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 June 30, 2022

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

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 July 21, 2022 is 89,242,847 shares.

1

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2022

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	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 4.	Controls and Procedures	63
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 6.	Exhibits	63
SIGNATURE		65

2

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym	Definition
AFUDC	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
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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Revenues:
Revenues, net	$	588	$	545	$	1,213	$	1,157
Alternative revenue programs, net of amortization	3		(8)		4		(11)
Total revenues	591		537		1,217		1,146
Operating expenses:
Purchased power and fuel	168		185		370		354
Generation, transmission and distribution	85		76		175		156
Administrative and other	84		79		173		165
Depreciation and amortization	103		101		202		204
Taxes other than income taxes	39		35		79		73
Total operating expenses	479		476		999		952
Income from operations	112		61		218		194
Interest expense, net	38		33		76		67
Other income:
Allowance for equity funds used during construction	3		5		6		9
Miscellaneous income, net	—		3		—		5
Other income, net	3		8		6		14
Income before income tax expense	77		36		148		141
Income tax expense	13		4		24		13
Net income	64		32		124		128
Other comprehensive income	1		—		1		—
Net income and Comprehensive income	$	65	$	32	$	125	$	128
Weighted-average common shares outstanding (in thousands):
Basic	89,225		89,554		89,310		89,555
Diluted	89,371		89,672		89,449		89,687
Earnings per share—Basic and diluted	$	0.72	$	0.36	$	1.39	$	1.43
See accompanying notes to condensed consolidated financial statements.

    

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)                            

	June 30, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	91	$	52
Accounts receivable, net	289		329
Inventories	96		78
Regulatory assets—current	16		24
Other current assets	310		205
Total current assets	802		688
Electric utility plant, net	8,164		8,005
Regulatory assets—noncurrent	498		533
Nuclear decommissioning trust	43		47
Non-qualified benefit plan trust	38		45
Other noncurrent assets	238		176
Total assets	$	9,783	$	9,494
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)                        

	June 30, 2022		December 31, 2021
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	191	$	244
Liabilities from price risk management activities—current	55		47
Current portion of finance lease obligation	21		20
Accrued expenses and other current liabilities	653		457
Total current liabilities	920		768
Long-term debt, net of current portion	3,286		3,285
Regulatory liabilities—noncurrent	1,418		1,360
Deferred income taxes	432		413
Unfunded status of pension and postretirement plans	205		206
Liabilities from price risk management activities—noncurrent	67		90
Asset retirement obligations	244		238
Non-qualified benefit plan liabilities	92		95
Finance lease obligations, net of current portion	297		273
Other noncurrent liabilities	84		59
Total liabilities	7,045		6,787
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2022 and December 31, 2021	—		—
Common stock, no par value, 160,000,000 shares authorized; 89,242,672 and 89,410,612 shares issued and outstanding as of June 30, 2022 and December 31, 2021, respectively	1,241		1,241
Accumulated other comprehensive loss	(9)		(10)
Retained earnings	1,506		1,476
Total shareholders’ equity	2,738		2,707
Total liabilities and shareholders’ equity	$	9,783	$	9,494
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)    

	Six Months Ended June 30,
	2022		2021
Cash flows from operating activities:
Net income	$	124	$	128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202		204
Deferred income taxes	9		6
Pension and other postretirement benefits	7		12
Allowance for equity funds used during construction	(6)		(9)
Decoupling mechanism deferrals, net of amortization	(4)		11
Deferral of incremental storm costs	(3)		(52)
2020 Labor Day wildfire earnings test reserve	15		—
Other non-cash income and expenses, net	38		19
Changes in working capital:
(Increase)/decrease in accounts receivable, net	37		(9)
(Increase)/decrease in inventories	(19)		(3)
(Increase)/decrease in margin deposits	3		(35)
Increase/(decrease) in accounts payable and accrued liabilities	(55)		13
Increase in margin deposits from wholesale counterparties	149		17
Other working capital items, net	6		15
Other, net	(52)		(41)
Net cash provided by operating activities	451		276
See accompanying notes to condensed consolidated financial statements.

7

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)        

	Six Months Ended June 30,
	2022		2021
Cash flows from investing activities:
Capital expenditures	(345)		(326)
Sales of Nuclear decommissioning trust securities	3		7
Purchases of Nuclear decommissioning trust securities	(3)		(5)
Proceeds from sale of properties	12		—
Other, net	(1)		(13)
Net cash used in investing activities	(334)		(337)
Cash flows from financing activities:
Payments on long-term debt	—		(140)
Borrowings on short-term debt	—		200
Repayments of short-term debt	—		(150)
Proceeds from Pelton/Round Butte financing arrangement	25		—
Dividends paid	(77)		(73)
Repurchase of common stock	(18)		(12)
Other	(8)		(4)
Net cash used in financing activities	(78)		(179)
Increase (Decrease) in cash and cash equivalents	39		(240)
Cash and cash equivalents, beginning of period	52		257
Cash and cash equivalents, end of period	$	91	$	17
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	63	$	61
Cash paid for income taxes	16		11
Non-cash investing and financing activities:
Assets obtained under leasing arrangements	29		—
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, as well as buying and selling transmission products and services, in an effort to provide reasonably-priced power for its retail customers. In addition, PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the Federal Energy Regulatory Commission (FERC). 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, entirely within the State of Oregon, encompasses 51 incorporated cities. As of June 30, 2022, PGE served 922,000 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 and six months ended June 30, 2022 and 2021 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 a normal recurring nature, unless otherwise noted. The financial information as of December 31, 2021 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2021, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2022, 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 and six months ended June 30, 2022 and 2021.

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

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale electricity and natural gas, interim financial results do not necessarily represent those to be expected for the year.

Reclassifications

To conform with current year presentation, the Company has reclassified an Increase in margin deposits from wholesale counterparties of $17 million from Other working capital items, net in the operating activities section of the condensed consolidated statements of cash flows for the six months ended June 30, 2021.

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Retail:
Residential	$	250	$	249	$	558	$	559
Commercial	168		170		346		332
Industrial	73		62		142		122
Direct access customers	9		13		17		24
Subtotal	500		494		1,063		1,037
Alternative revenue programs, net of amortization	3		(8)		4		(11)
Other accrued revenues, net	—		(2)		—		11
Total retail revenues	503		484		1,067		1,037
Wholesale revenues*	65		41		121		74
Other operating revenues	23		12		29		35
Total revenues	$	591	$	537	$	1,217	$	1,146

* Wholesale revenues include $14 million and $4 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2022 and 2021, respectively, and $33 million and $9 million for the six months ended June 30, 2022 and 2021, 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

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 (GRC) 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. The Company 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, the Company 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 the Company’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 within the condensed consolidated statements of income and comprehensive income and are not reflected in the line item Revenues, net.

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 and other energy providers.

11

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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. The Company generally determines standalone selling prices based on the prices charged to customers.

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, PGE assesses whether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $94 million and $117 million of unbilled revenues as of June 30, 2022 and December 31, 2021, respectively. Accounts receivable, net is net of an allowance for credit losses of $23 million and $26 million as of June 30, 2022 and December 31, 2021, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2022		2022
Balance as of beginning of period	$	28	$	26
(Decrease)/increase in provision	(2)		4
Amounts written off	(4)		(10)
Recoveries	1		3
Balance as of end of period	$	23	$	23

Other Current Assets

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

	June 30, 2022		December 31, 2021
Prepaid expenses	$	55	$	66
Assets from price risk management activities	221		102
Margin deposits	34		37
Other current assets	$	310	$	205

Assets from price risk management activities and related unrealized gains increased during the six months ended June 30, 2022 due to increases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

12

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Electric Utility Plant, Net

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

	June 30, 2022		December 31, 2021
Electric utility plant	$	12,062	$	11,838
Construction work-in-progress	383		313
Total cost	12,445		12,151
Less: accumulated depreciation and amortization	(4,281)		(4,146)
Electric utility plant, net	$	8,164	$	8,005

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $470 million and $446 million as of June 30, 2022 and December 31, 2021, respectively. Amortization expense related to intangible assets was $14 million and $15 million for the three months ended June 30, 2022 and 2021, respectively and $29 million and $30 million for the six months ended June 30, 2022 and 2021, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Pelton/Round Butte—Under terms of an agreement (the “Agreement”) approved by the OPUC in 2000, PGE had a 66.67% ownership interest in the 455 Megawatts (MW) Pelton/Round Butte hydroelectric project on the Deschutes River (Pelton/Round Butte), with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). In the Agreement, the CTWS had an option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte in 2021. On June 30, 2021, the CTWS notified PGE of their intent to exercise this purchase option. Under the terms of the purchase option, on January 1, 2022, PGE completed the sale of the additional undivided interest in the project at a net book value of $37 million, with no gain or loss recognized on the sale. Under terms of the Agreement, the CTWS has a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If the second option is exercised, the CTWS’ ownership percentage would exceed 50%. PGE remains the operator of the project.

PGE has agreed to purchase 100% of the CTWS’ share of the project’s output under a Power Purchase Agreement (PPA) through 2040. The exercise of the purchase option on January 1, 2022 was evaluated as a sale-leaseback arrangement, and PGE determined that the transaction did not qualify for sale-leaseback accounting. As a result, the transaction is accounted for as a financing arrangement. PGE will continue to record the tangible utility asset within Electric utility plant, net on the condensed consolidated balance sheets as if it were the legal owner and will continue to recognize depreciation expense over the estimated useful life. A financing obligation of $25 million was recorded in Other noncurrent liabilities in the first quarter of 2022. Proceeds related to the financing obligation of $25 million were recorded as a financing activity while proceeds from the sale of intangible property of $11 million and from the sale of construction work-in-progress of $1 million were recorded as an investing activity on the condensed consolidated statements of cash flow. The monthly PPA payments are split between interest expense and a reduction of the principal portion of the financing obligation. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

Battery storage agreement—In the first quarter of 2022, PGE commenced a finance lease for an energy storage agreement with a 20-year term, related to the Wheatridge Renewable Energy Facility. The Company recorded a lease liability and a corresponding right-of-use asset of $29 million in PGE’s condensed consolidated balance sheets.

13

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Regulatory Assets and Liabilities

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

	June 30, 2022					December 31, 2021
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	—	$	—		$	55
Pension and other postretirement plans	—			125		—			131
Debt issuance costs	—			22		—			23
Trojan decommissioning activities	—			99		—			90
February 2021 ice storm and damage	—			72		—			67
Power cost adjustment mechanism	—			30		—			29
2020 Labor Day wildfire	—			30		—			45
COVID-19	—			34		—			36
Wildfire mitigation	—			20		—			—
Other	16			66		24			57
Total regulatory assets	$	16		$	498	$	24		$	533
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,121	$	—		$	1,047
Deferred income taxes	—			201		—			208
Asset retirement obligations	—			4		—			43
Price risk management	165			23		55			—
Other	38			69		51			62
Total regulatory liabilities	$	203	*	$	1,418	$	106	*	$	1,360

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding in PGE’s 2022 GRC, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism, although deferral related to the decoupling mechanism will continue on a prorated basis through the end of 2022. In 2023 and forward, deferral related to the decoupling mechanism will cease. Key elements of the OPUC’s Order also included:

•establishment of a balancing account for the Company’s major storm damage recovery mechanism;

•denial of PGE’s proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project under construction. PGE can pursue recovery in the Company’s next GRC;

•approval of an intervenor request that would require PGE to defer and refund, subject to an earnings test, the revenue requirement associated with the Company’s Boardman coal-fired generating plant included in customer prices following plant closure in 2020; and

•creation of an earnings test for the deferrals for the 2020 Labor Day wildfire and the February 2021 ice storm and damage that is to be applied on a year-by-year basis.

As a result of the earnings tests outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended March 31, 2022 in the amount of $17 million. The amount recorded represents the Company’s estimate based on its interpretation of

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

the OPUC’s earnings test. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no release of deferrals or earnings test reserve is expected for 2021 and 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances compared to the amount reserved by the Company as of June 30, 2022, which could be material.

Wildfire Mitigation represents incremental costs and investments made by PGE under Oregon Senate Bill 762 (SB 762), which was passed in the 2021 legislative session with an effective date of July 19, 2021. SB 762 instructs public utilities to develop, implement, and operate a wildfire protection plan, in which reasonable costs can be recovered through the rates of all customers. The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in base rates in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in base rates. As of June 30, 2022, PGE’s deferred balance related to wildfire mitigation was $20 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence 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.

February 2021 ice storm and damage represents the costs incurred to repair damage to PGE’s transmission and distribution systems and restore power to customers as a result of the historic storms that ultimately led Oregon’s Governor to declare a state of emergency in February 2021. The Company filed an application for authorization to defer emergency restoration costs for the February storms (OPUC Docket UM 2156). PGE received OPUC Order No. 22-020 approving the February storms deferral in the first quarter of 2022. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect the deferred costs in customer prices over a seven year amortization period beginning November 1, 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. The OPUC’s conclusions of overall prudence, including application of the earnings test, 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 Cost Adjustment Mechanism—PGE is subject to a Power Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) net variable power costs (NVPC) forecast each year and included in customer prices via the Company’s Annual Power Cost Update Tariff (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s condensed consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the condensed consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For the year ended December 31, 2021,

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(Unaudited)

actual NVPC was $62 million above baseline NVPC, and therefore PGE deferred $30 million which represents 90% of the excess variance expected to be collected from customers for the year ended December 31. 2021.

2020 Labor Day Wildfire—In 2020, the state of Oregon experienced the most destructive wildfire seasons on record, with over one million acres of land burned that ultimately led Oregon’s Governor to declare a state of emergency. PGE has incurred costs to replace and rebuild PGE facilities damaged by the fires, as well as address 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 (Docket UM 2115). As of June 30, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the wildfire response was $30 million and $45 million, respectively. Among the provisions of Order 22-129, the OPUC established an earnings test for the 2020 Labor Day wildfire deferral. Pursuant to the earnings test outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $15 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. The charge was recorded to Generation, transmission and distribution expenses in the condensed consolidated statements of income. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect in customer prices over a seven year amortization period beginning November 1, 2022. PGE believes amounts deferred as of June 30, 2022 are 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. The OPUC’s conclusion of overall prudence, including application of the earnings test, 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.

COVID-19—The COVID-19 pandemic led Oregon’s Governor to declare a state of emergency on March 8, 2020. Due to the adverse impacts of COVID-19 on economic activity, 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. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent on 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. As of June 30, 2022 and December 31, 2021, PGE’s deferred balance was $34 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. The Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $2 million. The amount recorded represents the Company’s estimate based on its understanding of the OPUC’s intent to apply an earnings test to certain elements of utility COVID deferrals. 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 amounts deferred are 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. The OPUC’s conclusion of overall prudence, including application of earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

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(Unaudited)

Accrued Expenses and Other Current Liabilities

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

	June 30, 2022		December 31, 2021
Accrued employee compensation and benefits	$	51	$	67
Accrued taxes payable	30		46
Accrued interest payable	30		29
Accrued dividends payable	42		40
Regulatory liabilities—current	203		106
Margin deposits from wholesale counterparties	208		58
Other	89		111
Total accrued expenses and other current liabilities	$	653	$	457

Credit Facilities

As of June 30, 2022, PGE had a $650 million revolving credit facility scheduled to expire in September 2026. The Company has the ability to expand the revolving credit facility to $750 million, if needed, subject to the requirements of the agreement. 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, 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 the Company’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 June 30, 2022, PGE was in compliance with this covenant with a 55.6% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $650 million. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. The Company believes these potential adjustments will have an immaterial impact on PGE’s results of operations.

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 in order to allow for coverage of any potential need to repay any commercial paper that may be outstanding at the time. As of June 30, 2022, 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 three 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 $91 million were outstanding as of June 30, 2022. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2024.

17

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(Unaudited)

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Service cost	$	4	$	5	$	8	$	10
Interest cost*	7		7		14		14
Expected return on plan assets*	(12)		(11)		(24)		(22)
Amortization of net actuarial loss*	4		5		8		10
Net periodic benefit cost	$	3	$	6	$	6	$	12

* The net expense portion of non-service cost components are included in Miscellaneous income (expense), 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 June 30, 2022 and December 31, 2021, 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.

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(Unaudited)

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 June 30, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	63	$	—	$	—	$	—	$	63
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		8		—		—		17
Corporate credit	—		12		—		—		12
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	1		—		—		—		1
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		11		—		50
Natural gas	—		235		26		—		261
	$	79	$	294	$	37	$	14	$	424
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	43	$	71	$	—	$	114
Natural gas	—		7		1		—		8
	$	—	$	50	$	72	$	—	$	122

(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 $31 million, which are recorded at cash surrender value.

