10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2021

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: 001-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

121 SW 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:

(Title of class)	(Trading Symbol)	(Name of exchange on which registered)
Common Stock, no par value	POR	New York Stock Exchange
9.31% Medium-Term Notes due 2021	POR 21	New York Stock Exchange

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. [x] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

[x] Yes x [ ] No

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

Large accelerated filer	☒	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 standard 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 [x] No

Number of shares of common stock outstanding as of April 26, 2021 is 89,605,758 shares.

1

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2021

TABLE OF CONTENTS

Definitions		3
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Income and Comprehensive Income	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	55
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	56
Item 5.	Other Information	57
Item 6.	Exhibits	58
SIGNATURE		58

2

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym	Definition
AFDC	Allowance for funds used during construction
AUT	Annual Power Cost Update Tariff
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FMBs	First Mortgage Bonds
GAAP	Accounting principles generally accepted in the United States of America
GRC	General Rate Case
IRP	Integrated Resource Plan
Moody’s	Moody’s Investors Service
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hour
Nasdaq	National Association of Securities Dealers Automated Quotations
NVPC	Net Variable Power Costs
NYSE	New York Stock Exchange
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
RPS	Renewable Portfolio Standard
S&P	S&P Global Ratings
SEC	United States Securities and Exchange Commission
Trojan	Trojan nuclear power plant
Wheatridge	Wheatridge Renewable Energy Facility

3

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2021		2020
Revenues:
Revenues, net	$	612	$	564
Alternative revenue programs, net of amortization	(3)		9
Total revenues	609		573
Operating expenses:
Purchased power and fuel	169		153
Generation, transmission and distribution	80		73
Administrative and other	86		71
Depreciation and amortization	103		108
Taxes other than income taxes	38		35
Total operating expenses	476		440
Income from operations	133		133
Interest expense, net	34		33
Other income (expense):
Allowance for equity funds used during construction	4		3
Miscellaneous income (expense), net	2		(4)
Other income (expense), net	6		(1)
Income before income tax expense	105		99
Income tax expense	9		18
Net income	96		81
Other comprehensive income	—		1
Comprehensive income	$	96	$	82
Weighted-average common shares outstanding (in thousands):
Basic	89,556		89,429
Diluted	89,703		89,579
Earnings per share—Basic and diluted	$	1.07	$	0.91
See accompanying notes to condensed consolidated financial statements.

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)

	March 31, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	135	$	257
Accounts receivable, net	268		271
Inventories	67		72
Regulatory assets—current	25		23
Other current assets	127		98
Total current assets	622		721
Electric utility plant, net	7,616		7,539
Regulatory assets—noncurrent	591		569
Nuclear decommissioning trust	44		45
Non-qualified benefit plan trust	43		42
Other noncurrent assets	153		153
Total assets	$	9,069	$	9,069
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)

	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	199	$	153
Liabilities from price risk management activities—current	20		14
Short-term debt	200		150
Current portion of long-term debt	20		160
Current portion of finance lease obligation	16		16
Accrued expenses and other current liabilities	319		322
Total current liabilities	774		815
Long-term debt, net of current portion	2,886		2,886
Regulatory liabilities—noncurrent	1,353		1,369
Deferred income taxes	391		374
Unfunded status of pension and postretirement plans	299		299
Liabilities from price risk management activities—noncurrent	118		136
Asset retirement obligations	270		270
Non-qualified benefit plan liabilities	101		101
Finance lease obligations, net of current portion	128		129
Other noncurrent liabilities	74		77
Total liabilities	6,394		6,456
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2021 and December 31, 2020	—		—
Common stock, no par value, 160,000,000 shares authorized; 89,576,748 and 89,537,331 shares issued and outstanding as of March 31, 2021 and December 31, 2020, respectively	1,233		1,231
Accumulated other comprehensive loss	(11)		(11)
Retained earnings	1,453		1,393
Total shareholders’ equity	2,675		2,613
Total liabilities and shareholders’ equity	$	9,069	$	9,069
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)        

	Three Months Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	96	$	81
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	103		108
Deferred income taxes	(1)		7
Pension and other postretirement benefits	6		6
Allowance for equity funds used during construction	(4)		(3)
Decoupling mechanism deferrals, net of amortization	3		(9)
Amortization of net benefits due to Tax Reform	—		(6)
Deferral of incremental storm costs	(41)		—
Other non-cash income and expenses, net	13		19
Changes in working capital:
(Increase)/decrease in accounts receivable, net	(2)		19
Decrease/(increase) in inventories	4		(1)
(Increase)/decrease in margin deposits	(1)		(19)
Increase/(decrease) in accounts payable and accrued liabilities	26		(22)
Other working capital items, net	(14)		(9)
Other, net	(20)		(16)
Net cash provided by operating activities	168		155
Cash flows from investing activities:
Capital expenditures	(153)		(162)
Sales of Nuclear decommissioning trust securities	3		3
Purchases of Nuclear decommissioning trust securities	(3)		(2)
Other, net	(9)		4
Net cash used in investing activities	(162)		(157)

7

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

	Three Months Ended March 31,
	2021		2020
Cash flows from financing activities:
Proceeds from issuance of long-term debt	—		119
Payments on long-term debt	(140)		(98)
Borrowings on short-term debt	200		20
Repayments of short-term debt	(150)		(20)
Issuance of commercial paper, net	—		20
Dividends paid	(36)		(34)
Other	(2)		(5)
Net cash provided by (used in) financing activities	(128)		2
Increase (Decrease) in cash and cash equivalents	(122)		—
Cash and cash equivalents, beginning of period	257		30
Cash and cash equivalents, end of period	$	135	$	30
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	16	$	12
See accompanying notes to condensed consolidated financial statements.

8

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area encompasses 51 incorporated cities entirely within the State of Oregon. As of March 31, 2021, PGE served 909,000 retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein as of and for the three months ended March 31, 2021 and 2020 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2020 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2020, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 19, 2021, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three months ended March 31, 2021 and 2020.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with 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 experienced by the Company could differ materially from those estimates.

Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year.

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended March 31,
	2021		2020
Retail:
Residential	$	310	$	279
Commercial	162		159
Industrial	60		51
Direct access customers	11		11
Subtotal	543		500
Alternative revenue programs, net of amortization	(3)		9
Other accrued revenues, net	13		5
Total retail revenues	553		514
Wholesale revenues*	33		47
Other operating revenues	23		12
Total revenues	$	609	$	573

* Wholesale revenues include $5 million and $16 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2021 and 2020, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated, tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public 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 energy use by this customer class.

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that have not yet been billed to customers. This amount, classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed 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 customer prices.

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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

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

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power; hydro, solar and wind conditions; and daily and seasonal retail demand.

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

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers.

11

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 3: BALANCE SHEET COMPONENTS

Inventories

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

Accounts Receivable, Net

Accounts receivable, net includes $86 million and $97 million of unbilled revenues as of March 31, 2021 and December 31, 2020, respectively. Accounts receivable, net is net of an allowance for credit losses of $20 million as of March 31, 2021. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended March 31,
	2021
Balance as of beginning of period	$	16
Increase in provision	7
Amounts written off	(4)
Recoveries	1
Balance as of end of period	$	20

Other Current Assets

Other current assets consist of the following (in millions):

	March 31, 2021		December 31, 2020
Prepaid expenses	$	68	$	57
Assets from price risk management activities	50		33
Margin deposits	9		8
Other current assets	$	127	$	98

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):

	March 31, 2021		December 31, 2020
Electric utility plant	$	11,073	$	10,974
Construction work-in-progress	472		429
Total cost	11,545		11,403
Less: accumulated depreciation and amortization	(3,929)		(3,864)
Electric utility plant, net	$	7,616	$	7,539

12

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $403 million and $388 million as of March 31, 2021 and December 31, 2020, respectively. Amortization expense related to intangible assets was $15 million for the three months ended March 31, 2021 and 2020. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Regulatory Assets and Liabilities

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

	March 31, 2021					December 31, 2020
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	103	$	—		$	124
Pension and other postretirement plans	—			234		—			240
Debt issuance costs	—			25		—			25
Trojan decommissioning activities	—			97		—			95
Incremental storm costs	—			41		—			—
Other	25			91		23			85
Total regulatory assets	$	25		$	591	$	23		$	569
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,020	$	—		$	1,016
Deferred income taxes	—			222		—			239
Asset retirement obligations	—			38		—			37
Price risk management	30			—		18			—
Other	12			73		5			77
Total regulatory liabilities	$	42	(1)	$	1,353	$	23	(1)	$	1,369

(1)Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Incremental storm costs represents the incremental costs incurred during the three months ended March 31, 2021 to repair damage to PGE’s transmission and distribution systems and restore power to customers. As a result of the historic February winter storms, Oregon’s Governor declared a state of emergency on February 13, 2021. On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) . PGE does not expect an OPUC decision on the February storm deferral until later in 2021 or 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery which could result in a portion or all of PGE’s deferral being disallowed for recovery.

Accrued Expenses and Other Current Liabilities

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

13

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

	March 31, 2021		December 31, 2020
Accrued employee compensation and benefits	$	48	$	67
Accrued taxes payable	45		36
Accrued interest payable	43		29
Accrued dividends payable	37		38
Regulatory liabilities—current	42		23
Other	104		129
Total accrued expenses and other current liabilities	$	319	$	322

Credit Facilities

As of March 31, 2021, PGE had a $500 million revolving credit facility scheduled to expire in November 2023. The Company has the ability to expand the revolving credit facility to $600 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2021, PGE was in compliance with this covenant with a 55.2% debt-to-total capital ratio. The aggregate unused available credit capacity under the revolving credit facility was $500 million.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay any commercial paper that may be outstanding at the time. As of March 31, 2021, PGE had no commercial paper outstanding.

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

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $75 million were outstanding as of March 31, 2021. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bore interest for the relevant interest period at LIBOR plus 1.25%. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 31, 2021, this term loan was repaid in full with proceeds from the term loan described below.

On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan will bear interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to terms of the loan. The credit agreement expires on March 30, 2022, with any outstanding balance due and payable on such date. The Company used a portion of the proceeds to repay the prior 364-day term loan, with the remainder of the proceeds used for general corporate purposes.

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2022.

Long-term Debt

On January 6, 2021, the Company made a $140 million scheduled repayment on a 2.51% Series of First Mortgage Bonds with available cash.

Defined Benefit Retirement Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Service cost	$	5	$	4
Interest cost*	7		8
Expected return on plan assets*	(11)		(11)
Amortization of net actuarial loss*	5		4
Net periodic benefit cost	$	6	$	5

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE estimated the fair value of financial asset and liability instruments as of March 31, 2021 and December 31, 2020, and classified these financial instruments based on a fair value hierarchy that is applied 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:

Level 1	Quoted prices are available in active markets for identical assets or liabilities as of the measurement date;
Level 2	Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date; and
Level 3	Pricing inputs include significant inputs that are unobservable for the asset or liability.

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

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.

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

15

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

	As of March 31, 2021
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	72	$	—	$	—	$	—	$	72
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	12		7		—		—		19
Corporate credit	—		12		—		—		12
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	1		—		—		—		1
Debt securities—domestic government	8		—		—		—		8
Price risk management activities: (1) (4)
Electricity	—		14		5		—		19
Natural gas	—		44		2		—		46
	$	94	$	77	$	7	$	13	$	191
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	11	$	123	$	—	$	134
Natural gas	—		3		1		—		4
	$	—	$	14	$	124	$	—	$	138

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

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	As of December 31, 2020
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	255	$	—	$	—	$	—	$	255
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		11		—		—		20
Corporate credit	—		13		—		—		13
Money market funds measured at NAV (2)	—		—		—		12		12
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		4		4		—		8
Natural gas	—		36		1		—		37
	$	273	$	64	$	5	$	12	$	354
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		5		141		—		146
Natural gas	—		4		1		—		5
	$	—	$	9	$	142	$	—	$	151

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

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

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

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

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

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE.

