10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2023

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 April 20, 2023 is 96,621,298 shares.

1

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2023

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	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	59
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	60
Item 6.	Exhibits	60
SIGNATURE		61

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 March 31,
	2023		2022
Revenues:
Revenues, net	$	745	$	625
Alternative revenue programs, net of amortization	3		1
Total revenues	748		626
Operating expenses:
Purchased power and fuel	304		202
Generation, transmission and distribution	93		90
Administrative and other	80		89
Depreciation and amortization	111		99
Taxes other than income taxes	43		40
Total operating expenses	631		520
Income from operations	117		106
Interest expense, net	44		38
Other income:
Allowance for equity funds used during construction	3		3
Miscellaneous income, net	12		—
Other income, net	15		3
Income before income tax expense	88		71
Income tax expense	14		11
Net income and Comprehensive income	$	74	$	60
Weighted-average common shares outstanding (in thousands):
Basic	91,840		89,396
Diluted	92,571		89,527
Earnings per share:
Basic	$	0.81	$	0.67
Diluted	$	0.80	$	0.67
See accompanying notes to condensed consolidated financial statements.

    

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)                            

	March 31, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	12	$	165
Accounts receivable, net	362		398
Inventories	95		95
Regulatory assets—current	65		54
Other current assets	232		498
Total current assets	766		1,210
Electric utility plant, net	8,611		8,465
Regulatory assets—noncurrent	481		473
Nuclear decommissioning trust	38		39
Non-qualified benefit plan trust	38		38
Other noncurrent assets	217		234
Total assets	$	10,151	$	10,459
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)                        

	March 31, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	242	$	457
Liabilities from price risk management activities—current	100		118
Short-term debt	68		—
Current portion of long-term debt	—		260
Current portion of finance lease obligation	20		20
Accrued expenses and other current liabilities	321		641
Total current liabilities	751		1,496
Long-term debt, net of current portion	3,485		3,386
Regulatory liabilities—noncurrent	1,398		1,389
Deferred income taxes	447		439
Unfunded status of pension and postretirement plans	170		170
Liabilities from price risk management activities—noncurrent	70		75
Asset retirement obligations	250		257
Non-qualified benefit plan liabilities	81		83
Finance lease obligations, net of current portion	293		294
Other noncurrent liabilities	94		91
Total liabilities	7,039		7,680
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2023 and December 31, 2022	—		—
Common stock, no par value, 160,000,000 shares authorized; 96,620,972 and 89,283,353 shares issued and outstanding as of March 31, 2023 and December 31, 2022, respectively	1,548		1,249
Accumulated other comprehensive loss	(4)		(4)
Retained earnings	1,568		1,534
Total shareholders’ equity	3,112		2,779
Total liabilities and shareholders’ equity	$	10,151	$	10,459
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)    

	Three Months Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	74	$	60
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	111		99
Deferred income taxes	4		4
Pension and other postretirement benefits	1		3
Allowance for equity funds used during construction	(3)		(3)
Decoupling mechanism deferrals, net of amortization	(3)		(1)
Regulatory assets	(6)		(15)
Regulatory liabilities	8		5
2020 Labor Day wildfire earnings test reserve	—		15
Other non-cash income and expenses, net	10		15
Changes in working capital:
Decrease in accounts receivable, net	34		21
Decrease in inventories	—		6
Decrease in margin deposits	86		23
(Decrease) in accounts payable and accrued liabilities	(174)		(44)
(Decrease)/increase in margin deposits from wholesale counterparties	(140)		99
Other working capital items, net	(27)		(27)
Other, net	(14)		(11)
Net cash (used in) provided by operating activities	(39)		249
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)        