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

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(Unaudited)

	As of December 31, 2021
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	44	$	—	$	—	$	—	$	44
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		14		—		—		14
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	4		—		—		—		4
Money market funds	1		—		—		—		1
Equity securities	4		—		—		—		4
Price risk management activities: (1) (4)
Electricity	—		16		1		—		17
Natural gas	—		115		5		—		120
	$	62	$	155	$	6	$	14	$	237
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	33	$	90	$	—	$	123
Natural gas	—		13		1		—		14
	$	—	$	46	$	91	$	—	$	137

(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 $36 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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(Unaudited)

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 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 longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument.

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(Unaudited)

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 June 30, 2022
Electricity physical forwards	$	5	$	68	Discounted cash flow	Electricity forward price (per MWh)	$	24.00	$	161.94	$	67.03
Natural gas financial swaps	26		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.98		6.34		3.45
Electricity financial futures	6		3		Discounted cash flow	Electricity forward price (per MWh)	31.42		161.94		80.47
	$	37	$	72
As of December 31, 2021
Electricity physical forwards	$	—	$	90	Discounted cash flow	Electricity forward price (per MWh)	$	16.66	$	129.75	$	43.73
Natural gas financial swaps	5		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.02		8.02		2.81
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	26.76		68.43		52.46
	$	6	$	91

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)

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(Unaudited)

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Balance as of the beginning of the period	$	52	$	117	$	85	$	137
Net realized and unrealized gains*	(19)		(62)		(56)		(83)
Transfers from Level 3 to Level 2	2		3		6		4
Balance as of the end of the period	$	35	$	58	$	35	$	58

* Both realized and unrealized losses/(gains), of which the unrealized portions 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. Includes $2 million in net realized gains and $1 million in net realized losses for the three-month periods ended June 30, 2022 and June 30, 2021. respectively. For the six-month periods ended June 30, 2022 and June 30, 2021, includes $3 million in net realized gains and $2 million in net realized losses, respectively.

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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.

As of June 30, 2022, the carrying amount of PGE’s long-term debt was $3,286 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,092 million. As of December 31, 2021, the carrying amount of PGE’s long-term debt was $3,285 million, net of $14 million of unamortized debt expense, and its estimated aggregate fair value was $3,831 million.

NOTE 5: 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 the Company’s long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions with respect to Company-owned generation resources. The Company also performs portfolio management and wholesale market sales services for third parties in the region. 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 in order 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, future, swap, 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. PGE also enters into non-exchange-traded weather contract options, which are accounted for using the intrinsic value method. In accordance with ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative

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(Unaudited)

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):

	June 30, 2022		December 31, 2021
Current assets:
Commodity contracts:
Electricity	$	40	$	16
Natural gas	181		86
Total current derivative assets (1)	221		102
Noncurrent assets:
Commodity contracts:
Electricity	10		1
Natural gas	80		34
Total noncurrent derivative assets (1)	90		35
Total derivative assets (2)	$	311	$	137
Current liabilities:
Commodity contracts:
Electricity	$	51	$	36
Natural gas	4		11
Total current derivative liabilities	55		47
Noncurrent liabilities:
Commodity contracts:
Electricity	63		87
Natural gas	4		3
Total noncurrent derivative liabilities	67		90
Total derivative liabilities (2)	$	122	$	137

(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 June 30, 2022 and December 31, 2021, 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):

	June 30, 2022			December 31, 2021
Commodity contracts:
Electricity	5		MWhs	4		MWhs
Natural gas	173		Decatherms	181		Decatherms
Foreign currency	$	41	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

24

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(Unaudited)

scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of June 30, 2022 and December 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements were $3 million, for which PGE posted no collateral. Of the gross amounts recognized as of June 30, 2022 and December 31, 2021, $1 million was for electricity and $2 million was for natural gas.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Commodity contracts:
Electricity	$	(14)	$	(44)	$	(54)	$	(67)
Natural Gas	(27)		(89)		(238)		(114)
Foreign currency exchange	1		—		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 June 30, 2022 and 2021, net losses of $15 million and net gains of $112 million, respectively, have been offset. Net gains of $183 million and $151 million have been offset for the six-month periods ended June 30, 2022 and 2021, respectively.

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 June 30, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2022		2023		2024		2025		2026		Thereafter		Total
Commodity contracts:
Electricity	$	9	$	6	$	9	$	11	$	2	$	27	$	64
Natural gas	(117)		(107)		(23)		(7)		1		—		(253)
Net unrealized loss/(gain)	$	(108)	$	(101)	$	(14)	$	4	$	3	$	27	$	(189)

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 June 30, 2022 was $110 million, for which PGE has posted $54 million in collateral, consisting of $21 million of letters of credit and $33 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2022, the cash requirement to either post as collateral or settle the instruments immediately would have been $60 million. As of June 30, 2022, PGE had no 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 sheets.

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(Unaudited)

As of June 30, 2022, PGE received from counterparties $228 million in collateral, consisting of $20 million of letters of credit and $208 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.

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

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 and six months ended June 30, 2022, unvested performance-based restricted stock units and related dividend equivalent rights of 337 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 367 thousand shares excluded for the three and six months ended June 30, 2021.

Net income 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 June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
Weighted-average common shares outstanding—basic	89,225	89,554	89,310	89,555
Dilutive effect of potential common shares	146	118	139	132
Weighted-average common shares outstanding—diluted	89,371	89,672	89,449	89,687

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three- and six-month periods ended June 30, 2022 and 2021 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, 2021	89,410,612	$	1,241	$	(10)	$	1,476	$	2,707
Issuances of shares pursuant to equity-based plans	163,291	—		—		—		—
Stock-based compensation	—	—		—		—		—
Repurchase of common stock	(350,000)	(5)		—		(13)		(18)
Dividends declared ($0.4300 per share)	—	—		—		(40)		(40)
Net income	—	—		—		60		60
Balances as of March 31, 2022	89,223,903	$	1,236	$	(10)	$	1,483	$	2,709
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738
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
Issuances of shares pursuant to equity-based plans	74,974	1		—		—		1
Stock-based compensation	—	4		—		—		4
Repurchase of common stock	(250,000)	(3)		—		(9)		(12)
Dividends declared ($0.4300 per share)	—	—		—		(39)		(39)
Net income	—	—		—		32		32
Balances as of June 30, 2021	89,401,722	$	1,235	$	(11)	$	1,437	$	2,661

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(Unaudited)

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. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then 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.

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(Unaudited)

The EPA finalized a feasibility study, along with a 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 had 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, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. 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 had improved substantially with the passage of time. 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 Company anticipates that remedial design 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 announced on February 12, 2021 that the entirety 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 conclusion of 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. Based on the above facts and remaining uncertainties in the voluntary allocation process, 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. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor 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 (CTWS), 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

29

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(Unaudited)

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 estimated liabilities and environmental expenditures related to Portland Harbor through a combination of third-party proceeds, including but not limited to 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 GRC. 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 collecting any Portland Harbor cost from the PHERA through customer prices.

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, (the “Shimberg Action”) against one current and one former PGE executive and certain members and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought 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. On June 1, 2021, the plaintiff filed an unopposed motion to consolidate this lawsuit with the Ashabraner Action (described below), which the Court granted in an order dated July 27, 2021.

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, (the “JS Halberstam Action”) against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs.

On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope, 21-cv-13698 (the “Ashabraner Action”), against one current and one former PGE executive and certain and former members of the Company's Board of Directors. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought damages to be awarded to the Company, equitable relief, and an award of

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(Unaudited)

plaintiff’s attorneys’ fees and costs. On July 27, 2021, the Court issued an order consolidating the Ashabraner Action with the Shimberg Action.

On May 21, 2021, a putative shareholder derivative lawsuit was filed in the U.S. District Court for the District of Oregon, Portland Division captioned Berning v. Pope, No. 3:21-cv-00783-SI, (the “Berning Action”; collectively with the Shimberg, JS Halberstam, and Ashabraner Actions, the “Derivative Actions”), against one current and one former PGE executive and certain current and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted claims 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 also asserted a claim against the two executives for contribution and indemnity based on alleged violations of Sections 10(b) and 21D of the Exchange Act. The complaint demanded a jury trial and sought multiple forms of relief, including, among other things: a declaration that defendants breached and/or aided and abetted the breach of their fiduciary duties to PGE; an order directing PGE to reform and improve its corporate governance and internal procedures; restitution; and an award of attorneys’ fees, expenses, and costs.

On December 17, 2021, the parties to the Derivative Actions entered into a Memorandum of Understanding to settle the Derivative Actions subject to court approval and other terms (the "MOU"). After the parties entered into the MOU, the Court in the Shimberg and Ashabraner Actions granted an order to abate the proceedings until June 21, 2022. On December 17, 2021, the parties in the JS Halberstam Action filed a motion to stay the proceedings pending submission and court review of the settlement contemplated in the MOU.

On February 11, 2022, the parties to the Derivative Actions entered into a Stipulation of Settlement memorializing the terms of the non-monetary settlement, subject to Court approval, as set forth in the MOU. Under the Stipulation of Settlement, the parties to the JS Halberstam Action agreed to stay the proceedings in the Derivative Actions pending Court approval of the settlement. In addition, the Stipulation of Settlement provided that defendants would not oppose or object to a request by plaintiffs’ counsel for fees and expenses up to $750,000, which was subject to Court approval. Upon final approval of the Court, such fees and expenses were paid by the Company’s insurance provider under its insurance policy. On February 15, 2022, the plaintiff in the JS Halberstam Action filed a motion for preliminary approval of the settlement.

On March 28, 2022, the United States District Court for the District of Oregon entered an order preliminarily approving the settlement and the form and content of the notice to shareholders and set a final hearing for May 9, 2022, in the JS Halberstam Action. On April 18, 2022, the plaintiff in the JS Halberstam Action filed a motion for final approval of the settlement and fee and expense award. On May 9, 2022 the Court issued orders that granted final judgment approval of the settlement.

Governmental Investigations

In March, April and May 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC"), the Division of Enforcement of the SEC, and the Division of Enforcement of the FERC, 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, the SEC, and the FERC. Management cannot at this time predict the eventual scope or outcome of these matters.

Colstrip Litigation

The Company has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is located in the state of Montana and operated by one of the co-owners, Talen Montana, LLC (Talen). Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and

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(Unaudited)

Operation (O&O) Agreement and other matters. In addition, other parties have brought claims against the co-owners, which, along with the co-owner disagreements, are described below. On May 10, 2022, Talen’s parent company, Talen Energy Supply, LLC filed for chapter 11 bankruptcy protection, although Colstrip continues to operate and generate electricity for PGE customers and others.

Petition to compel arbitration—On April 12, 2021, co-owners Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and Portland General Electric Company (the Petitioners) petitioned in Spokane County Superior Court, Washington, Case No. 21201000-32, against another co-owner, NorthWestern Corporation (Northwestern), and Talen to compel the arbitration initiated by NorthWestern to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or whether unanimous consent is required. The O&O Agreement among the parties states that any dispute shall be submitted for resolution to a single arbitrator with appropriate expertise. On April 14, 2021, the Petitioners filed a petition to compel arbitration. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Petitioners filed a motion to remand in June 2021 that was denied. Talen filed a motion, which, following a hearing in July 2021, was granted, to transfer the case to the U.S. District Court for the District of Montana. This matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

Challenge to constitutionality of Montana Senate Bills 265 and 266 (SB 265 and SB 266)—On May 4, 2021, the Petitioners filed a claim against NorthWestern and Talen in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of SB 265, which attempts to void contractual provisions within the co-owner agreement for Colstrip if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. The passage of SB 265 was supported by Defendants and purports to void the O&O Agreement between all parties, which provides for one arbitrator and venue in Spokane, Washington. The petitioners allege that SB 265 violates the contracts clause of the U.S. Constitution and the Montana Constitution, and is preempted by the Federal Arbitration Act (FAA). The Petitioners seek declaratory relief that SB 265 is unconstitutional as applied to the O&O Agreement and the FAA preempts the enforcement of SB 265.

Petitioners filed a First Amended Complaint on May 19, 2021, adding the Attorney General of Montana (Montana AG) as defendant and challenging the constitutionality of SB 266, which purportedly gives the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, or otherwise fails to pay the costs to maintain the plant. Defendant Northwestern filed an answer on June 2, 2021 and asked that the case Talen filed, as described in the “Complaint to implement SB 265 and SB 266” below, and this case be consolidated. On May 27, 2021, Petitioners filed a Motion for Preliminary Injunction, to enjoin the Montana AG from enforcing SB 266 against them. On June 17, 2021, defendants NorthWestern and Talen filed their Oppositions to Motion for Preliminary Injunction (PI) and the Montana AG filed a response taking no position on the PI, stating the State of Montana does not envision enforcing SB 266 any time soon. The Court held a hearing on the Petitioners’ Motion for PI August 6, 2021. On October 13, 2021, the Court issued an order that granted the Petitioners’ Motion for PI, enjoining the Montana AG from enforcing SB 266 against them and on December 17. 2021, the Court further clarified its PI order.

On August 17, 2021, the Petitioners filed for partial summary judgment on their claim to declare unconstitutional or unenforceable SB 265, which purports to invalidate the arbitration provision of the parties’ contract. Talen opposes the motion and Northwestern does not oppose the motion, but requests the Court compel arbitration. On October 29, 2021, the Petitioners filed a motion for summary judgment on their claim to declare unconstitutional and unenforceable SB 266. In November 2021, parties filed responses, opposition, and a motion to stay action on the summary judgment. On December 3, 2021, NorthWestern moved to compel arbitration and to appoint a magistrate to oversee the arbitrator selection process. On December 23, 2021, Petitioners and Talen filed their responses. The Court conducted a hearing on April 26, 2022. A decision on this matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

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(Unaudited)

Complaint to implement Montana SB 265 and SB 266—On May 4, 2021, Talen filed a complaint against the Petitioners and NorthWestern, in the Thirteenth Judicial District Court in the State of Montana, as an attempt to implement Montana laws when determining the language of the O&O agreement based on the recent enactment of SB 265, which purports to invalidate provisions of the co-owner operating agreement regarding arbitration, and SB 266, which purports to give the Montana AG authority to prosecute and levy a $100,000 a day fine against any co-owner who takes steps to close Colstrip without unanimous consent of all co-owners. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. Talen filed a motion to remand the case to the State of Montana District Court. Petitioners and NorthWestern have filed a motion to consolidate this case with the Challenge to constitutionality of Montana Senate Bills 265 and 266, described above. On October 21, 2021, the Court stayed the motion to consolidate pending the outcome of Talen’s petition to remand. On December 1, 2021, the U.S. Magistrate Judge issued Findings and Recommendations to remand the case back to state Court. On December 15, 2021, the Petitioners filed Objections to the Findings and Recommendation. This matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. On December 14, 2020, the original claim was filed in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from the defendants’ coal dust. On August 26, 2021, the claim was amended to add PGE as a defendant. On November 1, 2021, the defendants filed an answer to the complaint. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court. The Court set a trial to begin September 26, 2023.

Since these lawsuits are in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible losses.

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 known 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 June 30, 2022, 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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(Unaudited)

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 Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(9.5)		(11.7)		(10.0)		(9.6)
State and local taxes, net of federal tax benefit	9.0		8.3		9.0		8.7
Flow-through depreciation and cost basis differences	0.6		(3.0)		0.6		(0.5)
Amortization of excess deferred income tax	(4.1)		(3.4)		(4.3)		(3.3)
Local tax flow-through adjustment	—		—		—		(6.1)
Other	(0.1)		(0.1)		(0.1)		(1.0)
Effective tax rate	16.9	%	11.1	%	16.2	%	9.2	%

* 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. In the first quarter of 2021, 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 reflected in the condensed consolidated statements of income for the three months ended March 31, 2021. The adjustment has no impact to the three or six months ended June 30, 2022.