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

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

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2021
Electricity physical forwards	$	—	$	123	Discounted cash flow	Electricity forward price (per MWh)	$	5.75	$	73.58	$	33.39
Natural gas financial swaps	2		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.60		4.32		2.22
Electricity financial futures	5		—		Discounted cash flow	Electricity forward price (per MWh)	5.75		73.58		37.97
	$	7	$	124
As of December 31, 2020
Electricity physical forwards	$	—	$	141	Discounted cash flow	Electricity forward price (per MWh)	$	11.17	$	51.18	$	29.74
Natural gas financial swaps	1		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.52		4.33		2.29
Electricity financial futures	4		—		Discounted cash flow	Electricity forward price (per MWh)	8.78		58.42		43.71
	$	5	$	142

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 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 long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.

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 PGE’s position as either the buyer or seller under 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
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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

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	Three Months Ended March 31,
	2021		2020
Balance as of the beginning of the period	$	137	$	97
Net realized and unrealized losses/(gains)*	(21)		39
Transfers from Level 3 to Level 2	1		(2)
Balance as of the end of the period	$	117	$	134

* Both realized and unrealized losses/(gains), of which unrealized portion are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

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.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

As of March 31, 2021, the carrying amount of PGE’s long-term debt was $2,906 million, net of $12 million of unamortized debt expense, and its estimated aggregate fair value was $3,359 million. As of December 31, 2020, the carrying amount of PGE’s long-term debt was $3,046 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,808 million.

NOTE 5: RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace 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. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this 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 flows.

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

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

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	March 31, 2021		December 31, 2020
Current assets:
Commodity contracts:
Electricity	$	14	$	4
Natural gas	36		29
Total current derivative assets(1)	50		33
Noncurrent assets:
Commodity contracts:
Electricity	5		4
Natural gas	10		8
Total noncurrent derivative assets(1)	15		12
Total derivative assets(2)	$	65	$	45
Current liabilities:
Commodity contracts:
Electricity	$	17	$	13
Natural gas	3		2
Total current derivative liabilities	20		15
Noncurrent liabilities:
Commodity contracts:
Electricity	117		133
Natural gas	1		3
Total noncurrent derivative liabilities	118		136
Total derivative liabilities(2)	$	138	$	151

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of March 31, 2021 and December 31, 2020, no derivative assets or liabilities were designated as hedging instruments.

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):

	March 31, 2021			December 31, 2020
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	154		Decatherms	137		Decatherms
Foreign currency	$	19	Canadian	$	19	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. 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 March 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements was $1 million, comprised solely of natural gas contracts for which PGE posted no collateral. As of December 31, 2020, PGE had no material master netting arrangements.

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Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Commodity contracts:
Electricity	$	(23)	$	32
Natural Gas	(25)		9
Foreign currency exchange	—		1

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended March 31, 2021 and 2020, net gains of $39 million and net losses of $42 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2021 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2021		2022		2023		2024		2025		Thereafter		Total
Commodity contracts:
Electricity	$	3	$	1	$	8	$	8	$	8	$	87	$	115
Natural gas	(28)		(12)		(2)		—		—		—		(42)
Net unrealized loss/(gain)	$	(25)	$	(11)	$	6	$	8	$	8	$	87	$	73

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 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 derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2021 was $128 million, for which PGE has posted $9 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2021, the cash requirement to either post as collateral or settle the instruments immediately would have been $125 million. As of March 31, 2021, PGE had $8 million cash collateral posted 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 condensed consolidated balance sheet.

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

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(Unaudited)

	March 31, 2021		December 31, 2020
Assets from price risk management activities:
Counterparty A	14	%	12	%
Counterparty B	13		17
Counterparty C	17		21
Counterparty D	14		16
	58	%	66	%
Liabilities from price risk management activities:
Counterparty E	89	%	93	%

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

NOTE 6: EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three months ended March 31, 2021, unvested performance-based restricted stock units and related dividend equivalent rights of 373 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 301 thousand shares excluded for the three months ended March 31, 2020.

Net income (loss) is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2021	2020
Weighted-average common shares outstanding—basic	89,556	89,429
Dilutive effect of potential common shares	147	150
Weighted-average common shares outstanding—diluted	89,703	89,579

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three-month periods ended March 31, 2021 and 2020 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2020	89,537,331	$	1,231	$	(11)	$	1,393	$	2,613
Issuances of shares pursuant to equity-based plans	39,417	—		—		—		—
Stock-based compensation	—	2		—		—		2
Dividends declared ($0.4075 per share)	—	—		—		(36)		(36)
Net income	—	—		—		96		96
Balances as of March 31, 2021	89,576,748	$	1,233	$	(11)	$	1,453	$	2,675
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	$	1,220	$	(9)	$	1,427	$	2,638

NOTE 8: 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 condensed consolidated financial statements are prepared. 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 PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made.

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(Unaudited)

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

PGE 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) significant facts are in 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 may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

EPA Investigation of Portland Harbor

An 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 as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

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

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

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has

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(Unaudited)

indicated it will take the initial lead to perform remedial design on the remaining areas. The EPA announced on February 12, 2021 that 100 percent of Portland Harbor is under an active engineering design phase.

PGE continues 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 remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position.

In 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 (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe.

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

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

Deschutes River Alliance Clean Water Act Claims

In 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 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

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(Unaudited)

acidity or alkalinity of the water. DRA alleged the violations were 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 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 alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had 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 March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the Confederated Tribes of Warm Springs (CTWS), which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant.

In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.

In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. The appeals are fully briefed and oral argument is set for May 7, 2021.

The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome will result in a material loss.

Securities Case

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

During the fourth quarter of 2020, the plaintiff in Hessel voluntarily dismissed his case and the court consolidated Cannataro and PERS of Mississippi into a single case captioned In re Portland General Electric Company Securities Litigation and appointed Public Employees’ Retirement System of Mississippi lead plaintiff (“Lead Plaintiff”). On January 11, 2021, Lead Plaintiff filed an amended complaint asserting causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 for alleged misstatements and omissions regarding, among other things, PGE’s alleged lack of sufficient internal controls and risks associated with PGE's trading activity in wholesale electric markets, purportedly on behalf of purchasers of PGE stock between February 13, 2020, and August 24, 2020 (“the Amended Complaint”). The Amended Complaint demands a jury trial and seeks compensatory damages of an unspecified amount and reimbursement of plaintiffs’ costs, and attorneys’ and expert fees. On March 12, 2021, the defendants filed a motion to dismiss the Amended Complaint. Briefing on the motion to dismiss is ongoing with oral argument set for July 9, 2021.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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

Putative Shareholder Derivative Lawsuits

On January 26, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned Shimberg v. Pope, No. 21- cv-02957, against one current and one former PGE executive and several members of the Company's Board of Directors (collectively, the "Individual Defendants") and naming the Company as a nominal defendant only. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the Individual Defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company of not less than $10 million, equitable relief to remedy the alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. The court has entered an order staying the action until September 15, 2021, or until further order of the court reinstating the action. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

On March 17, 2021, a putative shareholder derivative lawsuit was filed in U.S. District Court for the District of Oregon, captioned JS Halberstam Irrevocable Grantor Trust v. Davis, No. 3:21-cv-00413-SI, against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserts claims for alleged breaches of fiduciary duties, waste of corporate assets, contribution and indemnification, aiding and abetting, and gross mismanagement, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope, 21-cv-13698, against one current and one former PGE executive and several members of the Company's Board of Directors. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company, equitable relief, and an award of plaintiff’s attorneys’ fees and costs. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

Governmental Investigations

In March and April 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC") and the Division of Enforcement of the SEC, respectively, informed the Company they are conducting investigations arising out of the energy trading losses the Company previously announced in August 2020. The Company is cooperating with the CFTC and the SEC. Management cannot at this time predict the eventual scope or outcome of these matters.

Other Matters

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 that 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.

NOTE 9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas 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 March 31, 2021, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 10: INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended March 31,
	2021		2020
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(8.9)		(10.9)
State and local taxes, net of federal tax benefit	8.8		7.4
Flow-through depreciation and cost basis differences	0.3		1.6
Amortization of excess deferred income tax	(3.2)		(1.9)
Local tax flow-through adjustment	(8.2)		—
Other	(1.2)		1.0
Effective tax rate	8.6	%	18.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Local tax flow-through adjustment

The Company is subject to a local tax that is recovered through a supplemental tariff based on current tax expense, but for which the Company has also recognized deferred income tax expenses over time. Because it is probable that the local deferred taxes will be flowed through future customer prices in accordance with the supplemental tariff, PGE determined a corresponding regulatory asset should have been recorded. PGE recognized a regulatory asset to defer previously recorded deferred income tax expenses in the amount of $9 million with a corresponding credit to Income tax expense in the condensed consolidated statements of income for the three months ended March 31, 2021. The adjustment is immaterial to prior periods.

Carryforwards

Federal tax credit carryforwards as of March 31, 2021 and December 31, 2020 were $79 million and $77 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2041. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2021 will be realized; accordingly, no valuation allowance has been recorded. As of March 31, 2021, and December 31, 2020, PGE had no material unrecognized tax benefits.

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Item 2. 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, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but 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 forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:

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

•economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers, and elevated levels of uncollectible customer accounts;

•changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators;

•the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements;

•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;

•complications arising from PGE’s jointly-owned plant, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs;

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•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 that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;

•changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;

•capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;

•future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;

•changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;

•the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

•changes in residential, commercial, or industrial customer growth, or demographic patterns, in PGE’s service territory;

•the effectiveness of PGE’s risk management policies and procedures;

•cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, 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 the ability to recruit and retain appropriate talent;

•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 pandemic, earthquake, flood, ice, drought, lightning, wind, and fire;

•the impact of widespread health developments, including the global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities), which could materially and adversely affect, among other things, demand for electric services, customers’ ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;

•changes in financial or regulatory accounting principles or policies imposed by governing bodies;

•acts of war or terrorism; and

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

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Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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. The MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.

PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

February 2021 Ice Storms and Damage

Beginning on February 11, 2021, an historic set of storms involving heavy snow, winds and ice impacted the United States, including PGE’s service territory. On February 13, 2021, Oregon’s Governor declared a state of emergency due to severe winter weather that resulted in heavy snow and ice accumulation, high winds, critical transportation failures, and loss of power and communications capabilities. The wind and ice from the storms caused significant damage to PGE’s transmission and distribution systems, which resulted in over 750,000 outages, with many customers affected more than once. At peak activity during the recovery, PGE deployed over 400 repair crews across the service territory, with many of these crews provided through mutual aid arrangements from throughout the West.

Through March 31, 2021, PGE has incurred an estimated $87 million in incremental costs due to the storms, of which $33 million were capital and recorded to Electric utility plant, net and $54 million were operating expenses associated with transmission and distribution. Beginning in 2019, the OPUC authorized the Company to collect $4 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In response to the February storms, PGE exhausted its storm collection balance for 2021 of $9 million, which was used to offset operating expenses. After accounting for storm deferral tracking mechanisms already in place, the cumulative incurred operating expenses from the February storm damage are estimated to be $45 million as of March 31, 2021.

On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) and as of March 31, 2021, the Company has deferred a total of $41 million related to incremental operating expenses due to the storm. PGE expects to incur and defer additional costs subsequent to the storm related to replacing and rebuilding PGE facilities damaged by the storm, as well as addressing vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. PGE does not expect an OPUC decision on the February storm deferral until sometime during 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery which could result in a portion or all of PGE’s deferral being disallowed for recovery.