	Three Months Ended March 31,
	2023		2022
Cash flows from investing activities:
Capital expenditures	(274)		(167)
Sales of Nuclear decommissioning trust securities	—		2
Purchases of Nuclear decommissioning trust securities	—		(2)
Proceeds from sale of properties	2		12
Other, net	(4)		1
Net cash used in investing activities	(276)		(154)
Cash flows from financing activities:
Proceeds from issuance of common stock	$	300	$	—
Proceeds from issuance of long-term debt	100		—
Payments on long-term debt	(260)		—
Issuance of commercial paper, net	68		—
Proceeds from Pelton/Round Butte financing arrangement	—		25
Dividends paid	(40)		(38)
Repurchase of common stock	—		(18)
Other	(6)		(6)
Net cash provided by (used in) financing activities	162		(37)
(Decrease) Increase in cash and cash equivalents	(153)		58
Cash and cash equivalents, beginning of period	165		52
Cash and cash equivalents, end of period	$	12	$	110
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	22	$	18
Cash paid for income taxes	2		2
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 (State). 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 , 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 approximately 4,000 square mile, State-approved service area, entirely within the State, encompasses 51 incorporated cities. As of March 31, 2023, PGE served 928,000 retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

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

The financial information included herein as of and for the three months ended March 31, 2023 and 2022 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, 2022 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2022, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 16, 2023, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three months ended March 31, 2023 and 2022.

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

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended March 31,
	2023		2022
Retail:
Residential	$	362	$	308
Commercial	197		178
Industrial	82		69
Direct access customers	6		8
Subtotal	647		563
Alternative revenue programs, net of amortization	3		1
Other accrued revenues, net	1		—
Total retail revenues	651		564
Wholesale revenues*	88		56
Other operating revenues	9		6
Total revenues	$	748	$	626

* Wholesale revenues include $34 million and $19 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2023 and 2022, 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.

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 Revenues, net on the condensed consolidated statements of income.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon, among other things, 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.

11

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 3: BALANCE SHEET COMPONENTS

Inventories

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

Accounts Receivable, Net

Accounts receivable, net includes $115 million and $131 million of unbilled revenues as of March 31, 2023 and December 31, 2022, respectively. Accounts receivable, net includes an allowance for credit losses of $13 million and $12 million as of March 31, 2023 and December 31, 2022, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended March 31,
	2023
Balance as of beginning of period	$	12
Increase in provision	3
Amounts written off	(3)
Recoveries	1
Balance as of end of period	$	13

Other Current Assets

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

	March 31, 2023		December 31, 2022
Prepaid expenses	$	89	$	69
Assets from price risk management activities	113		313
Margin deposits	30		116
Other current assets	$	232	$	498

Assets from price risk management activities and related unrealized gains as well as Margin deposits decreased during the three months ended March 31, 2023 due to decreases 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):             

	March 31, 2023		December 31, 2022
Electric utility plant in-service	$	12,704	$	12,421
Construction work-in-progress	411		467
Total cost	13,115		12,888
Less: accumulated depreciation and amortization	(4,504)		(4,423)
Electric utility plant, net	$	8,611	$	8,465

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $513 million and $499 million as of March 31, 2023 and December 31, 2022, respectively. Amortization expense related to intangible assets was $14 million and $15 million for the three months ended March 31, 2023 and 2022, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Battery storage agreement—On April 26, 2023, PGE entered into a battery storage purchased power agreement (PPA) that will be accounted for as a lease upon commencement. The lease is expected to commence in December 2024 and has a term of 20 years. The expected total fixed contract consideration will approximate $737 million over the lease term.

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):

	March 31, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	22	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			133		—			133
February 2021 ice storm and damage	12			61		10			64
Power cost adjustment mechanism	16			10		14			14
2020 Labor Day wildfire	5			26		4			27
COVID-19	12			10		—			22
Wildfire mitigation	—			31		—			28
Other	20			72		26			68
Total regulatory assets	$	65		$	481	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,145	$	—		$	1,136
Deferred income taxes	—			190		—			194
Asset retirement obligations	—			9		—			7
Price risk management	12			—		195			—
Other	34			54		39			52
Total regulatory liabilities	$	46	*	$	1,398	$	234	*	$	1,389

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

Wildfire Mitigation represents incremental costs and investments made by PGE under 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 execute a wildfire protection plan, in which reasonable costs can be recovered through the prices to 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 March 31, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $31 million and $28 million, respectively. 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, or application of a potential 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 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 which may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of those discussions was an Energy Term Sheet (Term Sheet), which