Carryforwards

Federal tax credit carryforwards as of June 30, 2022 and December 31, 2021 were $102 million and $98 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2042. PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2022 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2022, and December 31, 2021, 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 Federal Regulatory Energy Commission (FERC), the Public Utility Commission of Oregon, (OPUC), the Securities and Exchange Commission (SEC), and the Division of Enforcement of the Commodity Futures Trading Commission (CFTC) 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, operating expenses, deferrals, timely recovery of costs, and capital investments, energy trading activities, 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;

•inflation and interest rates;

•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 timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described under the heading of Regulatory Matters in the Overview section of this Item 2, and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements in Item 1. Financial Statements of this Quarterly Report on Form 10-Q;

•natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability;

•unseasonable or extreme weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers’ demand for power and

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PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, PGE’s ability to access the wholesale energy market, PGE’s ability to operate its generating facilities and transmission and distribution systems, the Company’s costs to maintain, repair, and replace such facilities and systems, and recovery of costs;

•PGE’s ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk, which could cause damage to the Company’s own facilities or lead to potential liability if energized systems are involved in wildfires that cause harm;

•operational factors affecting PGE’s power generating facilities and battery storage facilities, including forced outages, unscheduled delays, 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;

•default or nonperformance on the part of any parties from whom PGE purchases capacity or energy, which may cause the Company to incur costs to purchase replacement power and related renewable attributes 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;

•delays in the supply chain and increased supply costs, failure to complete capital projects on schedule or within budget, failure of counterparties to perform under agreements, or the abandonment of capital projects, any of which could result in the Company’s inability to recover project costs, or impact PGE’s competitive position, market share, or results of operations in a material way;

•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, volatility of equity markets 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, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees;

•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, whether global or local in nature, including unseasonable or extreme weather and other natural phenomena that may affect energy costs or consumption, increase the Company’s costs, cause damage to PGE facilities and system, or adversely affect its operations;

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

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

•cybersecurity attacks, data security breaches, physical security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, employee, or Company information;

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•employee workforce factors, including potential strikes, work stoppages, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries since the beginning of the coronavirus (COVID-19) pandemic;

•new federal, state, and local laws that could have adverse effects on operating results;

•failure to achieve the Company’s greenhouse gas emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively responded to legislative requirements concerning greenhouse gas emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation;

•political and economic conditions;

•the impact of widespread health developments, including the global 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

•risks and uncertainties related to 2021 All-Source RFP final shortlist projects, including, but not limited to regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including application of tariffs impacting solar module imports), and legislative uncertainty.

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 United States Securities and Exchange Commission (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 also performs portfolio management and wholesale market sales services for third parties in the region. PGE is committed to developing products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

Company Strategy

The Company exists to power the advancement of society. PGE energizes lives, strengthens communities, and fosters energy solutions that promote social, economic, and environmental progress. The Company is committed to being a clean energy leader and delivering steady growth and returns to shareholders. PGE is focused on working

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with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing greenhouse gas emissions, and responding to evolving customer expectations. At the same time, the Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region. PGE is transforming all aspects of its business to empower its workforce to be even more results oriented to serve customers well. To create a clean energy future, PGE is focused on the following strategic initiatives:

•Decarbonize the power supply by reducing greenhouse gas (GHG) emissions associated with the power served to customers in-line with the GHG reduction targets set by Oregon House Bill (HB) 2021, ultimately achieving zero GHG emissions associated with the power served to customers by 2040;

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

•Perform by improving work efficiency, safety of its workforce, and reliability of its systems and equipment, all while adhering to the Company’s long-term earnings per diluted share growth guidance of 4-6% on average.

Climate change

State-mandated GHG reduction targets—In June 2021, the Oregon legislature passed HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the state. A number of provisions in the bill align with PGE’s strategic direction, and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see the “Environmental Laws and Regulations” section within this Overview.

Empowering customers and communities—PGE’s customers are committed to purchasing clean energy, as over 232 thousand residential and small commercial 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 have similar goals and continue to consider similar goals for the future.

The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.

As of June 30, 2022, the Green Future Impact Program has an approved capacity of 750 Megawatts (MW) nameplate. Through this voluntary program, the Company seeks to support the customers’ clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power.

Extreme weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. In June 2021, temperatures in the region reached all-time recorded highs, shattering the Company’s previous peak load demand, and surpassing the prior summer peak load by nearly 12%. The 2021 wildfire season that followed in Oregon produced what became the largest wildfire in the United States at the time. In February 2021, PGE’s service territory experienced an ice storm, which led to historic levels of customer power outages, and caused considerable expense for service restoration and damage repair (see “February 2021 Ice Storms and Damage” in the “Regulatory Matters” section of this Overview for more information on the impact to PGE’s

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results of operation). In 2020, Oregon experienced the most destructive wildfire season on record, with over one million acres of land burned (see “Wildfire” in the “Regulatory Matters” section of this Overview for more information on the impact to PGE’s results of operation). The increase and severity of extreme weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.

Investing in a clean energy future

PGE’s resource planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. With the passage of HB 2021, PGE will prepare a Clean Energy Plan (CEP), which will articulate the Company’s strategy to meet the 2030 and 2040 decarbonization targets. The first CEP is anticipated to be filed with the OPUC in the Spring of 2023 and will set annual decarbonization targets and articulate how PGE will achieve an equitable transition to a decarbonized grid. PGE’s resource planning analysis and stakeholder engagement will continue to occur through the Integrated Resource Plan (IRP) and Distribution System Plan (DSP) processes.

In May 2020, PGE obtained an OPUC Order acknowledging the Company’s 2019 IRP and associated Action Plan for PGE to acquire resources over the next four years, an important step in acquiring the necessary clean and renewable and capacity resources needed to meet requirements under HB 2021 by 2030. In October 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable and non-emitting resources. PGE estimates that the 2021 All-Source RFP will meet a portion of the Company’s projected need of approximately 2,500 to 3,500 MW of clean and renewable resources and approximately 800 to 1,000 MW of non-emitting dispatchable capacity resources in order to meet the Company’s 2030 emissions reduction target. These projections will be further evaluated and refined in the next IRP and CEP. PGE also expects it will need to exit Colstrip and is actively working on plans to achieve this by the end of 2025.

The 2021 All-Source RFP seeks:

•Approximately 375 to 500 MW of renewable resources;

•Approximately 375 MW of non-emitting dispatchable capacity resources that can be used to meet peak customer demand; and

•One or more resources for the Company’s Green Future Impact Program. Under the Green Future Impact Program, PGE plans to acquire up to 100 MW of new wind, solar, or hybrid renewable and battery storage resources to meet subscriber demand under the PGE supply option. The Company expects the Green Future Impact Program resources considered in the 2021 All-Source RFP to be incremental to the 150 MWa renewable energy target envisioned under the 2019 IRP Action Plan. On July 14, 2022, the OPUC directed PGE to seek additional renewable procurement volumes beyond 150 MWa provided adequate resources remain commercially available as part of the 2021 All-Source RFP. Specifically, the OPUC directed PGE to seek 250 MWa of renewable procurement volume inclusive of the 100 MW Green Future Impact procurement volume.

Renewable resources in PGE’s 2021 All-Source RFP must be eligible under Oregon’s Renewable Portfolio Standard (RPS) and qualify for the federal production tax credit (PTC) or the federal investment tax credit. All resources (dispatchable capacity or renewable) must be online by the end of 2024, with certain exceptions for long-lead time resources.

PGE issued the final 2021 All-Source RFP after receiving approval with modifications from the OPUC in December 2021, and proposals were submitted in January 2022. Bids were evaluated based on the OPUC-approved scoring methodology. Following determination of a final shortlist, PGE submitted a request for acknowledgement of the shortlist to the OPUC on May 5, 2022 that includes seven distinct projects submitted by five bidders for renewable resources and six distinct projects by four bidders for capacity resources.

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The proposals for renewable resources provide various combinations of wind, solar, and battery storage options that include PPAs along with Company-owned resources. The proposals for non-emitting capacity resources provide battery storage and pumped storage options that include PPAs along with Company-owned resources. The ultimate outcome of the 2021 All-Source RFP process may involve the selection of multiple projects for both renewable and capacity resources.

On July 14, 2022, the OPUC acknowledged, subject to additional conditions or directives that may be issued in the final order, PGE’s proposed final shortlist to procure approximately 250 MWa of renewable resources and sufficient non-emitting dispatchable capacity to meet the 2025 system need. 2021 All-Source RFP final shortlist projects were evaluated and selected based on conditions as of the shortlist date. PGE intends to finalize negotiations prior to the end of 2022 to allow sufficient time to capture expiring federal tax credits for the benefit of customers.

In February 2022, NewSun Energy LLC (“NewSun”) filed a petition for judicial review in the Marion County Circuit Court against the OPUC challenging the scoring methodology in the 2021 All-Source RFP. PGE has joined in the case as an intervenor. NewSun also filed a motion to stay the 2021 All-Source RFP process, which the Court subsequently denied. The OPUC filed a motion to dismiss the case and PGE joined the OPUC’s motion to dismiss. NewSun opposed the motion. In May 2022, the Court granted the motion to dismiss to which NewSun responded in June 2022 by filing a notice of appeal with the Court of Appeals of the State of Oregon. PGE cannot predict the outcome of the proceeding or potential impact, if any, to its ongoing 2021 All-Source RFP process.

In October 2021, PGE filed its inaugural Distribution System Plan (DSP), which lays out plans to build a grid that empowers customers to make energy management choices to support decarbonization and supports a two-way energy ecosystem with resources like batteries, EV charging, and solar panels where communities—especially underserved Oregonians—need them. The plan consists of two parts, the first of which was acknowledged by the OPUC on March 8, 2022. Part Two is expected to be filed in August 2022.

In October 2021, PGE filed an extension waiver for the next IRP that the OPUC approved. As a result, the next IRP will be filed for OPUC consideration by March 31, 2023.

Electrify the economy—To help Oregon reach its decarbonization goals, PGE is working to build a safe, reliable, and affordable, economy-wide, clean energy future. The Company is committed to increase electrification of buildings and support the accelerating pace of vehicle electrification.

Transportation electrification is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to develop infrastructure projects aimed at improving accessibility to electric vehicle charging stations, build fleet partnerships, and offer programs to encourage customers to advance transportation electrification.

In 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to Oregon’s carbon reduction goals. In 2020, the OPUC accepted the plan and related costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. In 2021, the Oregon legislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification.

Businesses and families continue to turn to electricity to serve their home and workplace needs and PGE continues to share information on the benefits of electric appliances, landscaping tools and equipment, and heat pumps, which provide efficient heating and cooling. In addition, the Company continues to pursue advanced technologies to enhance the grid, pursue distributed generation and energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs.

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Environmental Laws and Regulations

HB 2021—In June 2021, the Oregon Legislature passed HB 2021, which requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers by 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. The baseline emissions levels for the investor-owned utilities are the average annual GHG emissions for the years 2010, 2011, and 2012 associated with the electricity sold to their retail electricity consumers as reported to the Oregon Department of Environmental Quality (ODEQ).

HB 2021 requires utilities to develop a CEP for meeting the targets concurrent with the development of each IRP. In reviewing the CEP, the OPUC must ensure that utilities demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions and the transition to an equitable grid at reasonable costs to retail electricity consumers. The OPUC is also given authority to apply a performance incentive for early compliance with one or more of the clean energy targets.

Regulated entities will continue to report annual GHG emissions to ODEQ, as they do today. In threshold years, which are 2030, 2035, and 2040 and every year thereafter, the OPUC will use the data reported to ODEQ for that compliance year to determine whether the reduction targets are met. In determining compliance, if the utility has emissions in excess of the target, the OPUC must take into consideration unplanned emissions necessary to meet load if the utility experienced unexpected challenges, such as transmission constraints or under-production from hydro and other renewable resources. The bill also includes certain compliance exceptions to protect customers, including a cost cap and the ability for the OPUC to grant a temporary exemption if a utility is unable to comply with mandatory reliability standards.

HB 2021 also:

•Aligns with PGE decarbonization goals while protecting affordability and reliability;

•Establishes clear decarbonization authority for the OPUC, including authority over ESSs;

•Modernizes competition provisions of Oregon’s electricity restructuring law from 1999, Oregon Senate Bill 1149 (SB 1149);

•Provides clear authority and process for a community-wide green tariff program for customers 30 kilowatts and smaller and allows utilities the ability to earn a return on investments in program resources; and

•Codifies non-bypassability of costs to ensure all customers pay their share of HB 2021 policy costs.

Governor Executive Orders—In 2020, the Governor of Oregon issued an executive order that directed state agencies to integrate climate change and the State’s GHG emissions reduction goals into their plans, budgets, investments, and decisions to the extent allowed by law. Among other things, the executive order directed the OPUC to:

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

•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; and

•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.

In addition, the executive order directed the ODEQ to adopt a program to cap and reduce GHG emissions within the state from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. The ODEQ adopted such a program, referred to as the Climate Protection Plan (CPP), in December 2021. Electricity

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generation from the Company’s natural gas-fired resources is exempt from the CPP. The executive order also strengthened the reduction goals of the State’s Clean Fuels Program and extended the program, from the previous rule that required a ten percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

PGE continues to monitor activities of state agencies that have utilized the executive order to shape state policy or seek to implement the order through their own regulatory authority.

RPS Standards and Other Laws—In 2016, Oregon Senate Bill 1547 (SB 1547) set a benchmark for how much electricity must come from renewable sources and required the elimination of coal from Oregon utility customers’ energy supply no later than 2030.

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 Colstrip from 2042 to 2030. In 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.

Effective May 9, 2022, PGE’s depreciation rates and customer collection changed to reflect accelerated depreciation of Colstrip Units 3 and 4 from December 31, 2030 to December 31, 2025. PGE expects a major step toward meeting its goals under HB 2021 involves the need to exit Colstrip and is actively working on plans to achieve this by the end of 2025. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of PGE’s exit from the generation facility. See Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” for information regarding legal proceedings related to Colstrip.

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 that 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.

Regulatory Matters

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 such matters.

General Rate Case—In July 2021, PGE filed with the OPUC a GRC based on a 2022 test year. The net price increase and annual revenue requirement included a price increase as a result of higher net variable power costs (NVPC) expected in 2022, as reflected in the Annual Power Cost Update Tariff (AUT) filed with the OPUC in April 2021.

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PGE, OPUC staff, and certain customer groups reached an agreement that resolved cost of capital issues and allowed for:

•A capital structure of 50% debt and 50% equity;

•A return on equity of 9.5%; and

•A cost of capital of 6.83%, which reflects updates for actual and forecasted debt costs.

In addition, parties filed a stipulation with the OPUC reflecting an agreement that resolved the annual revenue requirement, average rate base, and corresponding increase authorized in customer prices. The stipulated agreement reflected a final revenue requirement that was based upon an average rate base of $5.6 billion and an annual revenue requirement increase of $74 million consisting of the following changes (in millions):

As filed (includes $40 million related to NVPC)			$	99
Load and NVPC Updates			16
Base Business Revenue Requirement Updates:
Faraday hydro capital-related revenue requirement (1)	$	(18)
Cost of debt settlement including reductions to reflect actual financing costs	(7)
Level III outage annual regulatory accrual (2)	(7)
Other reductions to rate base and operating and maintenance expenses	(5)
Other various modifications to reflect actual costs	(4)
Subtotal			(41)
As revised (includes $64 million related to NVPC) (3)			$	74

(1) The Faraday improvement capital project was not placed in-service as of May 9, 2022, and the capital-related revenue requirement was removed. As of June 30, 2022, the construction work-in-progress balance associated with Faraday was $127 million, including an allowance for funds used during construction (AFUDC).

(2) PGE is authorized to collect 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 the 2022 GRC, the Company requested an annual collection increase from $4 million to $11 million, and agreed to retain the annual collection at $4 million.

(3) Total revenue requirement increase to base rates is $83 million, of which $9 million is not considered incremental as it was already included in current customer prices via a supplemental tariff.

Further, the parties agreed to eliminate PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to this case. Throughout the remainder of 2022, estimated collections from, or refunds to, customers will be pro-rated based on the effective date of new customer prices per the 2022 GRC and expected to be amortized in customer prices in 2024 over a one-year period. The decoupling mechanism provided a means of recovery or refund of margin lost or gained as a result of changes in weather-adjusted energy use per customer in comparison to levels projected in customer prices. For further information on the decoupling mechanism, see “Decoupling” in this Overview section.

On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism. New customer prices as approved by the OPUC became effective May 9, 2022. Price changes for the AUT and items under other supplemental schedules occurred January 1, 2022. Key elements of the OPUC’s Order also included:

•establishment of a balancing account for the Company’s major storm damage recovery mechanism;

•denial of PGE’s proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project. PGE can pursue recovery in the Company’s next GRC;

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•establishment of a deferral that would require PGE to defer and refund, subject to an earnings test, the revenue requirement associated with Boardman included in customer prices following plant closure in 2020 (for more information see “Deferral of Boardman Revenue Requirement” within this “Overview” section); and

•creation of an earnings test for the deferrals for the 2020 Labor Day wildfire and the February 2021 ice storm and damage to be applied on a year-by-year basis.

Complete details of the 2022 GRC filing (OPUC Docket UE 394) and the resulting OPUC Order are available on the OPUC Internet website at www.oregon.gov/puc.

As a result of the earnings tests outlined in the OPUC’s Order, the Company released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended March 31, 2022 in the amount of $17 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no release of deferrals or earnings test reserve is expected for 2021 and 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances compared to the amount reserved by the Company as of June 30, 2022, which could be material.

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.

In March 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 that may qualify for deferral under Docket UM 2114. 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. In September 2020, the OPUC 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 OPUC in October 2020 with final stipulations for the Term Sheet approved in November 2020.