Company Strategy

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PGE remains committed to achieving steady growth and returns as the Company transforms to meet the challenges of climate change and an ever-evolving energy grid. Customers, policy makers, and other stakeholders expect PGE to reduce greenhouse gas emissions, keep the power grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company’s strategy strives to balance these interests. PGE plans to:

•Reduce greenhouse gas emissions associated with the power served to customers by 80% by 2030 (2010 baseline year), setting an aspirational goal for zero greenhouse gas emissions associated with the power served to customers by 2040;

•Electrify sectors of the economy like transportation and buildings that are also transforming to reduce greenhouse gas emissions; and

•Perform as a business, driving improvements to work efficiency, safety of our coworkers, and reliability of our systems and equipment, all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on average.

Decarbonize the power supply—PGE partners with customers and local and state governments to advance a clean energy future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help meet its greenhouse gas emission reduction goals.

The Climate Pledge—On April 21, 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report greenhouse gas emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets.

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

In response, the Company implemented a new customer service option, the Green Future Impact program, which allows for 100 MW of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the OPUC in the first quarter 2019, the program provides business customers access to bundled renewable attributes from those resources. On March 29, 2021, the OPUC issued an order that expanded the program by 200 MW and provided for the possibility of PGE ownership of the underlying renewable resources under certain conditions. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system.

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

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Other provisions of the law include:

•An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;

•A limitation on the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and

•An allowance for energy storage costs related to renewable energy in the Company’s Renewable Adjustment Clause (RAC) filings.

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

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

Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montana to near the western end of the state to serve markets in the Pacific Northwest and neighboring states. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development in the state of Montana might benefit from any excess transmission capacity that may become available.

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

After the failure of comprehensive cap and trade legislation in both the 2019 and 2020 Oregon legislative sessions, in March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate greenhouse gas (GHG) emissions. Many of the direct agency actions are on an aggressive timeline with due dates in 2020 and 2021. As the Governor is limited by current statutory authority, the executive order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in the 2019 and 2020 legislative sessions.

Among other things, the executive order:

•Modified the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050.

•Directed state agencies to integrate climate change and the State’s GHG reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law.

•Directed the OPUC to—

◦determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon’s reduction goals;

◦encourage electric companies to support transportation electrification infrastructure that supports GHG reductions and zero emission vehicle goals; and

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◦prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy.

•Directed the Oregon Department of Environmental Quality (DEQ) to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas; and

•More than doubled the reduction goals of the state’s Clean Fuels Program and extended the program, from the previous rule that required a 10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

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

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

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

Construction continues on the solar and battery components, which are expected to be placed in service at the end of 2021.

On May 6, 2020, the OPUC issued an order that acknowledged the Company’s 2019 IRP and the following Action Plan for PGE to undertake over the next four years to acquire the resources identified:

•Customer actions—

◦Seek to acquire all cost-effective energy efficiency; and

◦Seek to acquire all cost-effective and reasonable distributed flexibility.

•Renewable actions—Conduct a Renewables Request for Proposals (RFP) seeking up to approximately 150 MWa of new RPS-eligible resources that contribute to meeting PGE’s capacity needs by the end of 2024, with the following conditions, among others:

◦Resources must qualify for PTC or the federal Investment Tax Credit;

◦Resources must pass the cost-containment screen; and

◦The value of RECs generated prior to 2030 must be returned to customers.

•Capacity actions—Pursue dispatchable capacity through the following concurrent processes:

◦Pursue cost-competitive, bilateral contract agreements for existing capacity in the region; and

◦Conduct an RFP for non-emitting dispatchable resources that contribute to meeting PGE’s capacity needs.

The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of capacity contribution by 2025 from a

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combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage.

PGE and Douglas County Public Utility District (PUD) entered into an agreement during 2020 to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. The agreement also provides Douglas County PUD with PGE load management and wholesale market sales services. With a start date of January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MW toward a capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company’s stated decarbonization goals.

PGE filed an IRP Update with the OPUC in January 2021 seeking acknowledgement so that it may incorporate the updated resource cost and value information in PURPA QF avoided cost pricing. No changes were proposed to the 2019 IRP Action Plan in the IRP Update. However, based on the updated capacity need forecast reflecting the addition of the agreement with the Douglas County PUD and more sophisticated modeling, the updated capacity need in 2025 is 511 MW. At the April 20, 2021 special public meeting, the OPUC approved a motion to adopt, with supplements, the OPUC staff’s recommendation to acknowledge PGE’s 2019 IRP Update, with a written order to follow.

The Company has begun the process to select an independent evaluator for the upcoming RFP. This is the first step toward the RFP, which is expected to continue into 2022 before finalization, with the Company planning to submit a benchmark resource into the competitive process.

Renewable Recovery Framework—As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the Renewable Adjustment Clause (RAC). The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 General Rate Case (2019 GRC) Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. There have been no significant filings made under the RAC during 2021.

Electrify other sectors of the economy—PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:

•The use of electricity in more applications such as electric vehicles and heat pumps;

•The integration of new, geographically-diverse energy markets;

•The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation;

•The development of connected neighborhood microgrids and smart communities; and

•The use of data and analytics to better predict demand and support energy-saving customer programs.

In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support functions. As of March 31, 2021, the Company has recorded $132 million, including AFDC, in construction work-in-progress related to the IOC. The project is expected to be placed in-service in the fourth quarter of 2021.

The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044, which establishes Oregon’s zero emissions vehicle goals in statute at 250 thousand electric vehicle sales by 2025 and 90% of all new vehicle sales to be electric by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification

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plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State’s carbon reduction goals. In October 2020, the OPUC approved the plan and the Company began deferral accounting for costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs.

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

COVID-19 Impacts—The COVID-19 pandemic has had a variety of adverse impacts on economic activity. The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. As a result of these activities and economic hardships, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs.

On March 20, 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities which may qualify for deferral under Docket UM2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020.

For the three months ended March 31, 2021, PGE recorded no increase to its COVID-19 deferral. As of March 31, 2021 and December 31, 2020, PGE’s deferred balance was $10 million, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE expects incremental bad debt expense to be $6 million to $8 million for the year-ended 2021. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test.

PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s 2020 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative AFDC calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief to utilities that issued short-term debt in response to the COVID-19 emergency and the detrimental impacts the issuance of short-term debt has on the allowance for equity funds used during construction. PGE adopted the waiver in the second quarter of 2020 and retrospectively applied its provisions as of March 2020. On February 23, 2021, FERC issued an order extending the waiver an additional seven months, to be effective March 1, 2021 through September 30, 2021. PGE adopted the waiver extension.

Wildfire—In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE’s wildfire mitigation planning includes regular system-wide risk assessment,

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which led to the identification and activation of a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as a region at high risk of wildfire in 2020. Additionally, in response to wildfires across Oregon in 2020, PGE cut power to eight additional high-risk fire areas in partnership with local and regional agencies. The Company is intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises. These efforts include enhanced tree and brush clearing, replacing equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment.

PGE continues to incur costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs. As of March 31, 2021 and December 31, 2020, PGE’s cumulative deferred costs related to the wildfire response was $22 million and $15 million, respectively. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. PGE believes the full amount of the 2020 deferral is probable of recovery as the Company’s prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

Power Costs—Pursuant to the Annual Update Tariff (AUT) process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2021 AUT included a final increase in power costs for 2021, and a corresponding increase in annual revenue requirement, of $66 million from 2020 levels, which were reflected in customer prices effective January 1, 2021. See “Power Operations” within this Overview section of Item 2 for more information regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor Superfund site. As of March 31, 2021, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. However, the Company does not currently have sufficient information to 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. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company’s 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. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Decoupling—The decoupling mechanism, authorized by the OPUC through 2022, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

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The Company recorded an estimated refund of $2 million and a collection of $3 million from residential and commercial customers, respectively, for the three months ended March 31, 2021, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. In the first quarter of 2021, the Company continued to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2021, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2023. The Company expects to reach its 2021 limit for collection from commercial customers during the third quarter of 2021. No limit exists for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which have largely offset the revenue increases that have resulted from higher residential demand.

As of December 31, 2020, PGE had recorded an estimated net refund of $6 million for 2020, which if approved by the OPUC, will be credited to customers over a one-year period beginning January 1, 2022.

Deferral of Boardman Revenue Requirement—In October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with Boardman currently included in customer prices as established in the Company’s last general rate case. The application states a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. PGE estimates this amount could be up to $14 million for the period ended December 31, 2020 and $66 million for the year ending December 31, 2021. As of March 31, 2021 and December 31, 2020, PGE has not recorded a regulatory liability pursuant to this deferral application as the Company believes its current prices are just and reasonable in light of PGE’s continued substantial investments in utility plant. The costs of these investments, which are not currently reflected in customer prices, more than offset the revenue requirement for Boardman. If the OPUC authorizes a refund, PGE would record a regulatory liability with a corresponding charge to earnings.

Operating Activities

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

The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its 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 experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—The following tables present total energy deliveries and the average number of retail customers by customer type for the periods indicated.

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	Three Months Ended March 31,		% Increase (Decrease) in Energy Deliveries
	2021	2020
Energy deliveries (MWhs in thousands):
Retail:
Residential	2,239	2,131	5.1	%
Commercial	1,564	1,626	(3.8)	%
Industrial	897	810	10.7	%
Subtotal	4,700	4,567	2.9	%
Direct access:
Commercial	150	170	(11.8)	%
Industrial	359	355	1.1	%
Subtotal	509	525	(3.0)	%
Total retail energy deliveries	5,209	5,092	2.3	%
Wholesale energy deliveries	1,245	1,693	(26.5)	%
Total energy deliveries	6,454	6,785	(4.9)	%

	Three Months Ended March 31,
	2021			2020
Average number of retail customers:
Residential	797,602	88	%	787,095	88	%
Commercial	110,703	12		110,073	12
Industrial	193	—		194	—
Direct access	601	—		627	—
Total	909,099	100	%	897,989	100	%

Retail energy deliveries for the three months ended March 31, 2021 increased 2.3% compared with the three months ended March 31, 2020, as increases in residential and industrial deliveries more than offset the decline in commercial deliveries.

The results for the first quarter of 2020 largely reflected conditions prior to the COVID-19 pandemic. During the pandemic, residential loads have increased as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in an attempt to maintain social distancing or have closed as a result of the lack of business as residents followed directives from state and federal authorities. The industrial class as a whole has experienced an increase in energy deliveries, due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from noted closures than other sectors.

The following table indicates the number of heating and cooling degree-days for the three months ended March 31, 2021 and 2020, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

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	Heating Degree-days
	2021		2020		Avg.
January	620		588		719
February	641		605		598
March	544		568		530
Year-to-date	1,805		1,761		1,847
Decrease from the 15-year average	(2.3)	%	(4.7)	%

After adjusting for the effects of weather, retail energy deliveries for the three months ended March 31, 2021 increased 1.2% compared to the same period of 2020. The increase was driven by an increase of 8% in industrial deliveries and 3% growth in residential energy deliveries partially offset by a decrease in commercial energy deliveries of 5%. Residential average usage per customer saw an increase, which, combined with growth of 1.3% in the average number of residential customers, contributed to increased energy deliveries.

The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from Electricity Service Suppliers (ESSs). This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE’s total retail energy deliveries for the first three months of 2021.

During 2018, the OPUC created a New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. In early February 2020, PGE began offering service to customers under this program, which is capped at 119 MWa, based on an order issued by the OPUC in January 2020. With the adoption of the New Large Load Direct Access program in 2020, as much as 18% of the Company’s energy deliveries could have been supplied by ESSs. Actual energy deliveries to Direct Access customers by ESSs represented 10% of PGE’s total retail energy deliveries for the first three months of 2021 and 2020.

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

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. 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 and impacts NVPC and income from operations.

