excess amounts in customer prices in a subsequent rate proceeding after exhausting all remedies against the aforementioned parties. 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 would 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 that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project.

As actual project costs for Carty exceed $514 million, the Company is incurring a higher cost than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation and interest expense. On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue

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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 that 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 are recognized in the Company’s results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Any amounts approved by the OPUC for recovery under the deferral filing will 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 consolidated balance sheet were prudently incurred. There have been no settlement discussions with regulators related to such costs.
EPA Investigation of Portland Harbor

A 1997An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that 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 (CERCLA) 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.

The Portland Harbor site remedial investigation (RI) hashad been completed pursuant to an Administrative Order on Consent (AOC)agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which doesdid not include PGE. The LWG has funded the RIremedial investigation and feasibility study (FS) and has stated that it hashad 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.

The EPA has finalized the FS,feasibility study, along with the RI,remedial investigation, and these documentsthe 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 onin January 6, 2017. The ROD outlinesoutlined the EPA’s selected remediation alternative toplan for clean-up forof the Portland Harbor site, which has an 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 $1.05$1.1 billion. Remediation construction costs arewere estimated to be incurred over a 13 year13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30 year30-year period from the start of construction. The Company anticipatesEPA acknowledged the estimated costs are based on data that priorwas outdated and that pre-remedial design sampling was necessary to the commencement of remediation activities, a phase of resampling of the river will be necessarygather updated baseline data to better refine the remedial design and may impact estimated costs.cost. In December 2017, the EPA announced that four PRPs had entered into an administrative order on consent to conduct this additional sampling, which was estimated to be completed in two years. PGE is not among the four PRPs performing this sampling.

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-remedial design sampling, 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 or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.

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, and claims are not concluded until a final remedy for clean-up has been settled.site. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, and certain tribal entities.


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After the claimed damages at a site are assessed, theThe 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 assigning initial NRDA liability allocations to PRPs, which the Company anticipates will occur throughout the first half of 2017. PGE believes that the Company’sPGE’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, significantSignificant 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.material to PGE’s financial position.

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 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 customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. 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 planscontinues to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

On July 15, 2016, the Company filed a deferral application with the OPUC to allow for the deferral of the future environmental remediation costs, as well as, seek authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company has reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, subject to OPUC final decision, which is expected in the first quarter of 2017. The mechanism, as proposed, would allow the Company to recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism would establish annual prudency reviews of environmental expenditures and be subject to an annual earnings test.

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 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 Oregon Supreme Court (OSC) in October 2014.

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

In August 2006, the OSCOregon 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, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in 2013 and by the OSC in 2014.

In 2015, based on a motion filed by PGE, the Marion County Circuit Court (Circuit Court) lifted the abatement on the class 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

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The OSC further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The OSC added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for summary judgment, the plaintiffs moved to amend the complaints. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 2016, the Circuit Court entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs. OnIn April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. A Court of Appeals decision remains pending.

PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions that followed have reduced the risk of aany loss to the Company in excess ofbeyond the amounts previously recorded and discussed above. However, because the class actions remain subject to a decision in 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.

Pacific Northwest Refund ProceedingDeschutes River Alliance Clean Water Act Claims

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) 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 claimed PGE had 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 alleged 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 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 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 responseSeptember 2016, PGE filed a motion to dismiss, which asserted that 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 motion to dismiss. On April 7, 2017, the District Court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (CTWS) to appear in the case as a friend of the court. The CTWS shares ownership of the Project with PGE but was not initially named as a defendant.

In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the CTWS filed separate motions to dismiss. At a hearing on May 9, 2018, the Judge requested that PGE file an alternative motion to dismiss, which the Company and the CTWS filed on May 16, 2018. On June 11, 2018, the court denied the motions to dismiss filed in March 2018 and held that the CTWS was a necessary party to the Western energy crisislawsuit. DRA thereafter joined the CTWS as a defendant.

On August 3, 2018, the Judge denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of 2000-2001,PGE and CTWS. The Judge found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the FERC initiated, beginningProject in 2001,violation of the CWA, and accordingly dismissed the case.