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of both March 31, 2023 and December 31, 2022, PGE’s deferred balance was $22 million, 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 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. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. During the March 14, 2023 public meeting, Staff recommended the Commission approve PGE's filing of Advice No. 22-45 associated with the recovery of the COVID-19 deferral. On March 21, 2023, Advice No. 22-45 was approved by the Commission, allowing for amortization of deferred amounts over a two-year period, which began April 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. PGE estimated the revenue requirement for Boardman to be $14 million for the year ended December 31, 2020, an additional $66 million for the year ended December 31, 2021, and $23 million for the year ended December 31, 2022. 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, showed 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. Although still subject to OPUC review, PGE does not believe it exceeded its regulated return on equity under the earnings test for 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and states that no refund remains necessary for that year. The stipulation remains subject to OPUC approval. Review and determination of potential refund for the periods related to 2020 and 2022 remain outstanding.

In November 2022, the OPUC granted a motion by PGE to suspend the procedural schedule and directed the Company to file a status update no later than February 16, 2023. In granting the ruling the OPUC noted that it expects to resolve this matter, addressing both the 2020 and 2022 deferrals, within the first half of 2023. The status update on February 16, 2023 stated that a settlement conference had been scheduled and parties anticipated filing with the OPUC another status update, settlement agreement, or proposed procedural schedule by March 14, 2023. On March 13, 2023, PGE notified the OPUC that settlement discussions had been productive and the parties are progressing toward resolution of the matter before the end of the first half of 2023. Based on the application of an earnings test, PGE has not recorded a refund related to Boardman for 2020, 2021, or 2022. PGE believes the range of reasonably possible refund is limited to the Boardman revenue requirement for the year 2020. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could require additional refunds that would be recognized as a charge to earnings, which could be material.

15

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accrued Expenses and Other Current Liabilities

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

	March 31, 2023		December 31, 2022
Accrued employee compensation and benefits	$	52	$	66
Accrued taxes payable	30		29
Accrued interest payable	46		31
Accrued dividends payable	42		42
Regulatory liabilities—current	46		234
Margin deposits from wholesale counterparties	—		140
Other	105		99
Total accrued expenses and other current liabilities	$	321	$	641

The current portion of Regulatory liabilities and Margin deposits from wholesale counterparties decreased during the three months ended March 31, 2023 due to decreases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

Credit Facilities

As of March 31, 2023, PGE had a $650 million revolving credit facility scheduled to expire in September 2027. 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 March 31, 2023, PGE was in compliance with this covenant with a 54.2% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $582 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 March 31, 2023, PGE had $68 million 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 $135 million were outstanding as of March 31, 2023. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

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(Unaudited)

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.

Long-term Debt

On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bore interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and applicable margin of 87.5 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 1, 2023, this term loan was repaid in full with proceeds from the Equity Forward Sale Agreement described in Note 7, Shareholders’ Equity.

On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in First Mortgage Bonds (FMBs), $100 million of which were funded in full on January 13, 2023.

Defined Benefit Retirement Plan Costs

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

	Three Months Ended March 31,
	2023		2022
Service cost	$	3	$	4
Interest cost*	9		7
Expected return on plan assets*	(11)		(12)
Amortization of net actuarial loss*	—		4
Net periodic benefit cost	$	1	$	3

* 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 March 31, 2023 and December 31, 2022, 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

17

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(Unaudited)

categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.

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

	As of March 31, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	10		10		—		—		20
Corporate credit	—		11		—		—		11
Money market funds	—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	3		—		—		—		3
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		45		—		84
Natural gas	—		71		6		—		77
	$	19	$	131	$	51	$	7	$	208
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	41	$	72	$	—	$	113
Natural gas	—		50		7		—		57
	$	—	$	91	$	79	$	—	$	170

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

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

(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.

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

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(Unaudited)

	As of December 31, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds	—		—		—		11		11
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	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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.