The following table provides information regarding the performance of the Company’s generating resources for the three months ended March 31, 2021 and 2020:

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	Plant availability (1)				Actual energy provided compared to projected levels (2)				Actual energy provided as a percentage of total retail load
	2021		2020		2021		2020		2021		2020
Generation:
Thermal:
Natural gas	94	%	96	%	114	%	101	%	48	%	50	%
Coal (3)	—		100		103		108		12		24
Wind	94		96		129		164		11		12
Hydro	85		88		81		80		6		8

(1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.

(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.

(3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 94% during the three months ended March 31, 2021, compared with 92% in 2020. Boardman ceased coal-fired generation on October 15, 2020.

Energy received from PGE-owned and jointly-owned thermal plants decreased 18% during the three months ended March 31, 2021 compared to 2020, primarily as a result of Boardman ceasing coal-fired generation on October 15, 2020. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, decreased 8% during the three months ended March 31, 2021 compared to 2020. Energy received from mid-Columbia hydroelectric projects decreased 1% in the three months ended March 31, 2021, and the energy generated by the Company-owned facilities decreased 14%, due to less favorable hydro conditions in 2021. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See “Purchased power and fuel” in the Results of Operations section in this Item 2, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 19% during the three months ended March 31, 2021 compared to 2020 primarily due to the addition of Wheatridge. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation increase in comparison to projected levels, more PTCs were produced in 2021 than what was contemplated in the Company’s prices.

For Wheatridge, wind generation studies were used to develop NVPC cost forecasts, which were included in the RAC filing for the facility, and included in customer prices when the facility went into service. The RAC tariff included NVPC in 2020 along with all other aspects of the revenue requirement. Beginning January 1, 2021, the NVPCs were included in the Company’s AUT, although the other aspects of the RAC tariff will remain in effect until they are included in customer prices as a result of a future general rate case.

Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the

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extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for the three months ended March 31, 2021 and 2020, respectively:

•For the three months ended March 31, 2021, actual NVPC was $13 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be below the baseline, and outside the established deadband range. PGE does not expect its actual regulated ROE to exceed 10.5%; accordingly, no estimated refund to customers is expected under the PCAM for 2021.

•For the three months ended March 31, 2020, actual NVPC was $20 million below baseline NVPC. For the year ended December 31, 2020, actual NVPC, excluding certain trading losses totaling $127 million, was $13 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection to customers was recorded pursuant to the PCAM for 2020.

Critical Accounting Policies

The Company’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021.

Results of Operations

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

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

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

	Three Months Ended March 31,				% Increase (Decrease)
	2021		2020
Total revenues	$	609	$	573	6	%
Purchased power and fuel	169		153		10	%
Gross margin(1)	440		420		5	%
Other operating expenses:
Generation, transmission and distribution	80		73		10	%
Administrative and other	86		71		21	%
Depreciation and amortization	103		108		(5)	%
Taxes other than income taxes	38		35		9	%
Total other operating expenses	307		287		7	%
Income from operations	133		133		—	%
Interest expense, net(2)	34		33		3	%
Other income:
Allowance for equity funds used during construction	4		3		33	%
Miscellaneous income, net	2		(4)		150	%
Other income, net	6		(1)		700	%
Income before income tax expense	105		99		6	%
Income tax expense	9		18		(50)	%
Net income	$	96	$	81	19	%

(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Condensed Consolidated Statements of Income.

(2) Includes an allowance for borrowed funds used during construction of $2 million for the three months ended March 31, 2021 and 2020.

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Three Months Ended March 31, 2021 compared with the three months ended March 31, 2020

Net income - The following items contributed to the change in Net income for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions):

	Three Months Ended
March 31, 2020	$	81
Income tax expense	9
Other operating revenues primarily from the resale of excess natural gas used for fuel in 2021 that did not occur in 2020	7
Revenue from Wheatridge placed in service	4
Gains from Nonqualified benefit trust	4
Depreciation and amortization expense	3
Retail energy deliveries	2
Purchased power and fuel expense	(2)
Wholesale revenues	(12)
March 31, 2021	$	96
Change in Net income	$	15

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Total revenues consist of the following for the periods presented (dollars in millions):

	Three Months Ended March 31,
	2021				2020
Retail (1):
Residential	$	310	51	%	$	279	48	%
Commercial	162		26		159		28
Industrial	60		10		51		9
Direct Access	11		2		11		2
Subtotal	543		89		500		87
Alternative revenue programs, net of amortization	(3)		—		9		2
Other accrued revenues, net (2)	13		2		5		1
Total retail revenues	553		91		514		90
Wholesale revenues	33		5		47		8
Other operating revenues	23		4		12		2
Total revenues	$	609	100	%	$	573	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 $4 million for both 2021 and for 2020. Industrial revenues from ESS customers were $7 million for both 2021 and 2020.

(2) Amount for 2020 is primarily comprised of $6 million in amortization, including interest, related to the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA). For 2021, $11 million resulted from use of the storm cost deferral to partially offset expenses related to the January and February storms.

Total retail revenues — The following items contributed to the increase in Total retail revenues for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions):

	Three Months Ended
March 31, 2020	$	514
Increase as a result of the AUT, approved by the OPUC, with an expected offset in Purchased power and fuel	17
Recovery in Revenues of Storm related expenses in 2021	12
Increase from higher retail energy deliveries driven by the impact of COVID-19 on residential customers in the first quarter 2021 and higher industrial demand	11
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertains to Wheatridge being placed into service	6
Increase as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19	5
Decrease attributed to alternative revenue programs related to the decoupling mechanism due to increased residential use per customer	(12)
March 31, 2021	$	553
Change in Total retail revenues	$	39

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

For the three months ended March 31, 2021 wholesale revenues decreased $14 million, or 30%, from the three months ended March 31, 2020, as a result of a $13 million decrease related to 27% lower wholesale sales volume and a $1 million decrease as a result of a 3% decline in average wholesale sales prices. The reduction in volume resulted from a combination of reduced quarter over quarter thermal generation with the retirement of Boardman, reduced hydro generation, and a 2% increase in retail load requirement.

Other operating revenues for the three months ended March 31, 2021 increased $11 million from the three months ended March 31, 2020 due primarily to market conditions and economic dispatch that provided $10 million more revenue from the resale of natural gas in excess of amounts needed for the Company’s generation portfolio back into the wholesale market. Natural gas prices were significantly higher in 2021 after being depressed in 2020 due to milder than average winter temperatures in North America in 2020 that resulted in an oversupply of natural gas and lower prices.

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.

The following items contributed to the increase in Purchased power and fuel for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions, except for average variable power cost per MWh):

	Three Months Ended
March 31, 2020	$	153
Increase related to average variable power cost per MWh	13
Increase related to total system load	3
March 31, 2021	$	169
Change in Purchased power and fuel	$	16
Average variable power cost per MWh:
March 31, 2020	$	23.31
March 31, 2021	$	27.14
Total system load (MWhs in thousands):
March 31, 2020	6,586
March 31, 2021	6,237

For the three months ended March 31, 2021, the $13 million increase related to the change in average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 19% increase on the average cost of purchased power, offset with a 8% decrease on the average cost for the Company’s own generation. The $3 million increase related to total system load was primarily due to a 20% increase in purchased power (which was purchased at higher average prices), offset by a 17% decrease in the Company’s own generation, driven largely by the retirement of Boardman and lower hydro and wind production.

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PGE’s sources of energy, total system load, and retail load requirement for the periods presented are as follows:

	Three Months Ended March 31,
	2021			2020
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	2,383	38	%	2,433	37	%
Coal	582	9		1,186	18
Total thermal	2,965	47		3,619	55
Hydro	317	5		369	6
Wind	532	9		585	9
Total generation	3,814	61		4,573	70
Purchased power:
Term	1,844	30		1,604	24
Hydro	340	5		345	5
Wind	239	4		64	1
Total purchased power	2,423	39		2,013	30
Total system load	6,237	100	%	6,586	100	%
Less: wholesale sales	(1,245)			(1,693)
Retail load requirement	4,992			4,893

The following table presents the forecasted April-to-September 2021 and the actual 2020 runoff at particular points of major rivers relevant to PGE’s hydro resources:

	Runoff as a Percent of Normal*
Location	2021 Forecast		2020 Actual
Columbia River at The Dalles, Oregon	89	%	104	%
Mid-Columbia River at Grand Coulee, Washington	94		109
Clackamas River at Estacada, Oregon	85		75
Deschutes River at Moody, Oregon	90		86

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

Actual NVPC, the following items contributed to the increase in Actual NVPC for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions):

	Three Months Ended
March 31, 2020	$	106
Increase in Purchased power and fuel expense	16
Decrease (Increase) in Wholesale revenues	14
March 31, 2021	$	136
Change in NVPC	$	30

For further information regarding NVPC in relation to the PCAM, see “Purchased power and fuel expense” and “Revenues” within this “Results of Operations” for more details.

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For the three months ended March 31, 2021 and 2020, actual NVPC was $13 million below and $20 million above baseline NVPC, respectively.

Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be below the baseline and outside the deadband. PGE does not expect its actual regulated ROE to exceed 10.5%, accordingly, no estimated refund to customers is expected under the PCAM for 2021.

Generation, transmission and distribution - The following items contributed to the increase in Generation, transmission and distribution for the three months ended March 31, 2021 compared to the same period in 2020 (dollars in millions):

	Three Months Ended
March 31, 2020	$	73
January and February storm costs recovered via the Company’s storm cost recovery mechanism	12
Decrease primarily due to lower maintenance expense and lower general maintenance costs at some of the Company’s generation facilities	(6)
Miscellaneous expenses	1
March 31, 2021	$	80
Change in Generation, transmission and distribution	$	7

In the first quarter of 2021, PGE deferred $41 million of incremental costs related to February ice storm damage in PGE’s service territory. See “February 2021 Ice Storm” within “Perform as a Business” under the “Overview” section of this Item 2. for more information.

Administrative and other - The following items contributed to the increase in Administrative and other for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions):

	Three Months Ended
March 31, 2020	$	71
Higher legal and other professional service expenses	5
Higher employee wage and benefits expenses	4
Increase to bad debt expense	3
Miscellaneous expenses	3
March 31, 2021	$	86
Change in Administrative and other	$	15

Depreciation and amortization expense decreased $5 million in the three months ended March 31, 2021 compared to the same period in 2020, largely as a result of asset retirements, which were partially offset by capital additions.

Taxes other than income taxes expense increased $3 million in 2021 compared with 2020, primarily due to higher Oregon property taxes.

Interest expense, net increased $1 million in the three months ended March 31, 2021 compared to the same period in 2020. The increase was primarily attributable to the higher average balance of outstanding debt, including short-term debt.

50

Other income, net increased $7 million for the three months ended March 31, 2021 compared to the same period in 2020. The increase was primarily due to market changes on the non-qualified benefit trust.

Income tax expense decreased $9 million for three months ended March 31, 2021, compared to the same period in 2020, with the decreases primarily due to a cumulative catch-up adjustment to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax. See Note 10, Income Taxes in the Notes to Condensed Consolidated Financial Statements in Item 1.—”Financial Statements,” for more information.

LIQUIDITY AND CAPITAL RESOURCES

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, repairs from major storm damage, 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.

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

	Three Months Ended March 31,
	2021		2020
Cash and cash equivalents, beginning of period	$	257	$	30
Net cash provided by (used in):
Operating activities	168		155
Investing activities	(162)		(157)
Financing activities	(128)		2
Increase (decrease) in cash and cash equivalents	(122)		—
Cash and cash equivalents, end of period	$	135	$	30

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 following items contributed to the net change in cash flows from operations for the three months ended March 31, 2021 compared with the three months ended March 31, 2020 (dollars in millions):

51

	Increase/ (Decrease)
Net income	$	15
Deferral of incremental storm costs	(41)
Accounts payable and accrued liabilities	48
Accounts receivable, net	(21)
Margin deposits	18
Decoupling	12
Deferred income tax	(8)
Depreciation and amortization	(5)
Other	(5)
Net change in cash flow from operations	$	13

PGE estimates that non-cash charges for depreciation and amortization in 2021 will range from $410 million to $430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $600 million to $650 million. For additional information, see “Contractual Obligations” in this Liquidity and Capital Resources section of Item 2.