On August 24, 2018, DRA filed a seriesmotion seeking to alter or amend the judgment of proceedingsdismissal, arguing that there is a genuine dispute of fact regarding PGE’s compliance with requirements under the CWA. On October 1, 2018, the Judge denied DRA’s motion to determine whether refunds are warranted for bilateral salesalter or amend the judgment of electricity in the Pacific Northwest wholesale spot market during the period December 25, 2000 through June 20, 2001. Indismissal. On October 17, 2018, DRA filed an order issued in 2003, the FERC denied refunds. Various parties appealed the orderappeal to the Ninth Circuit Court of Appeals (Ninth Circuit) and, on appeal, the Ninth Circuit remanded the issue of refunds to the FERC for further consideration.Appeals.

On remand,The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome of this matter will result in 2011 and thereafter, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, expanded the refund period to include January 1, 2000 through December 24, 2000 for certain types of claims, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. Those orders included a finding by the FERC that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund proponents appealed these procedural orders at the Ninth Circuit. On December 17, 2015, the Ninth Circuit held that the FERC reasonably applied the Mobile-Sierra presumption to the class of contracts at issue in the proceedings and dismissed evidentiary challenges related to the scope of the proceeding. Plaintiffs on behalf of the California Energy Resources Scheduling division of the California Department of Water Resources filed a request for rehearing on February 1, 2016. By order issued April 18, 2016, the Ninth Circuit denied Plaintiffs’ request for panel rehearing of its decision regarding application of the Mobile-Sierra presumption.material loss.

In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order finding that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. In December 2015, the FERC denied all requests for rehearing of its order. With respect to the remaining respondent, FERC ordered additional proceedings, and in an order issued October 18, 2016, rejected the Plaintiffs’ request for refunds from the respondent, finding that the Plaintiffs had not met their Mobile-Sierra burden of proof.


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The Company has settled all of the direct claims asserted against it in the proceedings for an immaterial amount. The settlements and associated FERC orders did not fully eliminate the potential for so-called “ripple claims,” which have been described by the FERC as “sequential claims against a succession of sellers in a chain of purchases that are triggered if the last wholesale purchaser in the chain is entitled to a refund.” As a result of the FERC orders to date, there are only two sellers from whom ripple claims could arise if those orders are overturned on appeal. Both of these sellers have now authorized on-the- record representations that they would not pursue ripple claims if they were required to pay refunds. As a result, the Company does not believe that it will incur any material loss in connection with this matter.
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.

QUARTERLY FINANCIAL DATA
(Unaudited)
Quarter EndedQuarter Ended
March 31 June 30 September 30 December 31March 31 June 30 September 30 December 31
(In millions, except per share amounts)(In millions, except per share amounts)
2016       
2018       
Total revenues$493
 $449
 $525
 $524
Income from operations100
 80
 91
 75
Net income64
 46
 53
 49
Earnings per share:*
       
Basic0.72
 0.51
 0.59
 0.55
Diluted0.72
 0.51
 0.59
 0.55
2017       
Revenues, net$487
 $428
 $484
 $524
$530
 $449
 $515
 $515
Income from operations99
 64
 64
 106
123
 68
 77
 112
Net income61
 37
 34
 61
73
 32
 40
 42
Earnings per share: *
              
Basic0.68
 0.42
 0.38
 0.68
0.82
 0.36
 0.44
 0.48
Diluted0.68
 0.42
 0.38
 0.68
0.82
 0.36
 0.44
 0.48
2015       
Revenues, net$473
 $450
 $476
 $499
Income from operations85
 72
 68
 84
Net income50
 35
 36
 51
Earnings per share: *
       
Basic0.64
 0.44
 0.40
 0.57
Diluted0.62
 0.44
 0.40
 0.57
     
* 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.

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.


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(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, 20162018, the Company’s internal control over financial reporting is effective.

The Company’s internal control over financial reporting, as of December 31, 20162018, 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, 20162018.