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 March 31, 2023
Electricity physical forwards	$	44	$	69	Discounted cash flow	Electricity forward price (per MWh)	$	39.21	$	245.00	$	96.46
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.81		9.36		4.02
Electricity financial futures	1		2		Discounted cash flow	Electricity forward price (per MWh)	40.00		209.00		108.12
	$	51	$	79
As of December 31, 2022
Electricity physical forwards	$	52	$	93	Discounted cash flow	Electricity forward price (per MWh)	$	35.00	$	270.00	$	101.27
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.71		24.71		4.42
Electricity financial futures	11		—		Discounted cash flow	Electricity forward price (per MWh)	54.17		143.70		104.21
	$	69	$	101

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 March 31,
	2023		2022
Balance as of the beginning of the period	$	32	$	85
Net realized and unrealized (gains)*	(11)		(37)
Transfers from Level 3 to Level 2	7		4
Balance as of the end of the period	$	28	$	52

* 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 $5 million in net realized losses for the three months ended March 31, 2023 and $1 million in net realized gains for the three months ended March 31, 2022.

Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter.

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

As of March 31, 2023, the carrying amount of PGE’s long-term debt was $3,485 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,110 million. As of December 31, 2022, the carrying amount of PGE’s long-term debt was $3,646 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $2,984 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 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.

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(Unaudited)

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

	March 31, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	52	$	112
Natural gas	61		201
Total current derivative assets (1)	113		313
Noncurrent assets:
Commodity contracts:
Electricity	32		44
Natural gas	16		30
Total noncurrent derivative assets (1)	48		74
Total derivative assets (2)	$	161	$	387
Current liabilities:
Commodity contracts:
Electricity	$	69	$	93
Natural gas	31		25
Total current derivative liabilities	100		118
Noncurrent liabilities:
Commodity contracts:
Electricity	44		53
Natural gas	26		22
Total noncurrent derivative liabilities	70		75
Total derivative liabilities (2)	$	170	$	193

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

(2) As of March 31, 2023 and December 31, 2022, no derivative assets or liabilities were designated as hedging instruments.

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

	March 31, 2023			December 31, 2022
Commodity contracts:
Electricity	4		MWhs	6		MWhs
Natural gas	208		Decatherms	211		Decatherms
Foreign currency	$	8	Canadian	$	10	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of March 31, 2023, gross amounts included as Price risk management liabilities subject to master netting agreements were $7 million, entirely for natural gas, for which PGE has posted no collateral. As of

23

PORTLAND GENERAL ELECTRIC COMPANY

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(Unaudited)

December 31, 2022, gross amounts included as Price risk management liabilities subject to master netting agreements were $5 million, entirely for natural gas, for which PGE posted no collateral.

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

	Three Months Ended March 31,
	2023		2022
Commodity contracts:
Electricity	$	(35)	$	(40)
Natural Gas	132		(211)
Foreign currency exchange	—		—

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended March 31, 2023 and 2022, net losses of $206 million and net gains of $198 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2023 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2023		2024		2025		2026		2027		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	12	$	19	$	(4)	$	(2)	$	(15)	$	29
Natural gas	(18)		(2)		(4)		4		—		—		(20)
Net unrealized loss/(gain)	$	1	$	10	$	15	$	—	$	(2)	$	(15)	$	9

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2023 was $153 million, for which PGE has posted $16 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2023, the cash requirement to either post as collateral or settle the instruments immediately would have been $106 million. As of March 31, 2023, PGE had $14 million cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheets.

As of March 31, 2023, PGE received from counterparties $8 million in collateral, consisting entirely of letters of credit. 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.

24

PORTLAND GENERAL ELECTRIC COMPANY

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(Unaudited)

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.

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; ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the Equity Forward Sale Agreement (EFSA). See Note 7, Shareholders’ Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three months ended March 31, 2023, unvested performance-based restricted stock units and related dividend equivalent rights of 413 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 385 thousand shares excluded for the three months ended March 31, 2022.