As of June 30, 2022 and December 31, 2021, PGE’s deferred balance was $34 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. Based on the Term Sheet, PGE expects to cease deferring incremental bad debt expense associated with customers who are not on a time payment arrangement, after September 30, 2022. The Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $2 million. The amount recorded represents the Company’s estimate based on its understanding of the OPUC’s intent to apply an earnings test to certain elements of utility COVID deferrals. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings review.

PGE believes the amounts deferred are 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. The OPUC’s 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.

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2020 Labor Day Wildfire—In 2020, Oregon experienced the most destructive wildfire season on record, with over one million acres of land burned. PGE’s wildfire mitigation planning includes regular system-wide risk assessment, which led to the identification and activation of a 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 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.

In October 2020, the OPUC formally approved PGE’s request for deferral of 2020 wildfire-related costs. As of June 30, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the 2020 wildfire response was $30 million and $45 million, respectively. Pursuant to the earnings tests outlined in Order 22-129, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $15 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test.

Wildfire Mitigation—Represents incremental costs and investments made by PGE related to intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises under Oregon Senate Bill 762 (SB 762), which was passed in the 2021 legislative session with an effective date of July 19, 2021. 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. Pursuant to SB 762, PGE submitted a risk-based wildfire protection plan to the OPUC in December 2021. In Order 22-129, the OPUC did not adopt any rate adjustment mechanisms, but rather invited PGE to submit a filing proposing a cost recovery mechanism for incremental wildfire costs consistent with SB 762 and establishing an ongoing review for reasonableness. The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in customer prices in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in customer prices. As of June 30, 2022, PGE’s deferred balance related to wildfire mitigation was $20 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence, 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.

The Company’s deferral application for expenses related to wildfire mitigation, filed in 2019 under OPUC Docket UM 2019, has not yet been approved by the OPUC.

February 2021 Ice Storms and Damage—In February 2021, a historic set of storms involving heavy snow, winds and ice impacted the United States, including PGE’s service territory. 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.

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 June 30, 2022, the Company has deferred a total of $72 million, including interest, related to incremental operating expenses due to the storms. PGE incurred and deferred costs related to replacing and rebuilding PGE facilities damaged by the storms, as well as addressing vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. PGE received OPUC Order No. 22-020 approving the February storms deferral in the first quarter of 2022. While the Company believes the full amount of the deferral is probable of recovery given PGE’s prudently incurred costs were in response to the unique

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and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence, including an earnings test, 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.

Declared states of emergency—In September 2021, the OPUC issued an order that approved a pre-authorized deferral of costs associated with declared states of emergency. Qualifying events would include federal or state declared emergencies with impacts on PGE’s service territory. Previously the Company had to file a request for deferred accounting when an event of that nature occurred, and had to seek OPUC approval of such deferred accounting applications to be effective. With this order, PGE would provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts into customer prices, including a review of utility prudence, in a future proceeding, among other requirements. PGE has not recorded any costs under this deferral order.

Power Costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2022 AUT included a final increase in power costs for 2022, and a corresponding increase in annual revenue requirement, of $64 million from 2021 levels, which were reflected in customer prices effective January 1, 2022. For 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the Company’s power cost adjustment mechanism (PCAM) and related earnings test, PGE has deferred 90% of the excess variance for 2021, or $30 million, which is expected to be collected from customers. See “Power Operations” within this Overview section of Item 2 for more information regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The U.S. Environmental Protection Agency (EPA) has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of June 30, 2022, 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 (ROD) 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. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. 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. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor 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 estimated liabilities and incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including, but not limited to, 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 were to be 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, previously authorized by the OPUC through 2022, was 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

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mechanism provided for collection from (or refund to) customers if weather-adjusted use per customer was less (or more) than that projected in the Company’s most recent GRC.

Collections under the decoupling mechanism were 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 estimated collections recorded in 2022, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2024. No limit existed for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic had resulted in larger estimated refunds under the decoupling mechanism, which had largely offset the revenue increases that had resulted from higher residential demand.

In the 2022 GRC, parties reached an agreement that has eliminated PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to the case, which began May 9, 2022. Pursuant to the GRC Order, the OPUC adopted the agreement such that deferrals will cease in 2023, although amortization of previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices and deferral will continue on a prorated basis through the end of 2022.

For the six months ended June 30, 2022 the Company recorded an estimated total refund of $1 million to residential and commercial customers that resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company continues to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by the COVID-19 pandemic.

As of December 31, 2021, PGE had recorded a total estimated refund of $10 million that, subject to OPUC approval, will be refunded to customers over a one-year period, which would begin January 1, 2023.

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 the Company’s Boardman coal-fired generating plant (Boardman) then included in customer prices as established in the Company’s 2019 GRC. The application stated a deferral was required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. In October 2021, intervenors filed a motion with the OPUC requesting to consolidate the open Boardman deferral docket with PGE’s open 2022 GRC docket. The Administrative Law Judge denied the consolidation, although did provide an opportunity to use the 2022 GRC proceeding to settle any issues with deferrals.

PGE estimated the revenue requirement for Boardman to be $14 million for the period ended December 31, 2020, an additional $66 million for the year ended December 31, 2021, and $23 million for the six months ended June 30, 2022. Based on the application of an earnings test, PGE has not recorded a refund related to Boardman.

In the 2022 GRC Order, the OPUC found that the deferral was warranted with amortization subject to an earnings test. On July 27, 2022, the Company filed an application, which, subject to OPUC approval, will show that the Company did not exceed the earnings test threshold for 2020 or 2021 and consequently, no refund would be required for those years. Customer prices resulting from the 2022 GRC Order no longer include any revenue requirement related to Boardman after new customer prices took effect on May 9, 2022. PGE does not expect to exceed its regulated return on equity under the earnings test for 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances or refunds, which could be material.

Renewable Recovery Framework—As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC, which allows PGE to recover prudently incurred costs through filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent

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costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. There have been no significant filings made under the RAC during 2022.

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. The Company also performs portfolio management and wholesale market sales services for third parties in the region. 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:

	Three Months Ended June 30,		% Increase (Decrease) in Energy Deliveries		Six Months Ended June 30,		% Increase (Decrease) in Energy Deliveries
	2022	2021			2022	2021
Energy deliveries (MWhs in thousands):
Retail:
Residential	1,724	1,764	(2)	%	3,940	4,003	(2)	%
Commercial	1,552	1,601	(3)	%	3,186	3,165	1	%
Industrial	998	916	9	%	1,972	1,813	9	%
Subtotal	4,274	4,281	—	%	9,098	8,981	1	%
Direct access:
Commercial	133	148	(10)	%	264	298	(11)	%
Industrial	441	402	10	%	854	761	12	%
Subtotal	574	550	4	%	1,118	1,059	6	%
Total retail energy deliveries	4,848	4,831	—	%	10,216	10,040	2	%
Wholesale energy deliveries	1,425	1,259	13	%	2,932	2,504	17	%
Total energy deliveries	6,273	6,090	3	%	13,148	12,544	5	%

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	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
Average number of retail customers:
Residential	809,002	88	%	798,799	88	%	807,777	88	%	798,200	88	%
Commercial	112,090	12		110,825	12		111,879	12		110,764	12
Industrial	193	—		190	—		192	—		191	—
Direct access	553	—		584	—		552	—		593	—
Total	921,838	100	%	910,398	100	%	920,400	100	%	909,748	100	%

Total retail energy deliveries for the six months ended June 30, 2022 increased 2% compared with the six months ended June 30, 2021, driven by strong demand from the industrial customer class.

The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Residential usage continues to be elevated as remote and hybrid work schedules remain in place across the Company’s service area, although total deliveries declined slightly, reflecting the impact of relative temperatures as 2022 saw heating and cooling degree-days closer to average than what was experienced during the first six months of 2021.

The following table indicates the number of heating and cooling degree-days for the three and six months ended June 30, 2022 and 2021, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-days					Cooling Degree-days
	2022		2021		Avg.	2022		2021		Avg.
First Quarter	1,761		1,805		1,846	—		—		—
April	454		290		365	—		—		2
May	242		167		184	—		21		24
June	65		41		75	75		217		74
Second Quarter	761		498		624	75		238		100
Year-to-date	2,522		2,303		2,470	75		238		100
Increase/(decrease) from the 15-year average	2	%	(7)	%		(25)	%	138	%

After adjusting for the effects of weather, total retail energy deliveries for the six months ended June 30, 2022 increased 2.7% compared to the same period of 2021. The increase reflects 10% higher industrial delivery volumes, 1% more commercial delivery volumes, and residential deliveries that declined marginally when compared to the prior year. Residential weather-adjusted deliveries saw average usage per customer 1.5% lower during the first six months of 2022 compared with 2021, while the average number of residential customers was 1.2% greater during 2022 than 2021.

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 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 six months of 2022.

In early February 2020, PGE began offering service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, 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 11% of PGE’s total retail energy deliveries for the first six months of 2022 and 2021.

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Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. 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. PGE continuously makes economic dispatch decisions based on numerous factors, such as plant availability, customer demand, river flows, wind conditions, and current wholesale prices. 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 six months ended June 30, 2022 and 2021:

	Plant availability (1)				Actual energy provided compared to projected levels (2)				Actual energy provided as a percentage of total retail load
	2022		2021		2022		2021		2022		2021
Generation:
Thermal:
Natural gas	84	%	87	%	78	%	175	%	33	%	45	%
Coal (3)	83		78		91		105		10		9
Wind (4)	74		85		80		112		9		13
Hydro	96		94		81		76		6		6

(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 reflects Colstrip, which PGE does not operate.

(4)Plant availability includes Wheatridge, which PGE does not operate.

Energy received from PGE-owned and jointly-owned thermal plants during the six months ended June 30, 2022 compared to 2021 decreased 19%. This decrease is primarily related to PGE’s natural gas-fired plant which have been displaced by higher hydroelectric generation and purchases, and economic dispatch decisions in response to higher natural gas prices. 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, increased 35% during the six months ended June 30, 2022 compared to 2021 primarily due to increased runoff resulting from favorable snowpack conditions. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 44% while energy generated by the Company-owned facilities decreased 3% in the six months ended June 30, 2022 largely as a result of PGE’s sale of 16.66% of its ownership interest in Pelton/Round Butte to the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS), effective January 1, 2022. PGE purchases 100% of the CTWS’s share of the project output. 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 decreased 19% during the six months ended June 30, 2022 compared to 2021 primarily due to unplanned plant outages during the period. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind

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generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available.

Under PGE’s PCAM, the Company may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no 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 six months ended June 30, 2022 and 2021, respectively:

•For the six months ended June 30, 2022, actual NVPC was $32 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2022 is currently estimated to be below the baseline, and outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE is estimated to be below 10.5% there is no estimated refund to customers expected under the PCAM for 2022.

•For the six months ended June 30, 2021, actual NVPC was $6 million below baseline NVPC. For the year ended December 31, 2021, actual NVPC was $62 million above baseline NVPC, which was outside the established deadband range. Pursuant to the PCAM, as PGE’s preliminary regulatory ROE was below 8.5% pursuant to the related earnings test PGE deferred $30 million, which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s 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.

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Results of Operations

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

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

	Three Months Ended June 30,				% Increase (Decrease)		Six Months Ended June 30,				% Increase (Decrease)
	2022		2021				2022		2021
Total revenues	$	591	$	537	10	%	$	1,217	$	1,146	6	%
Operating expenses:
Purchased power and fuel	168		185		(9)	%	370		354		5	%
Generation, transmission and distribution	85		76		12	%	175		156		12	%
Administrative and other	84		79		6	%	173		165		5	%
Depreciation and amortization	103		101		2	%	202		204		(1)	%
Taxes other than income taxes	39		35		11	%	79		73		8	%
Total operating expenses	479		476		1	%	999		952		5	%
Income from operations	112		61		84	%	218		194		12	%
Interest expense, net*	38		33		15	%	76		67		13	%
Other income:
Allowance for equity funds used during construction	3		5		(40)	%	6		9		(33)	%
Miscellaneous income, net	—		3		(100)	%	—		5		(100)	%
Other income, net	3		8		(63)	%	6		14		(57)	%
Income before income tax expense	77		36		114	%	148		141		5	%
Income tax expense	13		4		225	%	24		13		85	%
Net income	64		32		100	%	124		128		(3)	%
Other comprehensive income	1		—		—	%	1		—		—	%
Net income and Comprehensive income	$	65	$	32	103	%	$	125	$	128	(2)	%

* Includes an allowance for borrowed funds used during construction of $1 million and $2 million for the three months ended June 30, 2022 and 2021, and $3 million and $4 million for the six months ended June 30, 2022 and 2021, respectively.

Net income for the three months ended June 30, 2022 was double that of the three months ended June 30, 2021 as total revenues increased while Purchased power and fuel expenses declined. Revenues increased as a result of several factors, including an increase in customer prices to cover anticipated higher net variable power costs as authorized by the OPUC in the AUT. The Company was able to optimize forward contracts for power and natural gas to lower its Purchased power and fuel expense compared to the same period of 2021, thus improving income from operations. Wholesale revenues also increased substantially while Other operating revenues reflected gains from the sale of excess natural gas back into the market. Total operating expenses were comparable to the prior year quarter as the savings in Purchased power and fuel expense mostly offset modest increases in the other line items. Other income declined primarily due to changes in performance of the Non-qualified benefit plan trust assets. Income taxes increased due primarily to higher Income before income tax expense.

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Net income for the six months ended June 30, 2022 was comparable to the same period of 2021. Wholesale revenues were the largest contributor to higher revenues in 2022 as both volumes and prices have increased. Increases in Retail revenues were led by the increase in customer prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT, which were anticipated to be offset by higher power costs.

Retail energy deliveries increased 2%, primarily driven by continued growth in industrial demand, including high-tech manufacturing. The impact of higher natural gas and electricity prices coupled with increased customer demand also drove Purchased power and fuel expense up. Retail revenues were impacted by a slightly lower average price mix in 2022 as a result of the increased demand in the industrial sector. Increases in Operating expenses reflect the result pursuant to the earnings tests outlined in Order 22-129, expenses related to service restoration costs, and continued vegetation management activities. Higher relative Income tax expense in 2022 reflects higher Income before income tax expense in the second quarter of 2022 as well as the favorable impact of a local tax flow-through adjustment that occurred in the first quarter of 2021.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2022				2021				2022				2021
Retail:
Residential	$	250	42	%	$	249	46	%	$	558	46	%	$	559	49	%
Commercial	168		28		170		32		346		29		332		29
Industrial	73		12		62		11		142		12		122		11
Direct Access*	9		2		13		2		17		1		24		2
Subtotal	500		84		494		91		1,063		88		1,037		91
Alternative revenue programs, net of amortization	3		1		(8)		(1)		4		—		(11)		(1)
Other accrued revenues, net	—		—		(2)		—		—		—		11		1
Total retail revenues	503		85		484		90		1,067		88		1,037		91
Wholesale revenues	65		11		41		8		121		10		74		6
Other operating revenues	23		4		12		2		29		2		35		3
Total revenues	$	591	100	%	$	537	100	%	$	1,217	100	%	$	1,146	100	%

* Commercial revenues from Direct Access customers for the three and six months ended June 30, 2022 were $3 million and $6 million, respectively. For the comparable three- and six-month periods of 2021, revenues were $5 million and $9 million, respectively. Industrial revenues from Direct Access customers for the three and six months ended June 30, 2022 were $6 million and $11 million, respectively. For the comparable three- and six-month periods of 2021, revenues were $7 million and $15 million, respectively.

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Total retail revenues—The following items contributed to the increase in Total retail revenues for the three and six months ended June 30, 2022 compared to the same periods in 2021 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2021	$	484	$	1,037
Increase as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)	16		36
Increase from higher retail energy deliveries driven by customer load growth	2		17
Increase attributed to alternative revenue programs related to the decoupling mechanism due primarily to increased residential use per customer in 2021 and prorated elimination of the mechanism in 2022	4		1
Decrease resulting from the combination of various supplemental tariffs and adjustments	(3)		(2)
Recovery in Revenues of storm related expenses	4		(7)
Decrease 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 economic recovery and increased industrial demand	(4)		(15)
June 30, 2022	$	503	$	1,067
Change in Total retail revenues	$	19	$	30

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 June 30, 2022, Wholesale revenues increased $24 million or 59% from the three months ended June 30, 2021 as an $18 million increase from 40% higher average wholesale sales price was combined with a $6 million increase due to a 13% increase in sales volumes. Although prices were high in the three months ended June 30, 2021 due to weaker than average regional hydro production in 2021, reduced regional capacity, and the demand impact resulting from the extreme heat event experienced in June 2021, prices have continued to increase during 2022 due to strong demand, the impact on natural gas prices due to global energy issues, and ongoing capacity limitations in the region.

Wholesale revenues for the six months ended June 30, 2022 increased $47 million from the six months ended June 30, 2021, as the average wholesale sales price increased 39% driving $34 million of the increase. The higher sales prices have resulted from several factors including the overall economic recovery and macroeconomic factors impacting the energy commodity markets, but were driven largely by higher natural gas prices. In addition, sales volumes were up 17%, which contributed another $13 million.