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. Net cash used in investing activities for the three months ended March 31, 2021 increased $5 million when compared with the three months ended March 31, 2020, as capital expenditures related to the IOC and winter storm restoration increased.

Excluding AFDC, the Company plans to make capital expenditures of $700 million in 2021, which it expects to fund with cash to be generated from operations during 2021, as discussed above, and the issuance of short- and long-term debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the three months ended March 31, 2021, net cash provided by financing activities was primarily the result of proceeds from the combination of a $140 million payment on long-term debt, the issuance of a new 364-day term loan of $200 million, repayment of prior 364-day term loan of $150 million, and payment of $36 million of dividends.

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2021 through 2025 (dollars in millions, excluding AFDC).

	2021		2022		2023		2024		2025
Ongoing capital expenditures*	$	600	$	550	$	550	$	550	$	550
Integrated Operations Center	100		—		—		—		—
Total capital expenditures	$	700	$	550	$	550	$	550	$	550
Long-term debt maturities	$	160	$	—	$	—	$	80	$	—

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

Debt and Equity Financings

52

PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.

For 2021, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $600 million to $650 million, issuances of long-term debt securities of up to $350 million, and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments.

Short-term Debt. Pursuant to an order issued by the Federal Energy Regulatory Commission on January 16, 2020, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2022. The following table shows available liquidity as of March 31, 2021 (in millions):

	As of March 31, 2021
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	500	$	—	$	500
Letters of credit (2)	220		75		145
Total credit	$	720	$	75	$	645
Cash and cash equivalents					135
Total liquidity					$	780

(1)Scheduled to expire November 2023.

(2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.

As of March 31, 2021, PGE had a $500 million unsecured revolving credit facility scheduled to expire in November 2023. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash 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 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. As of March 31, 2021, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $500 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.

On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan will bear interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to the terms of the loan. The credit agreement expires on March 30, 2022, with any outstanding balance due and payable on such date. The Company used a portion of the proceeds to repay the prior 364-day $150 million term loan that was issued on April 9, 2020, with the remainder of the proceeds used for general corporate purposes.

53

Long-term Debt. As of March 31, 2021, total long-term debt outstanding, net of $12 million of unamortized debt expense, was $2,906 million. On January 6, 2021, the Company made a $140 million scheduled repayment on a 2.51% Series of FMBs with available cash.

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 46.3% and 45.0% as of March 31, 2021 and December 31, 2020, respectively.

Credit Ratings and Debt Covenants

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

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

In the event Moody’s 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, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits, which is included in Other current assets on the Company’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.

As of March 31, 2021, PGE had posted $19 million of collateral with these counterparties, consisting of $9 million in cash and $10 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2021, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $33 million, and decreases to $7 million by December 31, 2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $119 million and decreases to $84 million by December 31, 2021 and to $77 million by December 31, 2022.

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

The indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2021, under the most restrictive issuance test in the Indenture, the Company could have issued up to $683 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

54

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of March 31, 2021, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 55.2%.

Off-Balance Sheet Arrangements

PGE has no off-balance sheet arrangements, other than surety bonds and outstanding letters of credit, 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.

PGE’s surety bond and letter of credit arrangements are described in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021, there have been no material changes outside the ordinary course of business as of March 31, 2021.

Contractual Obligations

PGE’s contractual obligations for 2021 and beyond are set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021. For such obligations, there have been no material changes outside the ordinary course of business as of March 31, 2021.

Item 3. 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. There have been no material changes to market risks, or credit risk, affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2021, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in PGE’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for information regarding legal proceedings.

55

Item 1A. Risk Factors.

There have been no material changes to PGE’s risk factors set forth in in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021.

56

Item 5. Other Information.

Annual Meeting of Shareholders

PGE held its 2021 annual meeting of shareholders on April 28, 2021. The following proposals were voted on at the meeting by the Company’s shareholders:

1.The election of directors;

2.An advisory, non-binding vote to approve the compensation of the Company’s named executive officers; and

3.The ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2021.

There were 89,575,693 shares of common stock issued and outstanding as of March 1, 2021, the record date for the meeting, with 83,730,106 shares represented at the annual meeting.

Each of the director nominees listed below was elected and the voting results were as follows:

Nominee	For	Against	Abstain	Broker Non-votes
Rodney L. Brown, Jr.	77,760,442	1,099,193	59,551	4,810,920
Jack E. Davis	78,570,131	293,752	55,303	4,810,920
Kirby A. Dyess	77,606,579	1,253,481	59,126	4,810,920
Mark B. Ganz	76,127,207	2,733,497	58,482	4,810,920
Marie O. Huber	78,604,566	264,256	50,364	4,810,920
Kathryn J. Jackson	77,663,051	1,207,714	48,421	4,810,920
Michael A. Lewis	78,616,416	244,084	58,686	4,810,920
Michael H. Millegan	76,831,221	2,028,080	59,885	4,810,920
Neil J. Nelson	77,333,206	1,524,396	61,584	4,810,920
M. Lee Pelton	68,181,861	10,678,035	59,290	4,810,920
Maria M. Pope	77,789,335	1,085,177	44,654	4,810,920
James P. Torgerson	75,535,833	3,324,946	58,407	4,810,920

Shareholders approved the compensation of the Company’s named executive officers. There were 77,823,690 votes cast for the proposal, 996,211 votes cast against the proposal, 99,285 abstentions, and 4,810,920 broker non-votes.

Shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2021. There were 81,865,721 votes cast for the proposal, 1,819,329 votes cast against the proposal, and 45,056 abstentions.

57

Item 6. Exhibits.

Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
10.1	Credit Agreement dated as of March 31, 2021 among Portland General Electric Company, the Borrower; the Lenders; U.S. Bank National Association, as Administrative Agent; and CoBank, ACB as Syndication Agent. (incorporated by reference to Exhibit 10.1 to PGE’s Form 8-K filed April 2, 2021).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed October 30, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language).

Certain instruments defining the rights of holders of other long-term debt of the Company 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. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

SIGNATURE

Pursuant to the requirements 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.

		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)
Date:	April 29, 2021	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)

58

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 29, 2021	By:	/s/ Maria M. Pope
			Maria M. Pope
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James A. Ajello, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 29, 2021	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President of Finance, Chief Financial Officer and Treasurer

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

We, Maria M. Pope, President and Chief Executive Officer, and James A. Ajello, Senior Vice President of Finance, Chief Financial Officer and Treasurer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021, as filed with the Securities and Exchange Commission on April 30, 2021 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”), fully complies with the requirements of that section.

We further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Maria M. Pope		/s/ James A. Ajello
Maria M. Pope		James A. Ajello
President and Chief Executive Officer		Senior Vice President of Finance, Chief Financial Officer and Treasurer
Date:	April 29, 2021	Date:	April 29, 2021

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2021	Apr. 26, 2021
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	001-5532-99
Entity Registrant Name	PORTLAND GENERAL ELECTRIC COMPANY
Entity Incorporation, State or Country Code	OR
Entity Tax Identification Number	93-0256820
Entity Address, Address Line One	121 SW Salmon Street
Entity Address, City or Town	Portland
Entity Address, State or Province	OR
Entity Address, Postal Zip Code	97204
City Area Code	503
Local Phone Number	464-8000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		89,605,758
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Medium-term Notes [Member]
Title of 12(b) Security	9.31% Medium-Term Notes due 2021
Trading Symbol	POR 21
Security Exchange Name	NYSE
Title of 12(b) Security	9.31% Medium-Term Notes due 2021
Trading Symbol	POR 21
Security Exchange Name	NYSE
Common Stock [Member]
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Revenue, net	$ 612	$ 564
Alternative revenue programs, net of amortization	(3)	9
Total revenues	609	573
Operating expenses:
Purchased power and fuel	169	153
Generation, transmission and distribution	80	73
Administrative and other	86	71
Depreciation and amortization	103	108
Taxes other than income taxes	38	35
Total operating expenses	476	440
Income from operations	133	133
Interest expense, net	34	33
Other income:
Allowance for equity funds used during construction	4	3
Miscellaneous income (loss), net	2	(4)
Other income, net	6	(1)
Income before income tax expense	105	99
Income tax expense	9	18
Net income	96	81
Other comprehensive Income	0	1
Comprehensive Income	$ 96	$ 82
Weighted-average common shares outstanding (in thousands):
Basic	89,556	89,429
Diluted	89,703	89,579
Earnings Per Share, Basic and Diluted	$ 1.07	$ 0.91

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 135	$ 257
Accounts receivable, net	268	271
Inventories	67	72
Regulatory assets - current	25	23
Other current assets	127	98
Total current assets	622	721
Electric utility plant, net	7,616	7,539
Regulatory assets - noncurrent	591	569
Nuclear decommissioning trust	44	45
Non-qualified benefit plan trust	43	42
Other noncurrent assets	153	153
Total assets	9,069	9,069
Current liabilities
Accounts payable	199	153
Liabilities from price risk mangement activities - current	20	14
Short-term debt	200	150
Current portion of long-term debt	20	160
Current portion of finance lease obligation	16	16
Accrued expenses and other current liabilities	319	322
Total current liabilities	774	815
Long-term debt, net of current portion	2,886	2,886
Regulatory liabilities-noncurrent	1,353	1,369
Deferred income taxes	391	374
Unfunded status of pension and psotretirement plans	299	299
Liabilities from price risk management activities-noncurrent	118	136
Asset retirement obligations	270	270
Non-qualified benefit plan liabilities	101	101
Finance lease obligations, net of current portion	128	129
Other noncurrent liabilities	74	77
Total liabilities	6,394	6,456
Commitments and contingencies (see notes)
Shareholders' Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2021 and December 31, 2020	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,576,748 and 89,537,331 shares issued and outstanding as of March 31, 2021 and December 31, 2020, respectively	1,233	1,231
Accumulated other comprehensive loss	(11)	(11)
Retained earnings	1,453	1,393
Total shareholders' equity	2,675	2,613
Total liabilities and shareholders' equity	$ 9,069	$ 9,069

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2021	Dec. 31, 2020
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares issued	89,576,748	89,537,331
Common stock, shares outstanding	89,576,748	89,537,331

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash flows from operating activities:
Net income	$ 96	$ 81
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	103	108
Deferred income taxes	(1)	7
Pension and other postretirement benefits	6	6
Allowance for equity funds used during construction	(4)	(3)
Decoupling mechanism deferrals, net of amortization	3	(9)
(Amortization) of net benefits due to Tax Reform	0	(6)
Deferral of incremental storm costs	(41)	0
Other non-cash income and expenses, net	13	19
Changes in working capital:
Decrease in accounts receivable, net	(2)	19
(Increase) in inventories	4	(1)
(Increase)/decrease in margin deposits	(1)	(19)
(Decrease) in accounts payable and accrued liabilities	26	(22)
Other working capital items, net	(14)	(9)
Other, net	(20)	(16)
Net cash provided by operating activities	168	155
Cash flows from investing activities:
Capital expenditures	(153)	(162)
Sales of Nuclear decommissioning trust securities	3	3
Purchases of Nuclear decommissioning trust securities	(3)	(2)
Other, net	(9)	4
Net cash used in investing activities	(162)	(157)
Cash flows from financing activities:
Proceeds from Issuance of long-term debt	0	119
Payments on long-term debt	(140)	(98)
Borrowings on short-term debt	200	20
Repayments of Short-term Debt	(150)	(20)
Issuance of commercial paper, net	0	20
Dividends paid	(36)	(34)
Other	(2)	(5)
Net cash provided by (used in) financing activities	(128)	2
Increase (Decrease) in cash and cash equivalents	(122)	0
Cash and cash equivalents, beginning of period	257	30
Cash and cash equivalents, end of period	135	30
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$ 16	$ 12

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Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2021

Basis of Presentation [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area encompasses 51 incorporated cities entirely within the State of Oregon. As of March 31, 2021, PGE served 909,000 retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein as of and for the three months ended March 31, 2021 and 2020 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2020 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2020, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 19, 2021, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three months ended March 31, 2021 and 2020.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with 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 experienced by the Company could differ materially from those estimates.

Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year.

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Revenue Recognition (Notes)

3 Months Ended

Mar. 31, 2021

Revenue Recognition and Deferred Revenue [Abstract]

Revenue Recognition, Multiple-deliverable Arrangements [Table Text Block]

REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended March 31,
	2021		2020
Retail:
Residential	$	310	$	279
Commercial	162		159
Industrial	60		51
Direct access customers	11		11
Subtotal	543		500
Alternative revenue programs, net of amortization	(3)		9
Other accrued revenues, net	13		5
Total retail revenues	553		514
Wholesale revenues*	33		47
Other operating revenues	23		12
Total revenues	$	609	$	573

* Wholesale revenues include $5 million and $16 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2021 and 2020, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated, tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public 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 energy use by this customer class.

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that have not yet been billed to customers. This amount, classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed 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 customer prices.

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

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

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power; hydro, solar and wind conditions; and daily and seasonal retail demand.

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

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers.

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Balance Sheet Components (Notes)

3 Months Ended

Mar. 31, 2021

Balance Sheet Components [Abstract]

BALANCE SHEET COMPONENTS

BALANCE SHEET COMPONENTS

Inventories

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

Accounts Receivable, Net

Accounts receivable, net includes $86 million and $97 million of unbilled revenues as of March 31, 2021 and December 31, 2020, respectively. Accounts receivable, net is net of an allowance for credit losses of $20 million as of March 31, 2021. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended March 31,
	2021
Balance as of beginning of period	$	16
Increase in provision	7
Amounts written off	(4)
Recoveries	1
Balance as of end of period	$	20

Other Current Assets

Other current assets consist of the following (in millions):

	March 31, 2021		December 31, 2020
Prepaid expenses	$	68	$	57
Assets from price risk management activities	50		33
Margin deposits	9		8
Other current assets	$	127	$	98

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):

	March 31, 2021		December 31, 2020
Electric utility plant	$	11,073	$	10,974
Construction work-in-progress	472		429
Total cost	11,545		11,403
Less: accumulated depreciation and amortization	(3,929)		(3,864)
Electric utility plant, net	$	7,616	$	7,539

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $403 million and $388 million as of March 31, 2021 and December 31, 2020, respectively. Amortization expense related to intangible assets was $15 million for the three months ended March 31, 2021 and 2020. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Regulatory Assets and Liabilities

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

	March 31, 2021					December 31, 2020
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	103	$	—		$	124
Pension and other postretirement plans	—			234		—			240
Debt issuance costs	—			25		—			25
Trojan decommissioning activities	—			97		—			95
Incremental storm costs	—			41		—			—
Other	25			91		23			85
Total regulatory assets	$	25		$	591	$	23		$	569
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,020	$	—		$	1,016
Deferred income taxes	—			222		—			239
Asset retirement obligations	—			38		—			37
Price risk management	30			—		18			—
Other	12			73		5			77
Total regulatory liabilities	$	42	(1)	$	1,353	$	23	(1)	$	1,369

(1)Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Incremental storm costs represents the incremental costs incurred during the three months ended March 31, 2021 to repair damage to PGE’s transmission and distribution systems and restore power to customers. As a result of the historic February winter storms, Oregon’s Governor declared a state of emergency on February 13, 2021. On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) . PGE does not expect an OPUC decision on the February storm deferral until later in 2021 or 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery which could result in a portion or all of PGE’s deferral being disallowed for recovery.

Accrued Expenses and Other Current Liabilities

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

	March 31, 2021		December 31, 2020
Accrued employee compensation and benefits	$	48	$	67
Accrued taxes payable	45		36
Accrued interest payable	43		29
Accrued dividends payable	37		38
Regulatory liabilities—current	42		23
Other	104		129
Total accrued expenses and other current liabilities	$	319	$	322

Credit Facilities

As of March 31, 2021, PGE had a $500 million revolving credit facility scheduled to expire in November 2023. The Company has the ability to expand the revolving credit facility to $600 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2021, PGE was in compliance with this covenant with a 55.2% debt-to-total capital ratio. The aggregate unused available credit capacity under the revolving credit facility was $500 million.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay any commercial paper that may be outstanding at the time. As of March 31, 2021, PGE had no commercial paper outstanding.

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

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $75 million were outstanding as of March 31, 2021. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bore interest for the relevant interest period at LIBOR plus 1.25%. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 31, 2021, this term loan was repaid in full with proceeds from the term loan described below.

On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan will bear interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to terms of the loan. The credit agreement expires on March 30, 2022, with any outstanding balance due and payable on such date. The Company used a portion of the proceeds to repay the prior 364-day term loan, with the remainder of the proceeds used for general corporate purposes.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2022.

Long-term Debt

On January 6, 2021, the Company made a $140 million scheduled repayment on a 2.51% Series of First Mortgage Bonds with available cash.

Defined Benefit Retirement Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Service cost	$	5	$	4
Interest cost*	7		8
Expected return on plan assets*	(11)		(11)
Amortization of net actuarial loss*	5		4
Net periodic benefit cost	$	6	$	5

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

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Fair Value of Financial Instruments (Notes)

3 Months Ended

Mar. 31, 2021

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE estimated the fair value of financial asset and liability instruments as of March 31, 2021 and December 31, 2020, and classified these financial instruments based on a fair value hierarchy that is applied 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:

Level 1	Quoted prices are available in active markets for identical assets or liabilities as of the measurement date;
Level 2	Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date; and
Level 3	Pricing inputs include significant inputs that are unobservable for the asset or liability.

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

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.

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

	As of March 31, 2021
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	72	$	—	$	—	$	—	$	72
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	12		7		—		—		19
Corporate credit	—		12		—		—		12
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	1		—		—		—		1
Debt securities—domestic government	8		—		—		—		8
Price risk management activities: (1) (4)
Electricity	—		14		5		—		19
Natural gas	—		44		2		—		46
	$	94	$	77	$	7	$	13	$	191
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	11	$	123	$	—	$	134
Natural gas	—		3		1		—		4
	$	—	$	14	$	124	$	—	$	138

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

	As of December 31, 2020
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	255	$	—	$	—	$	—	$	255
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		11		—		—		20
Corporate credit	—		13		—		—		13
Money market funds measured at NAV (2)	—		—		—		12		12
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		4		4		—		8
Natural gas	—		36		1		—		37
	$	273	$	64	$	5	$	12	$	354
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		5		141		—		146
Natural gas	—		4		1		—		5
	$	—	$	9	$	142	$	—	$	151

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

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

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

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

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

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE.

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

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

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

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

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

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2021
Electricity physical forwards	$	—	$	123	Discounted cash flow	Electricity forward price (per MWh)	$	5.75	$	73.58	$	33.39
Natural gas financial swaps	2		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.60		4.32		2.22
Electricity financial futures	5		—		Discounted cash flow	Electricity forward price (per MWh)	5.75		73.58		37.97
	$	7	$	124
As of December 31, 2020
Electricity physical forwards	$	—	$	141	Discounted cash flow	Electricity forward price (per MWh)	$	11.17	$	51.18	$	29.74
Natural gas financial swaps	1		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.52		4.33		2.29
Electricity financial futures	4		—		Discounted cash flow	Electricity forward price (per MWh)	8.78		58.42		43.71
	$	5	$	142

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 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 long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.

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 PGE’s position as either the buyer or seller under 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
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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

	Three Months Ended March 31,
	2021		2020
Balance as of the beginning of the period	$	137	$	97
Net realized and unrealized losses/(gains)*	(21)		39
Transfers from Level 3 to Level 2	1		(2)
Balance as of the end of the period	$	117	$	134

* Both realized and unrealized losses/(gains), of which unrealized portion are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

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.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

As of March 31, 2021, the carrying amount of PGE’s long-term debt was $2,906 million, net of $12 million of unamortized debt expense, and its estimated aggregate fair value was $3,359 million. As of December 31, 2020, the carrying amount of PGE’s long-term debt was $3,046 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,808 million.

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Risk Management (Notes)

3 Months Ended

Mar. 31, 2021

Price Risk Management [Abstract]

PRICE RISK MANAGEMENT

RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace 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. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this 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 flows.

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

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

	March 31, 2021		December 31, 2020
Current assets:
Commodity contracts:
Electricity	$	14	$	4
Natural gas	36		29
Total current derivative assets(1)	50		33
Noncurrent assets:
Commodity contracts:
Electricity	5		4
Natural gas	10		8
Total noncurrent derivative assets(1)	15		12
Total derivative assets(2)	$	65	$	45
Current liabilities:
Commodity contracts:
Electricity	$	17	$	13
Natural gas	3		2
Total current derivative liabilities	20		15
Noncurrent liabilities:
Commodity contracts:
Electricity	117		133
Natural gas	1		3
Total noncurrent derivative liabilities	118		136
Total derivative liabilities(2)	$	138	$	151

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of March 31, 2021 and December 31, 2020, no derivative assets or liabilities were designated as hedging instruments.

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):

	March 31, 2021			December 31, 2020
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	154		Decatherms	137		Decatherms
Foreign currency	$	19	Canadian	$	19	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. 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 March 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements was $1 million, comprised solely of natural gas contracts for which PGE posted no collateral. As of December 31, 2020, PGE had no material master netting arrangements.

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Commodity contracts:
Electricity	$	(23)	$	32
Natural Gas	(25)		9
Foreign currency exchange	—		1

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended March 31, 2021 and 2020, net gains of $39 million and net losses of $42 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2021 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2021		2022		2023		2024		2025		Thereafter		Total
Commodity contracts:
Electricity	$	3	$	1	$	8	$	8	$	8	$	87	$	115
Natural gas	(28)		(12)		(2)		—		—		—		(42)
Net unrealized loss/(gain)	$	(25)	$	(11)	$	6	$	8	$	8	$	87	$	73

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 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 derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2021 was $128 million, for which PGE has posted $9 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2021, the cash requirement to either post as collateral or settle the instruments immediately would have been $125 million. As of March 31, 2021, PGE had $8 million cash collateral posted 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 condensed consolidated balance sheet.

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

	March 31, 2021		December 31, 2020
Assets from price risk management activities:
Counterparty A	14	%	12	%
Counterparty B	13		17
Counterparty C	17		21
Counterparty D	14		16
	58	%	66	%
Liabilities from price risk management activities:
Counterparty E	89	%	93	%

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

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Earnings Per Share (Notes)

3 Months Ended

Mar. 31, 2021

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three months ended March 31, 2021, unvested performance-based restricted stock units and related dividend equivalent rights of 373 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 301 thousand shares excluded for the three months ended March 31, 2020.

Net income (loss) is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2021	2020
Weighted-average common shares outstanding—basic	89,556	89,429
Dilutive effect of potential common shares	147	150
Weighted-average common shares outstanding—diluted	89,703	89,579

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Equity (Notes)

3 Months Ended

Mar. 31, 2021

Equity [Abstract]

Equity

SHAREHOLDERS’ EQUITY

The activity in equity during the three-month periods ended March 31, 2021 and 2020 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2020	89,537,331	$	1,231	$	(11)	$	1,393	$	2,613
Issuances of shares pursuant to equity-based plans	39,417	—		—		—		—
Stock-based compensation	—	2		—		—		2
Dividends declared ($0.4075 per share)	—	—		—		(36)		(36)
Net income	—	—		—		96		96
Balances as of March 31, 2021	89,576,748	$	1,233	$	(11)	$	1,453	$	2,675
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	$	1,220	$	(9)	$	1,427	$	2,638

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Contingencies (Notes)

3 Months Ended

Mar. 31, 2021

Contingencies [Abstract]

CONTINGENCIES

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 condensed consolidated financial statements are prepared. 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 PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made.