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 March 31,
	2023	2022
Weighted-average common shares outstanding—basic	91,840	89,396
Dilutive effect of potential common shares	731	131
Weighted-average common shares outstanding—diluted	92,571	89,527

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three-month periods ended March 31, 2023 and 2022 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, 2022	89,283,353	$	1,249	$	(4)	$	1,534	$	2,779
Issuances of shares pursuant to equity-based plans	159,603	—		—		—		—
Issuances of shares pursuant to equity forward sales agreement	7,178,016	300		—		—		300
Stock-based compensation		(1)		—		—		(1)
Dividends declared ($0.4525 per share)	—	—		—		(40)		(40)
Net income	—	—		—		74		74
Balances as of March 31, 2023	96,620,972	$	1,548	$	(4)	$	1,568	$	3,112
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	—		—		—		—
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

Equity Forward Sale Agreement—In 2022, PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 10,100,000 shares of its common stock. In March 2023, the Company issued 7,178,016 shares pursuant to the EFSA and received net proceeds of $300 million.

Pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters for $43.00 per share, less an underwriting discount equal to $1.23625 per share. PGE receives proceeds from the sale of common stock when the EFSA is settled (described above), and at that time PGE records the proceeds, if any, in equity.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to October 25, 2024, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $43.00 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

26

PORTLAND GENERAL ELECTRIC COMPANY

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(Unaudited)

PGE concluded that the EFSA was an equity instrument and that it qualified for an exception from derivative accounting because the EFSA was indexed to its own stock. PGE anticipates settling the EFSA through physical settlement on or before October 25, 2024.

At March 31, 2023, the Company could have physically settled the EFSA by delivering 4,436,984 shares to the forward counterparty in exchange for cash of $184 million.

Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of PGE’s stock during the reporting period is higher than the average forward sale price during the reporting period. As of March 31, 2023, 577,479 incremental shares were included in the calculation of diluted EPS related to the securities under the EFSA. For additional information concerning the Company’s diluted earnings per share, see Note 6, Earnings Per Share.

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,

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 that 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 was 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.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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, 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. 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 estimated liabilities and recover incurred 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.

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 predict the eventual scope or outcome of these matters.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Colstrip-Related 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). In May 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. Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. An arbitration process has been initiated to address such business disagreements and has resulted in several legal proceedings, which, along with other matters related to Colstrip, are summarized below.

Arbitration—In March 2021, co-owner NorthWestern Corporation (NorthWestern) initiated arbitration against all other co-owners of Colstrip to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or, alternatively, 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. This arbitration process was initially stayed as a result of the bankruptcy filing of Talen’s parent company, but that stay was lifted in August 2022, by a voluntary stipulation. The arbitration has been stayed through June 16, 2023, by agreement of the parties. PGE cannot predict the ultimate outcome of the arbitration process.

Petition to compel arbitration—In April 2021, co-owners Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and PGE (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 that is described above. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Following a hearing in July 2021, Talen’s motion to transfer the case to the U.S. District Court for the District of Montana was granted. This matter is stayed, because of the bankruptcy filing of Talen’s parent company.

Challenge to constitutionality of Montana Senate Bills 265 and 266 (MSB 265 and MSB 266)—On May 4, 2021, the Petitioners filed a claim against NorthWestern and Talen (the Defendants) in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of MSB 265, which attempted to void contractual arbitration provisions within the O&O Agreement if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. 

The 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 MSB 266, which purportedly gave the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, and authority to penalize any co-owner who fails or refuses to pay the costs to maintain the plant.

The Petitioners filed motions for summary judgment on their claims and on September 29, 2022, the Magistrate Judge issued Findings and Recommendations, which were adopted in full by the Court on October 19, 2022, granting the summary judgment motions by finding that MSB 266 was unconstitutional, and MSB 265 was unconstitutional and in the alternative preempted by the Federal Arbitration Act.

Complaint to implement Montana SB 265—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 MSB 265. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. This matter is stayed, because of the bankruptcy filing of Talen’s parent company.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. In December 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. In August 2021, the claim was amended to add PGE as a defendant. 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. This matter was stayed for a time as a result of the bankruptcy filing of Talen’s parent company, but litigation has resumed and the parties are working through discovery issues.