Other operating revenues increased $9 million for the three months ended June 30, 2022 compared with the same period in 2021 as market conditions allowed the Company to sell excess natural gas at a gain.

In the six months ended June 30, 2022, Other operating revenues decreased $6 million compared to the same period of 2021. In the first quarter of 2021, market conditions allowed the Company to sell excess natural gas at a gain of $10 million, whereas in 2022 such excess gas was sold at a $6 million loss.

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

The following items contributed to the change in Purchased power and fuel for the three and six months ended June 30, 2022 compared to the same period in 2021 (dollars in millions, except for average variable power cost per Megawatt hour (MWh)):

	Three Months Ended		Six Months Ended
June 30, 2021	$	185	$	354
Decrease related to average variable power cost per MWh	(61)		(57)
Increase related to total system load	44		73
June 30, 2022	168		370
Change in Purchased power and fuel	$	(17)	$	16
Average variable power cost per MWh:
June 30, 2021	$	32.08	$	29.51
June 30, 2022	$	28.40	$	29.43
Total system load (MWhs in thousands):
June 30, 2021	5,754		11,991
June 30, 2022	5,946		12,594

For the three months ended June 30, 2022, the $61 million decrease related to the change in average variable power cost per MWh was driven by a 22% decrease in the average cost of purchased power and a 51% decrease on the average cost for the Company’s own generation. Total energy received from hydroelectric generation sources, both PGE-owned and purchased, increased significantly due to above average runoff conditions, which reduced power costs and economically displaced power from the Company’s higher cost natural gas-fired plant sources. The $44 million increase related to total system load was primarily due to a 42% increase in deliveries of energy obtained from purchased power based on economic dispatch decisions. This was offset by a 29% decrease in the Company’s own generation.

For the six months ended June 30, 2022, the $57 million decrease related to the change in average variable power cost per MWh was driven by a 10% decrease in the average cost of purchased power and a 25% decrease on the average cost for the Company’s own generation. The $73 million increase related to total system load was primarily due to a 38% increase in deliveries of energy obtained from purchased power resulting from the economic displacement of gas facilities in 2022. This was offset by an 18% decrease in the Company’s own generation.

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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 June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	1,086	18	%	1,906	33	%	3,235	26	%	4,289	36	%
Coal	356	6		313	5		966	8		895	7
Total thermal	1,442	24		2,219	38		4,201	34		5,184	43
Hydro	293	5		264	5		566	4		581	5
Wind	516	9		665	12		908	7		1,197	10
Total generation	2,251	38		3,148	55		5,675	45		6,962	58
Purchased power:
Hydro	2,002	33		1,343	23		3,564	27		2,472	21
Wind	250	4		244	4		445	4		482	4
Solar	216	4		175	3		329	3		267	2
Natural Gas	—	—		—	—		2	—		4	—
Waste, Wood and Landfill Gas	42	1		44	1		79	1		83	1
Source not specified	1,185	20		800	14		2,500	20		1,721	14
Total purchased power	3,695	62		2,606	45		6,919	55		5,029	42
Total system load	5,946	100	%	5,754	100	%	12,594	100	%	11,991	100	%
Less: wholesale sales	(1,425)			(1,259)			(2,932)			(2,504)
Retail load requirement	4,521			4,495			9,662			9,487

Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
Sources of energy (MWhs in thousands):
PURPA purchased power:
Hydro	8	5	14	10
Wind	8	9	13	15
Solar	178	164	282	252
Waste, Wood and Landfill Gas	24	29	45	47
Total	218	207	354	324

The following table presents the forecast April-to-September 2022 and the actual 2021 runoff at particular points of major rivers relevant to PGE’s hydro resources:

	Runoff as a Percent of Normal*
Location	2022 Forecast		2021 Actual
Columbia River at The Dalles, Oregon	110	%	82	%
Mid-Columbia River at Grand Coulee, Washington	114		89
Clackamas River at Estacada, Oregon	141		70
Deschutes River at Moody, Oregon	94		84

* 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.

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Actual NVPC for the three and six months ended June 30, 2022 decreased compared to the same period in 2021 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2021	$	144	$	280
Purchased power and fuel expense	(17)		16
Wholesale revenues	(24)		(47)
June 30, 2022	$	103	$	249
Change in NVPC	$	(41)	$	(31)

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.

For the three months ended June 30, 2022 and 2021, actual NVPC was $17 million below and $19 million above baseline NVPC, respectively. For the six months ended June 30, 2022 and 2021, actual NVPC was $32 million below and $6 million above baseline NVPC, respectively.

Based on forecast data, NVPC for the year ending December 31, 2022 is currently estimated to be below the baseline, and outside the deadband. Pursuant to the PCAM’s earnings test, because PGE’s preliminary regulatory ROE is expected to be below 10.5%, there is no estimated refund to customers expected under the PCAM for 2022.

Generation, transmission and distribution increased as follows for the three and six months ended June 30, 2022 compared to the same periods in 2021 (in millions):

	Three Months Ended		Six Months Ended
June 30, 2021	$	76	$	156
Release of previously deferred amounts pursuant to earnings test created in OPUC 2022 GRC Order	—		16
Higher service restoration and storm response costs, other than February 2021 wind and ice storm restoration expenses	7		6
Higher employee compensation and benefits expenses	3		6
(Lower)/higher distribution vegetation management, inspection, and maintenance expenses	(1)		3
February 2021 wind and ice storm restoration expenses	—		(13)
Miscellaneous expenses	—		1
June 30, 2022	$	85	$	175
Change in Generation, transmission and distribution	$	9	$	19

PGE experienced higher Generation, transmission and distribution expenses largely from vegetation management activities coupled with a strong labor market and rising cost of materials and supplies.

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Administrative and other increased for the three and six months ended June 30, 2022 compared to the same periods in 2021 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2021	$	79	$	165
Regulatory program amortization	2		3
Higher professional service expenses	2		2
(Lower)/higher employee compensation and benefits expenses	(2)		1
Lower bad debt expense	(2)		(3)
Miscellaneous expenses	5		5
June 30, 2022	$	84	$	173
Change in Administrative and other	$	5	$	8

Higher Administrative and other expenses reflect increases for employee wage and benefit expenses and outside services, including labor, driven by a strong labor market, as well as the cost of materials.

Depreciation and amortization expense increased $2 million for three months ended June 30, 2022 compared to the same period in 2021. The increase for the three months ended June 30, 2022 was driven by accelerated depreciation of the Colstrip facility as approved by the OPUC’s 2022 GRC Order and commenced in May 2022, as well as higher plant balances from capital additions, partially offset by regulatory amortization and deferral activity.

Depreciation and amortization expense decreased $2 million for the six months ended June 30, 2022, compared to the same period in 2021. The decrease was driven by regulatory amortizations and deferral activity, partially offset by accelerated depreciation of the Colstrip facility, as well as higher plant balances from capital additions.

Taxes other than income taxes expense increased $4 million and $6 million in the three and six months ended June 30, 2022, respectively, compared to the same periods in 2021. The increases for both the three and six months ended were driven by higher franchise, payroll, and property tax expenses.

Interest expense, net increased $5 million and $9 million in the three and six months ended June 30, 2022 compared to the same periods in 2021 due to higher lease-related interest expenses and higher long-term debt balances.

Other income, net decreased $5 million and $8 million for the three and six months ended June 30, 2022 compared to the same periods in 2021. The decreases were driven by unfavorable market changes on the non-qualified benefit trust and lower AFUDC equity income on lower construction work-in-progress balances.

Income tax expense increased $9 million and $11 million for three and six months ended June 30, 2022, compared to the same period in 2021. The increase for the three months ended June 30, 2022 was driven by an increase in pre-tax income. The increase for the six months ended June 30, 2022 was driven by a cumulative catch-up adjustment recorded in the first quarter of 2021 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.

Critical Accounting Policies and Estimates

There have been no material changes to the Company’s critical accounting policies and estimates as previously disclosed in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 17, 2022.

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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 (in millions):

	Six Months Ended June 30,
	2022		2021
Cash and cash equivalents, beginning of period	$	52	$	257
Net cash provided by (used in):
Operating activities	451		276
Investing activities	(334)		(337)
Financing activities	(78)		(179)
Increase (decrease) in cash and cash equivalents	39		(240)
Cash and cash equivalents, end of period	$	91	$	17

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 six months ended June 30, 2022 compared with the six months ended June 30, 2021 (in millions):

	Increase/ (Decrease)
Decrease in Net income	$	(4)
Increase in Margin deposits received from wholesale counterparties due to natural gas commodity prices	132
Increase related to Margin deposits paid to wholesale counterparties due to natural gas commodity prices	38
Increase related to the Deferral of incremental storm costs in 2021	49
Increase as a result of changes in Accounts receivable and Unbilled revenue	46
Decrease in Accounts payable primarily due to the timing of payments to vendors	(68)
Increase related to the 2020 Labor Day wildfire earnings test reserve non-cash adjustment to Net income	15
Change in Decoupling mechanism deferrals, net of amortization	(15)
Other miscellaneous changes	(18)
Net change in cash flow from operations	$	175

PGE estimates that non-cash charges for depreciation and amortization in 2022 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.

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Cash Flows from Investing Activities—Net cash used in investing activities for the six months ended June 30, 2022 decreased $3 million when compared with the six months ended June 30, 2021. 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, which increased $20 million, offset by a $12 million decrease related to proceeds from the sale of property and a $12 million decrease in other costs of removal related to the 2021 winter storm restoration.

Excluding AFUDC, the Company plans to make capital expenditures of $755 million in 2022, which it expects to fund with cash to be generated from operations during 2022, 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—During the six months ended June 30, 2022, net cash used in financing activities was primarily the result of payment of $77 million of dividends, proceeds from failed sale-leaseback transactions of $25 million, and repurchase of common stock of $18 million.

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2022 through 2026, excluding AFUDC (in millions).

	2022		2023		2024		2025		2026
Ongoing capital expenditures(1)	$	735	$	635	$	650	$	650	$	650
Integrated Operations Center	20		15		—		—		—
Total capital expenditures(2)	$	755	$	650	$	650	$	650	$	650
Long-term debt maturities	$	—	$	—	$	—	$	—	$	—

(1) Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connections. Includes accrued capital additions, preliminary engineering, removal costs, and certain intangible working capital assets.

(2) Amounts are estimates as of the date of this report and may be affected by economic conditions, including but not limited to, impacts of inflation, changes to the cost of materials and labor, and financing costs.

Debt and Equity Financings

PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors, 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 2022, 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 $220 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.

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Short-term Debt. Pursuant to an order issued by the FERC on January 20, 2022, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2024. The following table shows available liquidity as of June 30, 2022 (in millions):

	As of June 30, 2022
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	650	$	—	$	650
Letters of credit (2)	220		91		129
Total credit	$	870	$	91	$	779
Cash and cash equivalents					91
Total liquidity					$	870

(1)Scheduled to expire September 2026.

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

In September 2021, PGE amended and restated its existing revolving credit facility. As of June 30, 2022, PGE had a $650 million revolving credit facility scheduled to expire in September 2026. 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. In addition, the Credit Facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. 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, 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 June 30, 2022, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $650 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.

Long-term Debt. As of June 30, 2022, PGE’s total long-term debt outstanding, net of $13 million of unamortized debt expense, was $3,286 million.

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 45.5% and 45.2% as of June 30, 2022 and December 31, 2021 respectively.

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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
Issuer credit rating	A3	BBB+
Senior secured debt	A1	A
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 in PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.

As of June 30, 2022, PGE had posted $59 million of collateral with these counterparties, consisting of $29 million in cash and $30 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 June 30, 2022, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $90 million, and decreases to $22 million by December 31, 2022. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $170 million and decreases to $103 million by December 31, 2022 and to $92 million by December 31, 2023.

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 First Mortgage Bonds (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 June 30, 2022, under the most restrictive issuance test in the Indenture, the Company could have issued up to $618 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.

PGE’s revolving credit facility contains 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 June 30, 2022, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 55.6%.

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

62

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, 2021, filed with the SEC on February 17, 2022.

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 June 30, 2022, 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.

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, 2021, filed with the SEC on February 17, 2022.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

PGE did not repurchase any shares of its common stock during the three-month period ended June 30, 2022.

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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).
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 July 28, 2022, 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.

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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:	July 27, 2022	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President Finance CFO, Treasurer & Corporate Compliance Officer
			(duly authorized officer and principal financial officer)

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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:	July 27, 2022	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:	July 27, 2022	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President Finance CFO, Treasurer & Corporate Compliance Officer

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 Finance CFO, Treasurer & Corporate Compliance Officer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022, as filed with the Securities and Exchange Commission on July 28, 2022 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 Finance CFO, Treasurer & Corporate Compliance Officer
Date:	July 27, 2022	Date:	July 27, 2022

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Cover Page - shares	6 Months Ended
	Jun. 30, 2022	Jul. 21, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
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
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
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		89,242,847
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenue, net	$ 588	$ 545	$ 1,213	$ 1,157
Alternative revenue programs, net of amortization	3	(8)	4	(11)
Total revenues	591	537	1,217	1,146
Operating expenses:
Purchased power and fuel	168	185	370	354
Generation, transmission and distribution	85	76	175	156
Administrative and other	84	79	173	165
Depreciation and amortization	103	101	202	204
Taxes other than income taxes	39	35	79	73
Total operating expenses	479	476	999	952
Income from operations	112	61	218	194
Interest expense, net	38	33	76	67
Other income:
Allowance for equity funds used during construction	3	5	6	9
Miscellaneous income (loss), net	0	3	0	5
Other income, net	3	8	6	14
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	77	36	148	141
Income tax expense	13	4	24	13
Net income	64	32	124	128
Other comprehensive Income	1	0	1	0
Comprehensive Income	$ 65	$ 32	$ 125	$ 128
Weighted-average common shares outstanding (in thousands):
Basic	89,225	89,554	89,310	89,555
Diluted	89,371	89,672	89,449	89,687
Earnings Per Share, Basic and Diluted	$ 0.72	$ 0.36	$ 1.39	$ 1.43

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current assets:
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 91	$ 52
Accounts receivable, net	289	329
Inventories	96	78
Regulatory assets - current	16	24
Other current assets	310	205
Total current assets	802	688
Electric utility plant, net	8,164	8,005
Regulatory assets - noncurrent	498	533
Nuclear decommissioning trust	43	47
Non-qualified benefit plan trust	38	45
Other noncurrent assets	238	176
Total assets	9,783	9,494
Current liabilities
Accounts payable	191	244
Liabilities from price risk mangement activities - current	55	47
Current portion of finance lease obligation	21	20
Accrued expenses and other current liabilities	653	457
Total current liabilities	920	768
Long-term debt, net of current portion	3,286	3,285
Regulatory liabilities-noncurrent	1,418	1,360
Deferred income taxes	432	413
Unfunded status of pension and psotretirement plans	205	206
Liabilities from price risk management activities-noncurrent	67	90
Asset retirement obligations	244	238
Non-qualified benefit plan liabilities	92	95
Finance lease obligations, net of current portion	297	273
Other noncurrent liabilities	84	59
Total liabilities	7,045	6,787
Commitments and contingencies (see notes)
Shareholders' Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2022 and December 31, 2021	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,242,672 and 89,410,612 shares issued and outstanding as of June 30, 2022 and December 31, 2021, respectively	1,241	1,241
Accumulated other comprehensive loss	(9)	(10)
Retained earnings	1,506	1,476
Total shareholders' equity	2,738	2,707
Total liabilities and shareholders' equity	$ 9,783	$ 9,494

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2022	Dec. 31, 2021
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	89,242,672	89,410,612
Common stock, shares outstanding	89,242,672	89,410,612

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash flows from operating activities:
Net income	$ 124	$ 128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202	204
Deferred income taxes	9	6
Pension and other postretirement benefits	7	12
Allowance for equity funds used during construction	(6)	(9)
Decoupling mechanism deferrals, net of amortization	(4)	11
Deferral of incremental storm costs	(3)	(52)
2020 Labor Day wildfire earnings test reserve	15	0
Other non-cash income and expenses, net	38	19
Changes in working capital:
Decrease in accounts receivable, net	37	(9)
(Increase) in inventories	(19)	(3)
(Increase)/decrease in margin deposits	3	(35)
(Decrease) in accounts payable and accrued liabilities	(55)	13
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	149	17
Other working capital items, net	6	15
Other, net	(52)	(41)
Net cash provided by operating activities	451	276
Cash flows from investing activities:
Capital expenditures	(345)	(326)
Sales of Nuclear decommissioning trust securities	3	7
Purchases of Nuclear decommissioning trust securities	(3)	(5)
Proceeds from Sale of Property, Plant, and Equipment	12	0
Other, net	(1)	(13)
Net cash used in investing activities	(334)	(337)
Cash flows from financing activities:
Payments on long-term debt	0	(140)
Borrowings on short-term debt	0	200
Repayments of Short-term Debt	0	(150)
Proceeds from failed sale-leaseback transactions	25	0
Dividends paid	(77)	(73)
Repurchase of common stock	(18)	(12)
Other	(8)	(4)
Net cash provided by (used in) financing activities	(78)	(179)
Increase (Decrease) in cash and cash equivalents	39	(240)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	91	17
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	63	61
Cash paid for income taxes, net	16	11
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 29	$ 0

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Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2022

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, as well as buying and selling transmission products and services, in an effort to provide reasonably-priced power for its retail customers. In addition, PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the Federal Energy Regulatory Commission (FERC). 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, entirely within the State of Oregon, encompasses 51 incorporated cities. As of June 30, 2022, PGE served 922,000 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 and six months ended June 30, 2022 and 2021 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 a normal recurring nature, unless otherwise noted. The financial information as of December 31, 2021 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2021, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2022, 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 and six months ended June 30, 2022 and 2021.