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

PGE 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) significant facts are in 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 may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

EPA Investigation of Portland Harbor

An 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 as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

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

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

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has

indicated it will take the initial lead to perform remedial design on the remaining areas. The EPA announced on February 12, 2021 that 100 percent of Portland Harbor is under an active engineering design phase.

PGE continues 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 remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position.

In 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 (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe.

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

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

Deschutes River Alliance Clean Water Act Claims

In 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 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 were 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 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 alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had 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 March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the Confederated Tribes of Warm Springs (CTWS), which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant.

In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.

In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. The appeals are fully briefed and oral argument is set for May 7, 2021.

The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome will result in a material loss.

Securities Case

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

During the fourth quarter of 2020, the plaintiff in Hessel voluntarily dismissed his case and the court consolidated Cannataro and PERS of Mississippi into a single case captioned In re Portland General Electric Company Securities Litigation and appointed Public Employees’ Retirement System of Mississippi lead plaintiff (“Lead Plaintiff”). On January 11, 2021, Lead Plaintiff filed an amended complaint asserting causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 for alleged misstatements and omissions regarding, among other things, PGE’s alleged lack of sufficient internal controls and risks associated with PGE's trading activity in wholesale electric markets, purportedly on behalf of purchasers of PGE stock between February 13, 2020, and August 24, 2020 (“the Amended Complaint”). The Amended Complaint demands a jury trial and seeks compensatory damages of an unspecified amount and reimbursement of plaintiffs’ costs, and attorneys’ and expert fees. On March 12, 2021, the defendants filed a motion to dismiss the Amended Complaint. Briefing on the motion to dismiss is ongoing with oral argument set for July 9, 2021.

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

Putative Shareholder Derivative Lawsuits

On January 26, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned Shimberg v. Pope, No. 21- cv-02957, against one current and one former PGE executive and several members of the Company's Board of Directors (collectively, the "Individual Defendants") and naming the Company as a nominal defendant only. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the Individual Defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company of not less than $10 million, equitable relief to remedy the alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. The court has entered an order staying the action until September 15, 2021, or until further order of the court reinstating the action. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

On March 17, 2021, a putative shareholder derivative lawsuit was filed in U.S. District Court for the District of Oregon, captioned JS Halberstam Irrevocable Grantor Trust v. Davis, No. 3:21-cv-00413-SI, against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserts claims for alleged breaches of fiduciary duties, waste of corporate assets, contribution and indemnification, aiding and abetting, and gross mismanagement, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope, 21-cv-13698, against one current and one former PGE executive and several members of the Company's Board of Directors. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company, equitable relief, and an award of plaintiff’s attorneys’ fees and costs. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.

Governmental Investigations

In March and April 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC") and the Division of Enforcement of the SEC, respectively, informed the Company they are conducting investigations arising out of the energy trading losses the Company previously announced in August 2020. The Company is cooperating with the CFTC and the SEC. Management cannot at this time predict the eventual scope or outcome of these matters.

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 that may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

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Guarantees (Notes)	3 Months Ended
	Mar. 31, 2021
Guarantees [Abstract]
GUARANTEES	GUARANTEESPGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas 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 March 31, 2021, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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Income tax Income tax (Notes)

3 Months Ended

Mar. 31, 2021

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended March 31,
	2021		2020
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(8.9)		(10.9)
State and local taxes, net of federal tax benefit	8.8		7.4
Flow-through depreciation and cost basis differences	0.3		1.6
Amortization of excess deferred income tax	(3.2)		(1.9)
Local tax flow-through adjustment	(8.2)		—
Other	(1.2)		1.0
Effective tax rate	8.6	%	18.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030.

Local tax flow-through adjustment

The Company is subject to a local tax that is recovered through a supplemental tariff based on current tax expense, but for which the Company has also recognized deferred income tax expenses over time. Because it is probable that the local deferred taxes will be flowed through future customer prices in accordance with the supplemental tariff, PGE determined a corresponding regulatory asset should have been recorded. PGE recognized a regulatory asset to defer previously recorded deferred income tax expenses in the amount of $9 million with a corresponding credit to Income tax expense in the condensed consolidated statements of income for the three months ended March 31, 2021. The adjustment is immaterial to prior periods.

Carryforwards

Federal tax credit carryforwards as of March 31, 2021 and December 31, 2020 were $79 million and $77 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2041. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2021 will be realized; accordingly, no valuation allowance has been recorded. As of March 31, 2021, and December 31, 2020, PGE had no material unrecognized tax benefits.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2021

Basis of Presentation [Abstract]

Consolidation, Policy [Policy Text Block]

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations

Inventory, Policy [Policy Text Block]

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

Debt, Policy [Policy Text Block]

PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

Fair Value of Financial Instruments, Policy [Policy Text Block]

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 assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.

Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]

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

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

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

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE.

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

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

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

Fair Value Transfer, Policy [Policy Text Block]

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.

Derivatives, Policy [Policy Text Block]

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

Commitments and Contingencies, Policy [Policy Text Block]

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 condensed consolidated financial statements are prepared. 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 PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made.

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

PGE 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) significant facts are in 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 may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Guarantees, Indemnifications and Warranties Policies [Policy Text Block]

Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities.

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2021

Revenue Recognition and Deferred Revenue [Abstract]

Disaggregation of Revenue [Table Text Block]

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

	Three Months Ended March 31,
	2021		2020
Retail:
Residential	$	310	$	279
Commercial	162		159
Industrial	60		51
Direct access customers	11		11
Subtotal	543		500
Alternative revenue programs, net of amortization	(3)		9
Other accrued revenues, net	13		5
Total retail revenues	553		514
Wholesale revenues*	33		47
Other operating revenues	23		12
Total revenues	$	609	$	573

* Wholesale revenues include $5 million and $16 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2021 and 2020, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2021

Balance Sheet Components [Abstract]

Allowance for Credit Losses [Text Block]

The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended March 31,
	2021
Balance as of beginning of period	$	16
Increase in provision	7
Amounts written off	(4)
Recoveries	1
Balance as of end of period	$	20

Schedule of Other Current Assets [Table Text Block]

Other current assets consist of the following (in millions):

	March 31, 2021		December 31, 2020
Prepaid expenses	$	68	$	57
Assets from price risk management activities	50		33
Margin deposits	9		8
Other current assets	$	127	$	98

Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]

Electric utility plant, net consists of the following (in millions):

	March 31, 2021		December 31, 2020
Electric utility plant	$	11,073	$	10,974
Construction work-in-progress	472		429
Total cost	11,545		11,403
Less: accumulated depreciation and amortization	(3,929)		(3,864)
Electric utility plant, net	$	7,616	$	7,539

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	March 31, 2021					December 31, 2020
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	103	$	—		$	124
Pension and other postretirement plans	—			234		—			240
Debt issuance costs	—			25		—			25
Trojan decommissioning activities	—			97		—			95
Incremental storm costs	—			41		—			—
Other	25			91		23			85
Total regulatory assets	$	25		$	591	$	23		$	569
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,020	$	—		$	1,016
Deferred income taxes	—			222		—			239
Asset retirement obligations	—			38		—			37
Price risk management	30			—		18			—
Other	12			73		5			77
Total regulatory liabilities	$	42	(1)	$	1,353	$	23	(1)	$	1,369

(1)Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Other Liabilities Disclosure [Text Block]

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

	March 31, 2021		December 31, 2020
Accrued employee compensation and benefits	$	48	$	67
Accrued taxes payable	45		36
Accrued interest payable	43		29
Accrued dividends payable	37		38
Regulatory liabilities—current	42		23
Other	104		129
Total accrued expenses and other current liabilities	$	319	$	322

Pension and Other Postretirement Benefits Disclosure [Text Block]

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Service cost	$	5	$	4
Interest cost*	7		8
Expected return on plan assets*	(11)		(11)
Amortization of net actuarial loss*	5		4
Net periodic benefit cost	$	6	$	5

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2021

Fair Value of Financial Instruments [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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

	As of March 31, 2021
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	72	$	—	$	—	$	—	$	72
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	12		7		—		—		19
Corporate credit	—		12		—		—		12
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	1		—		—		—		1
Debt securities—domestic government	8		—		—		—		8
Price risk management activities: (1) (4)
Electricity	—		14		5		—		19
Natural gas	—		44		2		—		46
	$	94	$	77	$	7	$	13	$	191
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	11	$	123	$	—	$	134
Natural gas	—		3		1		—		4
	$	—	$	14	$	124	$	—	$	138

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

	As of December 31, 2020
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	255	$	—	$	—	$	—	$	255
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		11		—		—		20
Corporate credit	—		13		—		—		13
Money market funds measured at NAV (2)	—		—		—		12		12
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		4		4		—		8
Natural gas	—		36		1		—		37
	$	273	$	64	$	5	$	12	$	354
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		5		141		—		146
Natural gas	—		4		1		—		5
	$	—	$	9	$	142	$	—	$	151

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $33 million, which are recorded at cash surrender value.

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

Fair Value Option, Disclosures [Table Text Block]

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2021
Electricity physical forwards	$	—	$	123	Discounted cash flow	Electricity forward price (per MWh)	$	5.75	$	73.58	$	33.39
Natural gas financial swaps	2		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.60		4.32		2.22
Electricity financial futures	5		—		Discounted cash flow	Electricity forward price (per MWh)	5.75		73.58		37.97
	$	7	$	124
As of December 31, 2020
Electricity physical forwards	$	—	$	141	Discounted cash flow	Electricity forward price (per MWh)	$	11.17	$	51.18	$	29.74
Natural gas financial swaps	1		1		Discounted cash flow	Natural gas forward price (per Decatherm)	1.52		4.33		2.29
Electricity financial futures	4		—		Discounted cash flow	Electricity forward price (per MWh)	8.78		58.42		43.71
	$	5	$	142

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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

	Three Months Ended March 31,
	2021		2020
Balance as of the beginning of the period	$	137	$	97
Net realized and unrealized losses/(gains)*	(21)		39
Transfers from Level 3 to Level 2	1		(2)
Balance as of the end of the period	$	117	$	134

* Both realized and unrealized losses/(gains), of which unrealized portion are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

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Price Risk Management (Tables)

3 Months Ended

Mar. 31, 2021

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

	March 31, 2021		December 31, 2020
Current assets:
Commodity contracts:
Electricity	$	14	$	4
Natural gas	36		29
Total current derivative assets(1)	50		33
Noncurrent assets:
Commodity contracts:
Electricity	5		4
Natural gas	10		8
Total noncurrent derivative assets(1)	15		12
Total derivative assets(2)	$	65	$	45
Current liabilities:
Commodity contracts:
Electricity	$	17	$	13
Natural gas	3		2
Total current derivative liabilities	20		15
Noncurrent liabilities:
Commodity contracts:
Electricity	117		133
Natural gas	1		3
Total noncurrent derivative liabilities	118		136
Total derivative liabilities(2)	$	138	$	151

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of March 31, 2021 and December 31, 2020, no derivative assets or liabilities were designated as hedging instruments.

Schedule of Derivative Instruments [Table Text Block]

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

	March 31, 2021			December 31, 2020
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	154		Decatherms	137		Decatherms
Foreign currency	$	19	Canadian	$	19	Canadian

Derivatives Not Designated as Hedging Instruments [Table Text Block]

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):

	Three Months Ended March 31,
	2021		2020
Commodity contracts:
Electricity	$	(23)	$	32
Natural Gas	(25)		9
Foreign currency exchange	—		1

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting.