(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 20162018 that have materially affected, or are reasonably likely to materially affect, the Company’sCompany's internal control over financial reporting.

ITEM 9B.     OTHER INFORMATION.

OnResignation of Director

At a regularly scheduled meeting of the Board of Directors on February 15, 2017,13, 2019, director David Dietzler indicated his plans to retire as director of the CompensationCompany, effective on April 24, 2019, upon the election of directors at the Company’s 2019 annual meeting of shareholders. Pursuant to Section 3.2 of the Company’s bylaws, the board reduced the number of directors from twelve to eleven, effective upon such election of directors.

Adoption of Amended and Human Resources Committee approved amendmentsRestated Bylaws

Effective February 13, 2019, the Board of Directors amended and restated the Company’s bylaws to:
Permit the Company to hold virtual shareholder meetings (Section 2.3);
Establish a process for setting a record date for determining shareholders entitled to take corporate action without a meeting (Section 2.6);
Establish a deadline for shareholders seeking to take action without a meeting to deliver the requisite number of written shareholder consents to the Company’s Severance Pay PlanCompany (Section 2.15);
Update and enhance our advance notice bylaws by, among other things, expanding the scope of disclosures required of a shareholder seeking to bring a nomination or propose other business for Executive Employees (the “Plan”). The amendments provide that, in the eventconsideration at a meeting of termination of employment without cause following a Change in Control (as defined in the Plan), executive officers, including the named executive officers (NEOs), would be entitled to receive a severance payment in the amount of 52 weeks of base salary plus the target cash incentive awardshareholders (Sections 2.13 and 2.14); and
Provide for the fiscal year in which the termination occurs. In addition, the amendments eliminate the four-year vesting period for full severance benefits under the Plan, so that executive officers, including each of the NEOs, would be entitled to receive full severance benefits under the Plan, regardless of their years of service.certain other technical or minor updates and revisions.


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The foregoing summary is qualified in its entirety by reference to the full text of the Company’s Eleventh Amended and Restated Bylaws, a copy of which is included as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated by reference herein.

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,” and “Proposal 1: Election of Directors,” and “Executive Officers”Directors” 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 26, 201724, 2019. 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 26, 201724, 2019.

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

The information required by Item 12 is incorporated herein by reference to the relevant information under the captions “Security Ownership of Certain Beneficial Owners, Directors and Executive Officers” and “Equity Compensation Plans,” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A with the SEC in connection with the Annual Meeting of Shareholders scheduled to be held on April 26, 201724, 2019.

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 26, 201724, 2019.

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 26, 201724, 2019.