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 electricity and natural gas, interim financial results do not necessarily represent those to be expected for the year.

Reclassifications

To conform with current year presentation, the Company has reclassified an Increase in margin deposits from wholesale counterparties of $17 million from Other working capital items, net in the operating activities section of the condensed consolidated statements of cash flows for the six months ended June 30, 2021.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2022

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Retail:
Residential	$	250	$	249	$	558	$	559
Commercial	168		170		346		332
Industrial	73		62		142		122
Direct access customers	9		13		17		24
Subtotal	500		494		1,063		1,037
Alternative revenue programs, net of amortization	3		(8)		4		(11)
Other accrued revenues, net	—		(2)		—		11
Total retail revenues	503		484		1,067		1,037
Wholesale revenues*	65		41		121		74
Other operating revenues	23		12		29		35
Total revenues	$	591	$	537	$	1,217	$	1,146

* Wholesale revenues include $14 million and $4 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2022 and 2021, respectively, and $33 million and $9 million for the six months ended June 30, 2022 and 2021, 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 (GRC) 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. The Company 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, the Company 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 the Company’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 within the condensed consolidated statements of income and comprehensive income and are not reflected in the line item Revenues, net.

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 and other energy providers.

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. The Company generally determines standalone selling prices based on the prices charged to customers.

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Balance Sheet Components (Notes)

6 Months Ended

Jun. 30, 2022

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, PGE assesses whether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $94 million and $117 million of unbilled revenues as of June 30, 2022 and December 31, 2021, respectively. Accounts receivable, net is net of an allowance for credit losses of $23 million and $26 million as of June 30, 2022 and December 31, 2021, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2022		2022
Balance as of beginning of period	$	28	$	26
(Decrease)/increase in provision	(2)		4
Amounts written off	(4)		(10)
Recoveries	1		3
Balance as of end of period	$	23	$	23

Other Current Assets

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

	June 30, 2022		December 31, 2021
Prepaid expenses	$	55	$	66
Assets from price risk management activities	221		102
Margin deposits	34		37
Other current assets	$	310	$	205

Assets from price risk management activities and related unrealized gains increased during the six months ended June 30, 2022 due to increases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

Electric Utility Plant, Net

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

	June 30, 2022		December 31, 2021
Electric utility plant	$	12,062	$	11,838
Construction work-in-progress	383		313
Total cost	12,445		12,151
Less: accumulated depreciation and amortization	(4,281)		(4,146)
Electric utility plant, net	$	8,164	$	8,005

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $470 million and $446 million as of June 30, 2022 and December 31, 2021, respectively. Amortization expense related to intangible assets was $14 million and $15 million for the three months ended June 30, 2022 and 2021, respectively and $29 million and $30 million for the six months ended June 30, 2022 and 2021, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Pelton/Round Butte—Under terms of an agreement (the “Agreement”) approved by the OPUC in 2000, PGE had a 66.67% ownership interest in the 455 Megawatts (MW) Pelton/Round Butte hydroelectric project on the Deschutes River (Pelton/Round Butte), with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). In the Agreement, the CTWS had an option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte in 2021. On June 30, 2021, the CTWS notified PGE of their intent to exercise this purchase option. Under the terms of the purchase option, on January 1, 2022, PGE completed the sale of the additional undivided interest in the project at a net book value of $37 million, with no gain or loss recognized on the sale. Under terms of the Agreement, the CTWS has a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If the second option is exercised, the CTWS’ ownership percentage would exceed 50%. PGE remains the operator of the project.

PGE has agreed to purchase 100% of the CTWS’ share of the project’s output under a Power Purchase Agreement (PPA) through 2040. The exercise of the purchase option on January 1, 2022 was evaluated as a sale-leaseback arrangement, and PGE determined that the transaction did not qualify for sale-leaseback accounting. As a result, the transaction is accounted for as a financing arrangement. PGE will continue to record the tangible utility asset within Electric utility plant, net on the condensed consolidated balance sheets as if it were the legal owner and will continue to recognize depreciation expense over the estimated useful life. A financing obligation of $25 million was recorded in Other noncurrent liabilities in the first quarter of 2022. Proceeds related to the financing obligation of $25 million were recorded as a financing activity while proceeds from the sale of intangible property of $11 million and from the sale of construction work-in-progress of $1 million were recorded as an investing activity on the condensed consolidated statements of cash flow. The monthly PPA payments are split between interest expense and a reduction of the principal portion of the financing obligation. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

Battery storage agreement—In the first quarter of 2022, PGE commenced a finance lease for an energy storage agreement with a 20-year term, related to the Wheatridge Renewable Energy Facility. The Company recorded a lease liability and a corresponding right-of-use asset of $29 million in PGE’s condensed consolidated balance sheets.

Regulatory Assets and Liabilities

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

	June 30, 2022					December 31, 2021
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	—	$	—		$	55
Pension and other postretirement plans	—			125		—			131
Debt issuance costs	—			22		—			23
Trojan decommissioning activities	—			99		—			90
February 2021 ice storm and damage	—			72		—			67
Power cost adjustment mechanism	—			30		—			29
2020 Labor Day wildfire	—			30		—			45
COVID-19	—			34		—			36
Wildfire mitigation	—			20		—			—
Other	16			66		24			57
Total regulatory assets	$	16		$	498	$	24		$	533
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,121	$	—		$	1,047
Deferred income taxes	—			201		—			208
Asset retirement obligations	—			4		—			43
Price risk management	165			23		55			—
Other	38			69		51			62
Total regulatory liabilities	$	203	*	$	1,418	$	106	*	$	1,360

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding in PGE’s 2022 GRC, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism, although deferral related to the decoupling mechanism will continue on a prorated basis through the end of 2022. In 2023 and forward, deferral related to the decoupling mechanism will cease. Key elements of the OPUC’s Order also included:

•establishment of a balancing account for the Company’s major storm damage recovery mechanism;

•denial of PGE’s proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project under construction. PGE can pursue recovery in the Company’s next GRC;

•approval of an intervenor request that would require PGE to defer and refund, subject to an earnings test, the revenue requirement associated with the Company’s Boardman coal-fired generating plant included in customer prices following plant closure in 2020; and

•creation of an earnings test for the deferrals for the 2020 Labor Day wildfire and the February 2021 ice storm and damage that is to be applied on a year-by-year basis.

As a result of the earnings tests outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended March 31, 2022 in the amount of $17 million. The amount recorded represents the Company’s estimate based on its interpretation of

the OPUC’s earnings test. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no release of deferrals or earnings test reserve is expected for 2021 and 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances compared to the amount reserved by the Company as of June 30, 2022, which could be material.

Wildfire Mitigation represents incremental costs and investments made by PGE under Oregon Senate Bill 762 (SB 762), which was passed in the 2021 legislative session with an effective date of July 19, 2021. SB 762 instructs public utilities to develop, implement, and operate a wildfire protection plan, in which reasonable costs can be recovered through the rates of all customers. The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in base rates in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in base rates. As of June 30, 2022, PGE’s deferred balance related to wildfire mitigation was $20 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence 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.

February 2021 ice storm and damage represents the costs incurred to repair damage to PGE’s transmission and distribution systems and restore power to customers as a result of the historic storms that ultimately led Oregon’s Governor to declare a state of emergency in February 2021. The Company filed an application for authorization to defer emergency restoration costs for the February storms (OPUC Docket UM 2156). PGE received OPUC Order No. 22-020 approving the February storms deferral in the first quarter of 2022. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect the deferred costs in customer prices over a seven year amortization period beginning November 1, 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. The OPUC’s conclusions of overall prudence, including application of the earnings test, 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 Cost Adjustment Mechanism—PGE is subject to a Power Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) net variable power costs (NVPC) forecast each year and included in customer prices via the Company’s Annual Power Cost Update Tariff (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s condensed consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the condensed consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For the year ended December 31, 2021,

actual NVPC was $62 million above baseline NVPC, and therefore PGE deferred $30 million which represents 90% of the excess variance expected to be collected from customers for the year ended December 31. 2021.

2020 Labor Day Wildfire—In 2020, the state of Oregon experienced the most destructive wildfire seasons on record, with over one million acres of land burned that ultimately led Oregon’s Governor to declare a state of emergency. PGE has incurred costs to replace and rebuild PGE facilities damaged by the fires, as well as address 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 (Docket UM 2115). As of June 30, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the wildfire response was $30 million and $45 million, respectively. Among the provisions of Order 22-129, the OPUC established an earnings test for the 2020 Labor Day wildfire deferral. Pursuant to the earnings test outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $15 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. The charge was recorded to Generation, transmission and distribution expenses in the condensed consolidated statements of income. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect in customer prices over a seven year amortization period beginning November 1, 2022. PGE believes amounts deferred as of June 30, 2022 are 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. The OPUC’s conclusion of overall prudence, including application of the earnings test, 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.

COVID-19—The COVID-19 pandemic led Oregon’s Governor to declare a state of emergency on March 8, 2020. Due to the adverse impacts of COVID-19 on economic activity, 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. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent on 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. As of June 30, 2022 and December 31, 2021, PGE’s deferred balance was $34 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. The Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $2 million. The amount recorded represents the Company’s estimate based on its understanding of the OPUC’s intent to apply an earnings test to certain elements of utility COVID deferrals. 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 amounts deferred are 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. The OPUC’s conclusion of overall prudence, including application of earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

Accrued Expenses and Other Current Liabilities

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

	June 30, 2022		December 31, 2021
Accrued employee compensation and benefits	$	51	$	67
Accrued taxes payable	30		46
Accrued interest payable	30		29
Accrued dividends payable	42		40
Regulatory liabilities—current	203		106
Margin deposits from wholesale counterparties	208		58
Other	89		111
Total accrued expenses and other current liabilities	$	653	$	457

Credit Facilities

As of June 30, 2022, PGE had a $650 million revolving credit facility scheduled to expire in September 2026. The Company has the ability to expand the revolving credit facility to $750 million, if needed, subject to the requirements of the agreement. 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, 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 the Company’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 June 30, 2022, PGE was in compliance with this covenant with a 55.6% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $650 million. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. The Company believes these potential adjustments will have an immaterial impact on PGE’s results of operations.

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 in order to allow for coverage of any potential need to repay any commercial paper that may be outstanding at the time. As of June 30, 2022, 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 three 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 $91 million were outstanding as of June 30, 2022. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2024.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Service cost	$	4	$	5	$	8	$	10
Interest cost*	7		7		14		14
Expected return on plan assets*	(12)		(11)		(24)		(22)
Amortization of net actuarial loss*	4		5		8		10
Net periodic benefit cost	$	3	$	6	$	6	$	12

* The net expense portion of non-service cost components are included in Miscellaneous income (expense), 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)

6 Months Ended

Jun. 30, 2022

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 June 30, 2022 and December 31, 2021, 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 June 30, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	63	$	—	$	—	$	—	$	63
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		8		—		—		17
Corporate credit	—		12		—		—		12
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	1		—		—		—		1
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		11		—		50
Natural gas	—		235		26		—		261
	$	79	$	294	$	37	$	14	$	424
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	43	$	71	$	—	$	114
Natural gas	—		7		1		—		8
	$	—	$	50	$	72	$	—	$	122

(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 $31 million, which are recorded at cash surrender value.

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

	As of December 31, 2021
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	44	$	—	$	—	$	—	$	44
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		14		—		—		14
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	4		—		—		—		4
Money market funds	1		—		—		—		1
Equity securities	4		—		—		—		4
Price risk management activities: (1) (4)
Electricity	—		16		1		—		17
Natural gas	—		115		5		—		120
	$	62	$	155	$	6	$	14	$	237
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	33	$	90	$	—	$	123
Natural gas	—		13		1		—		14
	$	—	$	46	$	91	$	—	$	137

(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 $36 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 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 longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument.

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 June 30, 2022
Electricity physical forwards	$	5	$	68	Discounted cash flow	Electricity forward price (per MWh)	$	24.00	$	161.94	$	67.03
Natural gas financial swaps	26		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.98		6.34		3.45
Electricity financial futures	6		3		Discounted cash flow	Electricity forward price (per MWh)	31.42		161.94		80.47
	$	37	$	72
As of December 31, 2021
Electricity physical forwards	$	—	$	90	Discounted cash flow	Electricity forward price (per MWh)	$	16.66	$	129.75	$	43.73
Natural gas financial swaps	5		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.02		8.02		2.81
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	26.76		68.43		52.46
	$	6	$	91

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Balance as of the beginning of the period	$	52	$	117	$	85	$	137
Net realized and unrealized gains*	(19)		(62)		(56)		(83)
Transfers from Level 3 to Level 2	2		3		6		4
Balance as of the end of the period	$	35	$	58	$	35	$	58

* Both realized and unrealized losses/(gains), of which the unrealized portions 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. Includes $2 million in net realized gains and $1 million in net realized losses for the three-month periods ended June 30, 2022 and June 30, 2021. respectively. For the six-month periods ended June 30, 2022 and June 30, 2021, includes $3 million in net realized gains and $2 million in net realized losses, respectively.

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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.

As of June 30, 2022, the carrying amount of PGE’s long-term debt was $3,286 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,092 million. As of December 31, 2021, the carrying amount of PGE’s long-term debt was $3,285 million, net of $14 million of unamortized debt expense, and its estimated aggregate fair value was $3,831 million.

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Risk Management (Notes)

6 Months Ended

Jun. 30, 2022

Price Risk Management [Abstract]

RISK MANAGEMENT

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 the Company’s long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions with respect to Company-owned generation resources. The Company also performs portfolio management and wholesale market sales services for third parties in the region. 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 in order 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, future, swap, 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. PGE also enters into non-exchange-traded weather contract options, which are accounted for using the intrinsic value method. In accordance with ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative

instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not intend to engage in trading activities for non-retail purposes.

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

	June 30, 2022		December 31, 2021
Current assets:
Commodity contracts:
Electricity	$	40	$	16
Natural gas	181		86
Total current derivative assets (1)	221		102
Noncurrent assets:
Commodity contracts:
Electricity	10		1
Natural gas	80		34
Total noncurrent derivative assets (1)	90		35
Total derivative assets (2)	$	311	$	137
Current liabilities:
Commodity contracts:
Electricity	$	51	$	36
Natural gas	4		11
Total current derivative liabilities	55		47
Noncurrent liabilities:
Commodity contracts:
Electricity	63		87
Natural gas	4		3
Total noncurrent derivative liabilities	67		90
Total derivative liabilities (2)	$	122	$	137

(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 June 30, 2022 and December 31, 2021, 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):

	June 30, 2022			December 31, 2021
Commodity contracts:
Electricity	5		MWhs	4		MWhs
Natural gas	173		Decatherms	181		Decatherms
Foreign currency	$	41	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 June 30, 2022 and December 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements were $3 million, for which PGE posted no collateral. Of the gross amounts recognized as of June 30, 2022 and December 31, 2021, $1 million was for electricity and $2 million was for natural gas.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Commodity contracts:
Electricity	$	(14)	$	(44)	$	(54)	$	(67)
Natural Gas	(27)		(89)		(238)		(114)
Foreign currency exchange	1		—		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 June 30, 2022 and 2021, net losses of $15 million and net gains of $112 million, respectively, have been offset. Net gains of $183 million and $151 million have been offset for the six-month periods ended June 30, 2022 and 2021, respectively.

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 June 30, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2022		2023		2024		2025		2026		Thereafter		Total
Commodity contracts:
Electricity	$	9	$	6	$	9	$	11	$	2	$	27	$	64
Natural gas	(117)		(107)		(23)		(7)		1		—		(253)
Net unrealized loss/(gain)	$	(108)	$	(101)	$	(14)	$	4	$	3	$	27	$	(189)

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 June 30, 2022 was $110 million, for which PGE has posted $54 million in collateral, consisting of $21 million of letters of credit and $33 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2022, the cash requirement to either post as collateral or settle the instruments immediately would have been $60 million. As of June 30, 2022, PGE had no 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 sheets.