Schedule of Price Risk Derivatives [Table Text Block]

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2021 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2021		2022		2023		2024		2025		Thereafter		Total
Commodity contracts:
Electricity	$	3	$	1	$	8	$	8	$	8	$	87	$	115
Natural gas	(28)		(12)		(2)		—		—		—		(42)
Net unrealized loss/(gain)	$	(25)	$	(11)	$	6	$	8	$	8	$	87	$	73

Schedule of Concentration of Risk, by Counterparty [Table Text Block]

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

	March 31, 2021		December 31, 2020
Assets from price risk management activities:
Counterparty A	14	%	12	%
Counterparty B	13		17
Counterparty C	17		21
Counterparty D	14		16
	58	%	66	%
Liabilities from price risk management activities:
Counterparty E	89	%	93	%

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2021

Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2021	2020
Weighted-average common shares outstanding—basic	89,556	89,429
Dilutive effect of potential common shares	147	150
Weighted-average common shares outstanding—diluted	89,703	89,579

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Equity (Tables)

3 Months Ended

Mar. 31, 2021

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three-month periods ended March 31, 2021 and 2020 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2020	89,537,331	$	1,231	$	(11)	$	1,393	$	2,613
Issuances of shares pursuant to equity-based plans	39,417	—		—		—		—
Stock-based compensation	—	2		—		—		2
Dividends declared ($0.4075 per share)	—	—		—		(36)		(36)
Net income	—	—		—		96		96
Balances as of March 31, 2021	89,576,748	$	1,233	$	(11)	$	1,453	$	2,675
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	$	1,220	$	(9)	$	1,427	$	2,638

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Income tax Income tax (Tables)

3 Months Ended

Mar. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended March 31,
	2021		2020
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(8.9)		(10.9)
State and local taxes, net of federal tax benefit	8.8		7.4
Flow-through depreciation and cost basis differences	0.3		1.6
Amortization of excess deferred income tax	(3.2)		(1.9)
Local tax flow-through adjustment	(8.2)		—
Other	(1.2)		1.0
Effective tax rate	8.6	%	18.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030.

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Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands	Mar. 31, 2021 mi² retail_customers
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	909

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Disaggregation of Revenue [Line Items]
Subtotal	$ 543	$ 500
Alternative revenue programs, net of amortization	(3)	9
Other accrued (deferred) revenues, net	13	5
Total retail revenues	553	514
Wholesale revenues	33	47
Other operating revenue	23	12
Total revenues	609	573
Gain on Derivative Instruments, Pretax	5	16
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	310	279
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	162	159
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	60	51
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 11	$ 11

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Balance Sheet Components Allowance for Credit Losses (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 16
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	7
Accounts Receivable, Allowance for Credit Loss, Writeoff	(4)
Accounts Receivable, Allowance for Credit Loss, Recovery	1
Accounts Receivable, Allowance for Credit Loss	$ 20

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Other Current Assets [Line Items]
Prepaid expenses	$ 68	$ 57
Assets from price risk management activities	50	33
Margin deposits	9	8
Other current assets	$ 127	$ 98

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 11,073	$ 10,974
Construction work-in-progress	472	429
Total cost	11,545	11,403
Less: accumulated depreciation and amortization	(3,929)	(3,864)
Electric utility plant, net	$ 7,616	$ 7,539

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 25		$ 23
Regulatory assets - noncurrent	591		569
Regulatory Liability, Current	42		23
Regulatory liabilities-noncurrent	1,353		1,369
Purchased power and fuel	169	$ 153
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	1,020		1,016
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	222		239
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	38		37
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	0		0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	12		5
Regulatory liabilities-noncurrent	73		77
Regulatory Clause Revenues, under-recovered
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	30		18
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	103		124
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	234		240
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	25		25
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	97		95
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	25		23
Regulatory assets - noncurrent	91		$ 85
Storm Costs
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	$ 41

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Accrued employee compensation and benefits	$ 48	$ 67
Accrued taxes payable	45	36
Accrued interest payable	43	29
Accrued dividends payable	37	38
Regulatory liabilities—current	42	23
Other	104	129
Total accrued expenses and other current liabilities	$ 319	$ 322

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5	$ 4
Interest cost	7	8
Expected return on plan assets	(11)	(11)
Amortization of net actuarial loss	5	4
Net periodic benefit cost	$ 6	$ 5

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Balance Sheet Components (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2020 USD ($)	Apr. 09, 2020 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 20		$ 16
Unbilled Receivables, Current	86		97
Finite-Lived Intangible Assets, Accumulated Amortization	403		388
Amortization of Intangible Assets	15
Line of Credit Facility, Maximum Borrowing Capacity	$ 600
Debt Instrument, Covenant Description	65.00%
Ratio of Indebtedness to Net Capital	0.552
Short-term debt	$ 200		150	$ 150
Line of Credit Facility, Remaining Borrowing Capacity	500
Line of Credit Facility, Current Borrowing Capacity	220	$ 500
Letters of credit issued	75
Authorized Short-Term Debt	900
Long-term Debt, Current Maturities	20		$ 160
Proceeds from Issuance of Long-term Debt	0	119
Purchased power and fuel	169	153
Repayments of Long-term Debt	140	$ 98
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Short-term debt	$ 0

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Assets:
Cash equivalents	$ 72	$ 255
Debt securities:
Domestic government	19	20
Corporate credit	12	13
Money market funds measured at NAV (2)	13	12
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	1	7
Debt securities—domestic government	8	1
Assets from price risk management activities: (1) (3)
Electricity	19	8
Natural gas	46	37
Total	13	12
Assets, Fair Value Disclosure	191	354
Liabilities from price risk management activities: (1) (3)
Electricity	134	146
Natural gas	4	5
Total	138	151
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	72	255
Debt securities:
Domestic government	12	9
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	1	7
Debt securities—domestic government	8	1
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	94	273
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	7	11
Corporate credit	12	13
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	14	4
Natural gas	44	36
Total	77	64
Liabilities from price risk management activities: (1) (3)
Electricity	11	5
Natural gas	3	4
Total	14	9
Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	5	4
Natural gas	2	1
Total	7	5
Liabilities from price risk management activities: (1) (3)
Electricity	123	141
Natural gas	1	1
Total	$ 124	$ 142

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Mar. 31, 2021	Dec. 31, 2020
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 5.75	$ 11.17
Natural gas financial swaps	1.60	1.52
Financial swaps - electricity	5.75	8.78
High [Member]
Commodity Contracts
Electricity physical forwards	73.58	51.18
Natural gas financial swaps	4.32	4.33
Financial swaps - electricity	73.58	58.42
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	33.39	29.74
Natural gas financial swaps	2.22	2.29
Financial swaps - electricity	37.97	43.71
Assets [Member]
Commodity Contracts
Electricity physical forwards	0	0
Natural gas financial swaps	2,000,000	1,000,000
Financial swaps - electricity	5,000,000	4,000,000
Total commodity contracts	7,000,000	5,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	123,000,000	141,000,000
Natural gas financial swaps	1,000,000	1,000,000
Financial swaps - electricity	0	0
Total commodity contracts	$ 124,000,000	$ 142,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 137	$ 97
Net realized and unrealized (gains)/losses	(21)	39
Transfers out of Level 3 to Level 2	1	2
Balance as of the end of the period	$ 117	$ 134

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 33	$ 33
Long-term Debt	2,906	3,046
Unamortized Debt Issuance Expense	12	13
Long-term Debt, Fair Value	$ 3,359	$ 3,808

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Current Assets, Commodity Contracts:
Electricity	$ 14	$ 4
Natural gas	36	29
Total current derivative assets	50	33
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	5	4
Commodity Contract Asset, Noncurrent, Natural Gas	10	8
Derivative Asset, Noncurrent	15	12
Total derivative assets	65	45
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	17	13
Natural gas	3	2
Total current derivative liabilities	20	15
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	117	133
Natural gas	1	3
Total noncurrent derivative liabilities	118	136
Total derivative liabilities	$ 138	$ 151

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2021 CAD ($) MMBTU MWh	Dec. 31, 2020 CAD ($) MWh MMBTU
Commodity contracts:
Electricity | MWh	5	6
Natural gas | MMBTU	154	137
Foreign currency | $	$ 19	$ 19

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Commodity contracts:
Electricity	$ (23)	$ 32
Natural Gas	(25)	9
Foreign currency exchange	$ 0	$ 1

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Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Mar. 31, 2021 USD ($)
Electricity [Member]
Commodity contracts:
2020	$ 3
2021	(1)
2022	8
2023	(8)
2024	8
Thereafter	87
Total	(115)
Natural Gas [Member]
Commodity contracts:
2020	28
2021	(12)
2022	2
2023	0
2024	0
Thereafter	0
Total	(42)
Net Unrealized Loss [Member]
Commodity contracts:
2020	25
2021	(11)
2022	6
2023	(8)
2024	8
Thereafter	87
Total	$ (73)

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Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details)	Mar. 31, 2021	Dec. 31, 2020
Assets from price risk management activities:
Counterparty A	14.00%	12.00%
Counterparty B	13.00%	17.00%
Counterparty C	17.00%	21.00%
Counterparty D	14.00%	16.00%
Concentration of Risk, Derivative Instruments, Assets	58.00%	66.00%
Liabilities from price risk management activities:
Counterparty E	89.00%	93.00%

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ 39	$ 42
Derivative, Net Liability Position, Aggregate Fair Value	128
Collateral Already Posted, Aggregate Fair Value	9
Collateral cash requirement	125
Deposit Assets	8
Purchased power and fuel	169	$ 153
Liabilities, Total [Member]
Derivative Instruments and Hedges, Liabilities	$ 1

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	89,556	89,429
Dilutive effect of potential common shares	147	150
Weighted Average Number of Shares Outstanding, Diluted	89,703	89,579

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	373	301

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Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2021	Sep. 30, 2020	Mar. 31, 2020
Common Stock, Shares, Outstanding beginning of period	89,537,331
Issuance of shares pursuant to equity-based plans		$ 0	$ 0
Stockholders' Equity	$ 2,613		2,591
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent			1
Dividends declared		(36)	(35)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 96	96	81
Common Stock, Shares, Outstanding end of period	89,576,748
Stockholders' Equity	$ 2,675	$ 2,675	$ 2,638
Common Stock, Dividends, Per Share, Declared		$ 0.4075	$ 0.3850
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	$ 2
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,537,331		89,387,124
Issuances of shares pursuant to equity-based plans		39,417	77,397
Common Stock, Shares, Outstanding end of period		89,576,748	89,464,521
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans		$ 0	$ 0
Stockholders' Equity	$ 1,231		1,220
Dividends declared		0	0
Stockholders' Equity		1,233	1,220
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	2
AOCI Attributable to Parent [Member]
Stockholders' Equity	(11)		(10)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent			1
Dividends declared		0	0
Stockholders' Equity		(11)	(9)
Retained Earnings [Member]
Stockholders' Equity	$ 1,393		1,381
Dividends declared		36	35
Stockholders' Equity		$ 1,453	$ 1,427

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Contingencies (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($) party
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties | party	100
Litigation Settlement, Expense	$ 115
Loss Contingency, Estimate of Possible Loss	1,700
Loss Contingency, Damages Sought, Value	1,200
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
Environmental Remediation Expense	$ 6

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%
Federal tax credits	(8.90%)	(10.90%)
State and local taxes, net of federal tax benefit	8.80%	7.40%
Flow through depreciation and cost basis differences	0.30%	1.60%
Excess deferred tax amortization	(3.20%)	(1.90%)
Other	(8.20%)	0.00%
Effective tax rate	8.60%	18.20%
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(1.20%)	1.00%

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Income tax Income tax (Details) - USD ($)	Mar. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 79,000,000	$ 77,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	0
Deferred Tax Assets, Other Tax Carryforwards	$ 9,000,000