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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*
Third Amended and Restated Articles of Incorporation of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 3.1).
3.2*3.2Tenth
Eleventh Amended and Restated Bylaws of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 3.2).Company.
(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*
Sixty-second Supplemental Indenture dated April 1, 2009 (Form 8-K filed April 16, 2009, Exhibit 4.1) (File No. 001-05532-99).
4.4*
Seventy-third Supplemental Indenture dated August 1, 2017, between the Company and Wells Fargo Bank, National Association, as Trustee (Form 8-K filed August 3, 2017, Exhibit 4.1).
(10)Material Contracts
10.1*
Amended and Restated Credit Agreement dated March 6, 2015 between Portland General Electric Company and Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A., Barclays Bank PLC, JPMorgan Chase Bank, N.A. and U.S. Bank National Association (Form 10-Q filed April 27, 2015, Exhibit 10.1).
10.210.2*
First Amendment to Credit Agreement, dated February 21, 2017 among Portland General Electric Company, Lenders, and Wells Fargo Bank, National Association, as administrative agent for the Lenders (Form 10-K filed February 16, 2018, Exhibit 10.2).
10.3
Second Amendment to Credit Agreement, dated as of January 16, 2019 among Portland General Electric Company, Lenders, and Wells Fargo Bank, National Association, as administrative agent for the Lenders.
10.4*
Consent Agreement, dated November 3, 2017 among Portland General Electric Company, Lenders, and Wells Fargo Bank, National Association, as administrative agent for the Lenders (Form 10-K filed February 16, 2018, Exhibit 10.3).
10.5*
Portland General Electric Company Severance Pay Plan for Executive Employees, as amended and restated effective February 14, 2017.2017 (Form 10-K filed February 17, 2017, Exhibit 10.2). +
10.3*10.6*
Portland General Electric Company Outplacement Assistance Plan dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.2) (File No. 001-05532-99). +
10.4*10.7*
Portland General Electric Company 2005 Management Deferred Compensation Plan dated January 1, 2005 (Form 10-K filed March 11, 2005, Exhibit 10.18) (File No. 001-05532-99). +
10.5*10.8*
Portland General Electric Company Management Deferred Compensation Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.1) (File No. 001-05532-99). +
10.6*10.9*
Portland General Electric Company Supplemental Executive Retirement Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.2) (File No. 001-05532-99). +
10.7*10.10*
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). +
10.8*10.11*
Portland General Electric Company Umbrella Trust for Management dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.4) (File No. 001-05532-99). +
10.9*Portland General Electric Company 2006 Stock Incentive Plan, as amended (Form 10-K filed February 27, 2008, Exhibit 10.23) (File No. 001-05532-99). +
10.10*Portland General Electric Company 2006 Annual Cash Incentive Master Plan (Form 8-K filed March 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.11*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). +
10.12*Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (Form 8-K filed February 26, 2008, Exhibit 10.1) (File No. 001-05532-99). +
10.13*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). +

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Exhibit
Number
Description
10.12*
Portland General Electric Company Stock Incentive Plan, As Amended and Restated Effective February 13, 2018. (Form 10-Q filed April 27, 2018, Exhibit 10.1) (File No. 001-055532-99). +
10.13*
Portland General Electric Company 2006 Annual Cash Incentive Master Plan (Form 8-K filed March 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.14*
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). +
10.15*
Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (Form 8-K filed February 26, 2008, Exhibit 10.1) (File No. 001-05532-99). +
10.16*
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). +
10.17*
Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters for Officers and Key Employees (Form 8-K filed February 19, 2010, Exhibit 10.1) (File No. 001-05532-99). +
10.15*10.18*
Form of Directors’ Restricted Stock Unit Agreement (Form 8-K filed July 14, 2006, Exhibit 10.1) (File No. 001-05532-99). +
10.16*10.19*
Form of Officers’ and Key Employees’ Performance Stock Unit Agreement (Form 10-Q filed May 3, 2012, Exhibit 10.1) (File No. 001-05532-99). +
(12)Statements Re Computation of Ratios
12.1Computation of Ratio of Earnings to Fixed Charges.
(23)Consents of Experts and Counsel
23.1
Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP.
(31)Rule 13a-14(a)/15d-14(a) Certifications
31.1
Certification of Chief Executive Officer.
31.2
Certification of Chief Financial Officer.
(32)Section 1350 Certifications
32.1
Certifications of Chief Executive Officer and Chief Financial Officer.Officer.
(101)Interactive Data File
101.INSXBRL Instance 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.

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

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


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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 16, 201714, 2019.
 
 PORTLAND GENERAL ELECTRIC COMPANY
   
 By:/s/ JAMES J. PIRO        MARIA M. POPE
  James J. PiroMaria 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 16, 201714, 2019.

SignatureTitle
  
/s/ JAMES J. PIROMARIA M. POPE
President, Chief Executive Officer, and Director
(principal executive officer)
James J. PiroMaria M. Pope
  
/s/ JAMES F. LOBDELL
Senior Vice President of Finance, Chief Financial Officer, and Treasurer
(principal financial and accounting officer)
James F. Lobdell
  
/s/ JOHN W. 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/ KATHRYN J. JACKSONDirector
Kathryn J. Jackson 
  
/s/ NEIL J. NELSONDirector
Neil J. Nelson 
  
/s/ M. LEE PELTONDirector
M. Lee Pelton 
  
/s/ CHARLES W. SHIVERYDirector
Charles W. Shivery 

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