As of June 30, 2022, PGE received from counterparties $228 million in collateral, consisting of $20 million of letters of credit and $208 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.

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

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)

6 Months Ended

Jun. 30, 2022

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 and six months ended June 30, 2022, unvested performance-based restricted stock units and related dividend equivalent rights of 337 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 367 thousand shares excluded for the three and six months ended June 30, 2021.

Net income 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 June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
Weighted-average common shares outstanding—basic	89,225	89,554	89,310	89,555
Dilutive effect of potential common shares	146	118	139	132
Weighted-average common shares outstanding—diluted	89,371	89,672	89,449	89,687

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Equity (Notes)

6 Months Ended

Jun. 30, 2022

Equity [Abstract]

Equity

SHAREHOLDERS’ EQUITY

The activity in equity during the three- and six-month periods ended June 30, 2022 and 2021 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, 2021	89,410,612	$	1,241	$	(10)	$	1,476	$	2,707
Issuances of shares pursuant to equity-based plans	163,291	—		—		—		—
Stock-based compensation	—	—		—		—		—
Repurchase of common stock	(350,000)	(5)		—		(13)		(18)
Dividends declared ($0.4300 per share)	—	—		—		(40)		(40)
Net income	—	—		—		60		60
Balances as of March 31, 2022	89,223,903	$	1,236	$	(10)	$	1,483	$	2,709
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738
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
Issuances of shares pursuant to equity-based plans	74,974	1		—		—		1
Stock-based compensation	—	4		—		—		4
Repurchase of common stock	(250,000)	(3)		—		(9)		(12)
Dividends declared ($0.4300 per share)	—	—		—		(39)		(39)
Net income	—	—		—		32		32
Balances as of June 30, 2021	89,401,722	$	1,235	$	(11)	$	1,437	$	2,661

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Contingencies (Notes)

6 Months Ended

Jun. 30, 2022

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. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then 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 a feasibility study, along with a 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 had 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, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. 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 had improved substantially with the passage of time. 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 Company anticipates that remedial design 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 announced on February 12, 2021 that the entirety 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 conclusion of 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. Based on the above facts and remaining uncertainties in the voluntary allocation process, 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. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor 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 (CTWS), 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 estimated liabilities and environmental expenditures related to Portland Harbor through a combination of third-party proceeds, including but not limited to 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 GRC. 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 collecting any Portland Harbor cost from the PHERA through customer prices.

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, (the “Shimberg Action”) against one current and one former PGE executive and certain members and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought 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. On June 1, 2021, the plaintiff filed an unopposed motion to consolidate this lawsuit with the Ashabraner Action (described below), which the Court granted in an order dated July 27, 2021.

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, (the “JS Halberstam Action”) against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs.

On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope, 21-cv-13698 (the “Ashabraner Action”), against one current and one former PGE executive and certain and former members of the Company's Board of Directors. The plaintiff asserted 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 alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought damages to be awarded to the Company, equitable relief, and an award of

plaintiff’s attorneys’ fees and costs. On July 27, 2021, the Court issued an order consolidating the Ashabraner Action with the Shimberg Action.

On May 21, 2021, a putative shareholder derivative lawsuit was filed in the U.S. District Court for the District of Oregon, Portland Division captioned Berning v. Pope, No. 3:21-cv-00783-SI, (the “Berning Action”; collectively with the Shimberg, JS Halberstam, and Ashabraner Actions, the “Derivative Actions”), against one current and one former PGE executive and certain current and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted claims 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 also asserted a claim against the two executives for contribution and indemnity based on alleged violations of Sections 10(b) and 21D of the Exchange Act. The complaint demanded a jury trial and sought multiple forms of relief, including, among other things: a declaration that defendants breached and/or aided and abetted the breach of their fiduciary duties to PGE; an order directing PGE to reform and improve its corporate governance and internal procedures; restitution; and an award of attorneys’ fees, expenses, and costs.

On December 17, 2021, the parties to the Derivative Actions entered into a Memorandum of Understanding to settle the Derivative Actions subject to court approval and other terms (the "MOU"). After the parties entered into the MOU, the Court in the Shimberg and Ashabraner Actions granted an order to abate the proceedings until June 21, 2022. On December 17, 2021, the parties in the JS Halberstam Action filed a motion to stay the proceedings pending submission and court review of the settlement contemplated in the MOU.

On February 11, 2022, the parties to the Derivative Actions entered into a Stipulation of Settlement memorializing the terms of the non-monetary settlement, subject to Court approval, as set forth in the MOU. Under the Stipulation of Settlement, the parties to the JS Halberstam Action agreed to stay the proceedings in the Derivative Actions pending Court approval of the settlement. In addition, the Stipulation of Settlement provided that defendants would not oppose or object to a request by plaintiffs’ counsel for fees and expenses up to $750,000, which was subject to Court approval. Upon final approval of the Court, such fees and expenses were paid by the Company’s insurance provider under its insurance policy. On February 15, 2022, the plaintiff in the JS Halberstam Action filed a motion for preliminary approval of the settlement.

On March 28, 2022, the United States District Court for the District of Oregon entered an order preliminarily approving the settlement and the form and content of the notice to shareholders and set a final hearing for May 9, 2022, in the JS Halberstam Action. On April 18, 2022, the plaintiff in the JS Halberstam Action filed a motion for final approval of the settlement and fee and expense award. On May 9, 2022 the Court issued orders that granted final judgment approval of the settlement.

Governmental Investigations

In March, April and May 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC"), the Division of Enforcement of the SEC, and the Division of Enforcement of the FERC, 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, the SEC, and the FERC. Management cannot at this time predict the eventual scope or outcome of these matters.

Colstrip Litigation

The Company has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is located in the state of Montana and operated by one of the co-owners, Talen Montana, LLC (Talen). Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and

Operation (O&O) Agreement and other matters. In addition, other parties have brought claims against the co-owners, which, along with the co-owner disagreements, are described below. On May 10, 2022, Talen’s parent company, Talen Energy Supply, LLC filed for chapter 11 bankruptcy protection, although Colstrip continues to operate and generate electricity for PGE customers and others.

Petition to compel arbitration—On April 12, 2021, co-owners Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and Portland General Electric Company (the Petitioners) petitioned in Spokane County Superior Court, Washington, Case No. 21201000-32, against another co-owner, NorthWestern Corporation (Northwestern), and Talen to compel the arbitration initiated by NorthWestern to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or whether unanimous consent is required. The O&O Agreement among the parties states that any dispute shall be submitted for resolution to a single arbitrator with appropriate expertise. On April 14, 2021, the Petitioners filed a petition to compel arbitration. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Petitioners filed a motion to remand in June 2021 that was denied. Talen filed a motion, which, following a hearing in July 2021, was granted, to transfer the case to the U.S. District Court for the District of Montana. This matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

Challenge to constitutionality of Montana Senate Bills 265 and 266 (SB 265 and SB 266)—On May 4, 2021, the Petitioners filed a claim against NorthWestern and Talen in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of SB 265, which attempts to void contractual provisions within the co-owner agreement for Colstrip if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. The passage of SB 265 was supported by Defendants and purports to void the O&O Agreement between all parties, which provides for one arbitrator and venue in Spokane, Washington. The petitioners allege that SB 265 violates the contracts clause of the U.S. Constitution and the Montana Constitution, and is preempted by the Federal Arbitration Act (FAA). The Petitioners seek declaratory relief that SB 265 is unconstitutional as applied to the O&O Agreement and the FAA preempts the enforcement of SB 265.

Petitioners filed a First Amended Complaint on May 19, 2021, adding the Attorney General of Montana (Montana AG) as defendant and challenging the constitutionality of SB 266, which purportedly gives the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, or otherwise fails to pay the costs to maintain the plant. Defendant Northwestern filed an answer on June 2, 2021 and asked that the case Talen filed, as described in the “Complaint to implement SB 265 and SB 266” below, and this case be consolidated. On May 27, 2021, Petitioners filed a Motion for Preliminary Injunction, to enjoin the Montana AG from enforcing SB 266 against them. On June 17, 2021, defendants NorthWestern and Talen filed their Oppositions to Motion for Preliminary Injunction (PI) and the Montana AG filed a response taking no position on the PI, stating the State of Montana does not envision enforcing SB 266 any time soon. The Court held a hearing on the Petitioners’ Motion for PI August 6, 2021. On October 13, 2021, the Court issued an order that granted the Petitioners’ Motion for PI, enjoining the Montana AG from enforcing SB 266 against them and on December 17. 2021, the Court further clarified its PI order.

On August 17, 2021, the Petitioners filed for partial summary judgment on their claim to declare unconstitutional or unenforceable SB 265, which purports to invalidate the arbitration provision of the parties’ contract. Talen opposes the motion and Northwestern does not oppose the motion, but requests the Court compel arbitration. On October 29, 2021, the Petitioners filed a motion for summary judgment on their claim to declare unconstitutional and unenforceable SB 266. In November 2021, parties filed responses, opposition, and a motion to stay action on the summary judgment. On December 3, 2021, NorthWestern moved to compel arbitration and to appoint a magistrate to oversee the arbitrator selection process. On December 23, 2021, Petitioners and Talen filed their responses. The Court conducted a hearing on April 26, 2022. A decision on this matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

Complaint to implement Montana SB 265 and SB 266—On May 4, 2021, Talen filed a complaint against the Petitioners and NorthWestern, in the Thirteenth Judicial District Court in the State of Montana, as an attempt to implement Montana laws when determining the language of the O&O agreement based on the recent enactment of SB 265, which purports to invalidate provisions of the co-owner operating agreement regarding arbitration, and SB 266, which purports to give the Montana AG authority to prosecute and levy a $100,000 a day fine against any co-owner who takes steps to close Colstrip without unanimous consent of all co-owners. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. Talen filed a motion to remand the case to the State of Montana District Court. Petitioners and NorthWestern have filed a motion to consolidate this case with the Challenge to constitutionality of Montana Senate Bills 265 and 266, described above. On October 21, 2021, the Court stayed the motion to consolidate pending the outcome of Talen’s petition to remand. On December 1, 2021, the U.S. Magistrate Judge issued Findings and Recommendations to remand the case back to state Court. On December 15, 2021, the Petitioners filed Objections to the Findings and Recommendation. This matter is stayed, as a result of the bankruptcy filing of Talen’s parent company.

Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. On December 14, 2020, the original claim was filed in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from the defendants’ coal dust. On August 26, 2021, the claim was amended to add PGE as a defendant. On November 1, 2021, the defendants filed an answer to the complaint. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court. The Court set a trial to begin September 26, 2023.

Since these lawsuits are in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible losses.

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 known 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)	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022, 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)

6 Months Ended

Jun. 30, 2022

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 Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(9.5)		(11.7)		(10.0)		(9.6)
State and local taxes, net of federal tax benefit	9.0		8.3		9.0		8.7
Flow-through depreciation and cost basis differences	0.6		(3.0)		0.6		(0.5)
Amortization of excess deferred income tax	(4.1)		(3.4)		(4.3)		(3.3)
Local tax flow-through adjustment	—		—		—		(6.1)
Other	(0.1)		(0.1)		(0.1)		(1.0)
Effective tax rate	16.9	%	11.1	%	16.2	%	9.2	%

* 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. In the first quarter of 2021, 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 reflected in the condensed consolidated statements of income for the three months ended March 31, 2021. The adjustment has no impact to the three or six months ended June 30, 2022.

Carryforwards

Federal tax credit carryforwards as of June 30, 2022 and December 31, 2021 were $102 million and $98 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2042. PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2022 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2022, and December 31, 2021, PGE had no material unrecognized tax benefits.

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2022

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, PGE 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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds 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 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 longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument.

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 in order 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, future, swap, 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. PGE also enters into non-exchange-traded weather contract options, which are accounted for using the intrinsic value method. In accordance with ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not intend to engage in trading activities for non-retail purposes.

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. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then 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)

6 Months Ended

Jun. 30, 2022

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Retail:
Residential	$	250	$	249	$	558	$	559
Commercial	168		170		346		332
Industrial	73		62		142		122
Direct access customers	9		13		17		24
Subtotal	500		494		1,063		1,037
Alternative revenue programs, net of amortization	3		(8)		4		(11)
Other accrued revenues, net	—		(2)		—		11
Total retail revenues	503		484		1,067		1,037
Wholesale revenues*	65		41		121		74
Other operating revenues	23		12		29		35
Total revenues	$	591	$	537	$	1,217	$	1,146

* Wholesale revenues include $14 million and $4 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2022 and 2021, respectively, and $33 million and $9 million for the six months ended June 30, 2022 and 2021, 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)

6 Months Ended

Jun. 30, 2022

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 June 30,		Six Months Ended June 30,
	2022		2022
Balance as of beginning of period	$	28	$	26
(Decrease)/increase in provision	(2)		4
Amounts written off	(4)		(10)
Recoveries	1		3
Balance as of end of period	$	23	$	23

Schedule of Other Current Assets [Table Text Block]

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

	June 30, 2022		December 31, 2021
Prepaid expenses	$	55	$	66
Assets from price risk management activities	221		102
Margin deposits	34		37
Other current assets	$	310	$	205

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

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

	June 30, 2022		December 31, 2021
Electric utility plant	$	12,062	$	11,838
Construction work-in-progress	383		313
Total cost	12,445		12,151
Less: accumulated depreciation and amortization	(4,281)		(4,146)
Electric utility plant, net	$	8,164	$	8,005

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	June 30, 2022					December 31, 2021
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	—	$	—		$	55
Pension and other postretirement plans	—			125		—			131
Debt issuance costs	—			22		—			23
Trojan decommissioning activities	—			99		—			90
February 2021 ice storm and damage	—			72		—			67
Power cost adjustment mechanism	—			30		—			29
2020 Labor Day wildfire	—			30		—			45
COVID-19	—			34		—			36
Wildfire mitigation	—			20		—			—
Other	16			66		24			57
Total regulatory assets	$	16		$	498	$	24		$	533
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,121	$	—		$	1,047
Deferred income taxes	—			201		—			208
Asset retirement obligations	—			4		—			43
Price risk management	165			23		55			—
Other	38			69		51			62
Total regulatory liabilities	$	203	*	$	1,418	$	106	*	$	1,360

* 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):

	June 30, 2022		December 31, 2021
Accrued employee compensation and benefits	$	51	$	67
Accrued taxes payable	30		46
Accrued interest payable	30		29
Accrued dividends payable	42		40
Regulatory liabilities—current	203		106
Margin deposits from wholesale counterparties	208		58
Other	89		111
Total accrued expenses and other current liabilities	$	653	$	457

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Service cost	$	4	$	5	$	8	$	10
Interest cost*	7		7		14		14
Expected return on plan assets*	(12)		(11)		(24)		(22)
Amortization of net actuarial loss*	4		5		8		10
Net periodic benefit cost	$	3	$	6	$	6	$	12

* The net expense portion of non-service cost components are included in Miscellaneous income (expense), 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)

6 Months Ended

Jun. 30, 2022

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 June 30, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	63	$	—	$	—	$	—	$	63
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		8		—		—		17
Corporate credit	—		12		—		—		12
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	1		—		—		—		1
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		11		—		50
Natural gas	—		235		26		—		261
	$	79	$	294	$	37	$	14	$	424
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	43	$	71	$	—	$	114
Natural gas	—		7		1		—		8
	$	—	$	50	$	72	$	—	$	122

(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 $31 million, which are recorded at cash surrender value.

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

	As of December 31, 2021
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	44	$	—	$	—	$	—	$	44
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		14		—		—		14
Money market funds	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	4		—		—		—		4
Money market funds	1		—		—		—		1
Equity securities	4		—		—		—		4
Price risk management activities: (1) (4)
Electricity	—		16		1		—		17
Natural gas	—		115		5		—		120
	$	62	$	155	$	6	$	14	$	237
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	33	$	90	$	—	$	123
Natural gas	—		13		1		—		14
	$	—	$	46	$	91	$	—	$	137

(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 $36 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 June 30, 2022
Electricity physical forwards	$	5	$	68	Discounted cash flow	Electricity forward price (per MWh)	$	24.00	$	161.94	$	67.03
Natural gas financial swaps	26		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.98		6.34		3.45
Electricity financial futures	6		3		Discounted cash flow	Electricity forward price (per MWh)	31.42		161.94		80.47
	$	37	$	72
As of December 31, 2021
Electricity physical forwards	$	—	$	90	Discounted cash flow	Electricity forward price (per MWh)	$	16.66	$	129.75	$	43.73
Natural gas financial swaps	5		1		Discounted cash flow	Natural gas forward price (per Decatherm)	2.02		8.02		2.81
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	26.76		68.43		52.46
	$	6	$	91

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Balance as of the beginning of the period	$	52	$	117	$	85	$	137
Net realized and unrealized gains*	(19)		(62)		(56)		(83)
Transfers from Level 3 to Level 2	2		3		6		4
Balance as of the end of the period	$	35	$	58	$	35	$	58

* Both realized and unrealized losses/(gains), of which the unrealized portions 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. Includes $2 million in net realized gains and $1 million in net realized losses for the three-month periods ended June 30, 2022 and June 30, 2021. respectively. For the six-month periods ended June 30, 2022 and June 30, 2021, includes $3 million in net realized gains and $2 million in net realized losses, respectively.

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Price Risk Management (Tables)

6 Months Ended

Jun. 30, 2022

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):

	June 30, 2022		December 31, 2021
Current assets:
Commodity contracts:
Electricity	$	40	$	16
Natural gas	181		86
Total current derivative assets (1)	221		102
Noncurrent assets:
Commodity contracts:
Electricity	10		1
Natural gas	80		34
Total noncurrent derivative assets (1)	90		35
Total derivative assets (2)	$	311	$	137
Current liabilities:
Commodity contracts:
Electricity	$	51	$	36
Natural gas	4		11
Total current derivative liabilities	55		47
Noncurrent liabilities:
Commodity contracts:
Electricity	63		87
Natural gas	4		3
Total noncurrent derivative liabilities	67		90
Total derivative liabilities (2)	$	122	$	137

(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 June 30, 2022 and December 31, 2021, 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):

	June 30, 2022			December 31, 2021
Commodity contracts:
Electricity	5		MWhs	4		MWhs
Natural gas	173		Decatherms	181		Decatherms
Foreign currency	$	41	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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Commodity contracts:
Electricity	$	(14)	$	(44)	$	(54)	$	(67)
Natural Gas	(27)		(89)		(238)		(114)
Foreign currency exchange	1		—		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 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 June 30, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2022		2023		2024		2025		2026		Thereafter		Total
Commodity contracts:
Electricity	$	9	$	6	$	9	$	11	$	2	$	27	$	64
Natural gas	(117)		(107)		(23)		(7)		1		—		(253)
Net unrealized loss/(gain)	$	(108)	$	(101)	$	(14)	$	4	$	3	$	27	$	(189)

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2022

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 June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
Weighted-average common shares outstanding—basic	89,225	89,554	89,310	89,555
Dilutive effect of potential common shares	146	118	139	132
Weighted-average common shares outstanding—diluted	89,371	89,672	89,449	89,687

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Equity (Tables)

6 Months Ended

Jun. 30, 2022

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three- and six-month periods ended June 30, 2022 and 2021 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, 2021	89,410,612	$	1,241	$	(10)	$	1,476	$	2,707
Issuances of shares pursuant to equity-based plans	163,291	—		—		—		—
Stock-based compensation	—	—		—		—		—
Repurchase of common stock	(350,000)	(5)		—		(13)		(18)
Dividends declared ($0.4300 per share)	—	—		—		(40)		(40)
Net income	—	—		—		60		60
Balances as of March 31, 2022	89,223,903	$	1,236	$	(10)	$	1,483	$	2,709
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738
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
Issuances of shares pursuant to equity-based plans	74,974	1		—		—		1
Stock-based compensation	—	4		—		—		4
Repurchase of common stock	(250,000)	(3)		—		(9)		(12)
Dividends declared ($0.4300 per share)	—	—		—		(39)		(39)
Net income	—	—		—		32		32
Balances as of June 30, 2021	89,401,722	$	1,235	$	(11)	$	1,437	$	2,661

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Income tax Income tax (Tables)

6 Months Ended

Jun. 30, 2022

Income Tax Disclosure [Abstract]

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(9.5)		(11.7)		(10.0)		(9.6)
State and local taxes, net of federal tax benefit	9.0		8.3		9.0		8.7
Flow-through depreciation and cost basis differences	0.6		(3.0)		0.6		(0.5)
Amortization of excess deferred income tax	(4.1)		(3.4)		(4.3)		(3.3)
Local tax flow-through adjustment	—		—		—		(6.1)
Other	(0.1)		(0.1)		(0.1)		(1.0)
Effective tax rate	16.9	%	11.1	%	16.2	%	9.2	%

* 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, $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) mi² retail_customers	Jun. 30, 2021 USD ($)
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	922
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities | $	$ 149	$ 17

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Subtotal	$ 500	$ 494	$ 1,063	$ 1,037
Alternative revenue programs, net of amortization	3	(8)	4	(11)
Other Cost of Operating Revenue	0
Other accrued (deferred) revenues, net		(2)	0	(11)
Total retail revenues	503	484	1,067	1,037
Wholesale revenues	65	41	121	74
Other operating revenue	23	12	29	35
Total revenues	591	537	1,217	1,146
Gain on Derivative Instruments, Pretax	14	4	33	9
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	250	249	558	559
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	168	170	346	332
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	73	62	142	122
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 9	$ 13	$ 17	$ 24

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Balance Sheet Components Allowance for Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 28	$ 26
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	(2)	4
Accounts Receivable, Allowance for Credit Loss, Writeoff	(4)	(10)
Accounts Receivable, Allowance for Credit Loss, Recovery	1	3
Accounts Receivable, Allowance for Credit Loss	$ 23	$ 23

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Other Current Assets [Line Items]
Prepaid expenses	$ 55	$ 66
Assets from price risk management activities	221	102
Margin deposits	34	37
Other current assets	$ 310	$ 205

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 12,062	$ 11,838
Construction work-in-progress	383	313
Total cost	12,445	12,151
Less: accumulated depreciation and amortization	(4,281)	(4,146)
Electric utility plant, net	$ 8,164	$ 8,005

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 16		$ 16		$ 24
Regulatory assets - noncurrent	498		498		533
Regulatory Liability, Current	203		203		106
Regulatory liabilities-noncurrent	1,418		1,418		1,360
Purchased power and fuel	168	$ 185	370	$ 354
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	1,121		1,121		1,047
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	201		201		208
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	4		4		43
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	23		23		0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	38		38		51
Regulatory liabilities-noncurrent	69		69		62
Regulatory Clause Revenues, under-recovered
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	165		165		55
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	0		0		55
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	125		125		131
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	22		22		23
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	99		99		90
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	16		16		24
Regulatory assets - noncurrent	66		66		57
Storm Costs
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	72		72		67
221119 Other Electric Power Generation
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30		29
Fire
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30		45
pandemic
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	34		34		$ 36
wildfire
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	$ 20		$ 20

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Accrued employee compensation and benefits	$ 51	$ 67
Accrued taxes payable	30	46
Accrued interest payable	30	29
Accrued dividends payable	42	40
Regulatory liabilities—current	203	106
Deposits, Wholesale	208	58
Other	89	111
Total accrued expenses and other current liabilities	$ 653	$ 457

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4	$ 5	$ 8	$ 10
Interest cost	7	7	14	14
Expected return on plan assets	(12)	(11)	(24)	(22)
Amortization of net actuarial loss	4	5	8	10
Net periodic benefit cost	$ 3	$ 6	$ 6	$ 12

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Balance Sheet Components (Details) $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 23	$ 28		$ 23		$ 26
Unbilled Receivables, Current	94			94		117
Finite-Lived Intangible Assets, Accumulated Amortization	470			470		446
Amortization of Intangible Assets	14		$ 15	29	$ 30
Line of Credit Facility, Maximum Borrowing Capacity	$ 750			$ 750
Debt Instrument, Covenant Description				65.00%
Ratio of Indebtedness to Net Capital	0.556			0.556
Line of Credit Facility, Remaining Borrowing Capacity	$ 650			$ 650
Line of Credit Facility, Current Borrowing Capacity	220		650	220	650
Authorized Short-Term Debt	900			900
Purchased power and fuel	168		$ 185	370	354
Repayments of Long-term Debt				0	140
Operating Lease, Right-of-Use Asset	29			29
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30
Amount above baseline net variable power costs				(32)		62
Lower deadband limit below baseline net variable power costs				15
Upper deadband limit above baseline net variable power costs				30
Proceeds from failed sale-leaseback transactions				25	$ 0
Letters of Credit Outstanding, Amount	91			91
Sale Leaseback Transaction, Net Book Value						37
Gain (Loss) on Disposition of Intangible Assets				11
Gain (Loss) on Disposition of Property Plant Equipment				1
Asset Impairment Charges				17
Increase (Decrease) in Deferred Charges		$ 15
Tangible Asset Impairment Charges				2
Finance Lease, Liability	25			25
221119 Other Electric Power Generation
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30		29
Fire
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30		45
pandemic
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	34			34		$ 36
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Commercial paper	$ 0			$ 0

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Assets:
Cash equivalents	$ 63	$ 44
Debt securities:
Domestic government	17	19
Corporate credit	12	14
Money market funds measured at NAV (2)	14	14
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	3	4
Debt securities—domestic government	3	4
Assets from price risk management activities: (1) (3)
Electricity	50	17
Natural gas	261	120
Total	14	14
Assets, Fair Value Disclosure	424	237
Liabilities from price risk management activities: (1) (3)
Electricity	114	123
Natural gas	8	14
Total	122	137
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	63	44
Debt securities:
Domestic government	9	9
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	3	4
Debt securities—domestic government	3	4
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	79	62
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	8	10
Corporate credit	12	14
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	39	16
Natural gas	235	115
Total	294	155
Liabilities from price risk management activities: (1) (3)
Electricity	43	33
Natural gas	7	13
Total	50	46
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	11	1
Natural gas	26	5
Total	37	6
Liabilities from price risk management activities: (1) (3)
Electricity	71	90
Natural gas	1	1
Total	$ 72	$ 91

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 24.00	$ 16.66
Natural gas financial swaps	2.98	2.02
Financial swaps - electricity	31.42	26.76
High [Member]
Commodity Contracts
Electricity physical forwards	161.94	129.75
Natural gas financial swaps	6.34	8.02
Financial swaps - electricity	161.94	68.43
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	67.03	43.73
Natural gas financial swaps	3.45	2.81
Financial swaps - electricity	80.47	52.46
Assets [Member]
Commodity Contracts
Electricity physical forwards	5,000,000	0
Natural gas financial swaps	26,000,000	5,000,000
Financial swaps - electricity	6,000,000	1,000,000
Total commodity contracts	37,000,000	6,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	68,000,000	90,000,000
Natural gas financial swaps	1,000,000	1,000,000
Financial swaps - electricity	3,000,000	0
Total commodity contracts	$ 72,000,000	$ 91,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 52	$ 117	$ 85	$ 137
Net realized and unrealized (gains)/losses	(19)	(62)	(56)	(83)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	2
Transfers out of Level 3 to Level 2		3	6	4
Balance as of the end of the period	$ 35	$ 58	$ 35	$ 58

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 31		$ 31		$ 36
net realized loss	1			$ 2
Long-term Debt	3,286		3,286		3,285
Unamortized Debt Issuance Expense	13		13		14
Long-term Debt, Fair Value	3,092		3,092		$ 3,831
Net gain or loss recognized in the statement of income offset by regulatory accounting	15	$ (112)	(183)	$ (151)
net realized gains	$ 2		$ 3

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current Assets, Commodity Contracts:
Electricity	$ 40	$ 16
Natural gas	181	86
Total current derivative assets	221	102
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	10	1
Commodity Contract Asset, Noncurrent, Natural Gas	80	34
Derivative Asset, Noncurrent	90	35
Total derivative assets	311	137
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	51	36
Natural gas	4	11
Total current derivative liabilities	55	47
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	63	87
Natural gas	4	3
Total noncurrent derivative liabilities	67	90
Total derivative liabilities	$ 122	$ 137

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2022 CAD ($) MWh MMBTU	Dec. 31, 2021 CAD ($) MWh MMBTU
Commodity contracts:
Electricity | MWh	5	4
Natural gas | MMBTU	173	181
Foreign currency | $	$ 41	$ 19

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Commodity contracts:
Electricity	$ (14)	$ (44)	$ (54)	$ (67)
Natural Gas	(27)	(89)	(238)	(114)
Foreign currency exchange	$ 1	$ 0	$ 1	$ 0

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Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Jun. 30, 2022 USD ($)
Electricity [Member]
Commodity contracts:
2022	$ 9
2023	6
2024	(9)
2025	11
2026	2
Thereafter	27
Total	(64)
Natural Gas [Member]
Commodity contracts:
2022	117
2023	107
2024	(23)
2025	7
2026	1
Thereafter	0
Total	(253)
Net Unrealized Loss/(gain)[Member]
Commodity contracts:
2022	108
2023	101
2024	(14)
2025	4
2026	3
Thereafter	27
Total	$ (189)

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ (15)	$ 112	$ 183	$ 151
Derivative, Net Liability Position, Aggregate Fair Value	110		110
Collateral Already Posted, Aggregate Fair Value	54		54
Collateral cash requirement	60		60
Purchased power and fuel	168	$ 185	370	$ 354
Deposits, Wholesale	208		208		$ 58
Deposits	20		20
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	3		3
Letters of Credit Outstanding, Amount	91		91
Derivative, Collateral, Right to Reclaim Cash	33		33
Pledged Assets Separately Reported, Securities Pledged under Letter of Credit Facilities, at Fair Value	21		21
Derivative Asset, Fair Value, Amount Offset Against Collateral	228		228
Electricity [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1		1
Natural Gas [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 2		$ 2

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	89,225	89,554	89,310	89,555
Dilutive effect of potential common shares	146	118	139	132
Weighted Average Number of Shares Outstanding, Diluted	89,371	89,672	89,449	89,687

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	337	367	337	367

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Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2022	Jun. 30, 2021
Common Stock, Shares, Outstanding beginning of period		89,410,612			89,410,612
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	2,709	2,707	2,675	2,613	$ 2,707	$ 2,613
Dividends declared	(41)	(40)	(39)	(36)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 64	60	32	96	$ 124	128
Common Stock, Shares, Outstanding end of period	89,242,672				89,242,672
Stockholders' Equity	$ 2,738	$ 2,709	$ 2,661	$ 2,675	$ 2,738	2,661
Common Stock, Dividends, Per Share, Declared	$ 0.4525	$ 0.4300	$ 0.4300	$ 0.4075
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	$ 4	$ 0	$ 4	$ 2
Repurchase of common stock		$ (18)	$ (12)		$ (18)	$ (12)
Stock Repurchased During Period, Shares		(350,000)	(250,000)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	$ 1
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,223,903	89,410,612	89,576,748	89,537,331	89,410,612	89,537,331
Issuances of shares pursuant to equity-based plans	18,769	163,291	74,974	39,417
Common Stock, Shares, Outstanding end of period	89,242,672	89,223,903	89,401,722	89,576,748	89,242,672	89,401,722
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	1,236	1,241	1,233	1,231	$ 1,241	$ 1,231
Dividends declared	0	0	0	0
Stockholders' Equity	1,241	1,236	1,235	1,233	1,241	1,235
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	4	0	4	2
Repurchase of common stock		(5)	(3)
AOCI Attributable to Parent [Member]
Stockholders' Equity	(10)	(10)	(11)	(11)	(10)	(11)
Dividends declared	0	0	0	0
Stockholders' Equity	(9)	(10)	(11)	(11)	(9)	(11)
Repurchase of common stock		0	0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	1
Retained Earnings [Member]
Stockholders' Equity	1,483	1,476	1,453	1,393	1,476	1,393
Dividends declared	41	40	39	36
Stockholders' Equity	$ 1,506	1,483	1,437	$ 1,453	$ 1,506	$ 1,437
Repurchase of common stock		$ (13)	$ (9)

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Contingencies (Details)	6 Months Ended
	Jun. 30, 2022 USD ($) party
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties | party	100
Litigation Settlement, Expense	$ 115,000,000
Loss Contingency, Estimate of Possible Loss	1,700,000,000
Loss Contingency, Damages Sought, Value	1,200,000,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500,000,000
Environmental Remediation Expense	6,000,000
amount authorized to levy	100,000
lower range of costs	1,900,000,000
upper range of costs	3,500,000,000
Class action damages sought	10,000,000
Estimated Litigation Liability	$ 750,000

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%	21.00%
Federal tax credits	(9.50%)	(11.70%)	(10.00%)	(9.60%)
State and local taxes, net of federal tax benefit	9.00%	8.30%	9.00%	8.70%
Flow through depreciation and cost basis differences	0.60%	(3.00%)	0.60%	(0.50%)
Excess deferred tax amortization	(4.10%)	(3.40%)	(4.30%)	(3.30%)
Other	0.00%	0.00%	0.00%	(6.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(0.10%)	(0.10%)	(0.10%)	(1.00%)
Effective tax rate	16.90%	11.10%	16.20%	9.20%

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Income tax Income tax (Details) - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Other Tax Carryforwards	$ 9,000,000
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	102,000,000	$ 98,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0