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 March 31, 2023, 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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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(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 March 31,
	2023		2022
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(9.3)		(10.5)
State and local taxes, net of federal tax benefit	9.0		8.9
Flow-through depreciation and cost basis differences	1.0		0.7
Amortization of excess deferred income tax	(3.7)		(4.5)
Other	(2.1)		(0.1)
Effective tax rate	15.9	%	15.5	%

* 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 PTC generation will end at various dates through 2033.

Carryforwards

Federal tax credit carryforwards as of both March 31, 2023 and December 31, 2022 were $102 million. These credits primarily consist of PTCs, which will expire at various dates through 2043. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2023 will be realized; accordingly, no valuation allowance has been recorded. As of March 31, 2023, and December 31, 2022, PGE had no material unrecognized tax benefits.

Inflation Reduction Act of 2022

The Inflation Reduction Act of 2022 (“IRA”) was signed into law by President Biden on August 16, 2022. There was no immediate impact of the IRA to PGE’s results of operations for the three months ended March 31, 2023. PGE will be closely monitoring guidance from the IRS regarding the enhanced energy credits available under the IRA. PGE expects to be able to generate and utilize increased energy credits in future periods, and continues to hold that it is more likely than not that the deferred income tax assets will be realized.

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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 the adoption of community choice aggregation;

•the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in 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 severe 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 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, inability to complete negotiations on contracts for capital projects, 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, including but not limited to volatility caused by macroeconomic and international issues, 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 growth, or demographic patterns, in PGE’s service territory;

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

•cybersecurity attacks, data security breaches, physical attacks and security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, information

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technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, vendor, employee, or Company information;

•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 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 respond 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;

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

•acts of war or terrorism.

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

OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s 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. The Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers.

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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 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 Power—Reduce greenhouse gas emissions associated with electricity served to retail customers by at least 80% by 2030 and 100% by 2040;

•Electrify the Economy—Increase beneficial electricity use to capture the benefits of new technologies while building an increasingly clean, flexible and reliable grid; and

•Advance our Performance—Improve safety, efficiency, and system and equipment reliability while maintaining affordable energy service and growing earnings per share 5% to 7% annually.

Climate Change

State-mandated Greenhouse gas (GHG) emissions reduction targets—In June 2021, the Oregon legislature passed House Bill (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 emissions 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 “HB 2021” in the “Laws and Regulations” section of this Overview.

Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 234 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 large business and municipality 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 March 31, 2023, 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.

The Climate Pledge—In 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report GHG emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency

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improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets.

Severe weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. 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

The Resource Planning Process— PGE’s resource planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. In 2020, the OPUC acknowledged, subject to conditions and directives, the Company’s 2019 Integrated Resource Plan (IRP) and associated Action Plan. With the passage of HB 2021, PGE prepared a Clean Energy Plan (CEP), which articulates the Company’s strategy to meet the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was filed in connection with, the Company’s 2023 IRP. PGE filed its first combined IRP and CEP with the OPUC on March 31, 2023. That filing projects PGE’s resource and capacity needs over the next 20 years and proposes an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements.

PGE may need to procure and integrate approximately 3,000 to 4,000 MW in order to meet the Company’s 2030 emissions reduction target. PGE estimates that this need will be met by targeted acquisition of approximately 2,000 to 3,000 MW of non-emitting resources and adding approximately 1,000 MW of non-emitting dispatchable capacity through new acquisition or extending existing capacity contracts.

2021 All-Source RFP

In 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, to fill the need identified in the 2019 IRP action plan and to meet a portion of the Company’s estimated 2030 need. PGE issued the final 2021 All-Source RFP in December 2021, and proposals were submitted in January 2022. PGE submitted a request for acknowledgement of the final shortlist to the OPUC on May 5, 2022 that included seven distinct projects submitted by five bidders for renewable resources and six distinct projects by four bidders for capacity resources.

On July 14, 2022, during a public meeting, the OPUC acknowledged, with conditions, PGE’s proposed final shortlist of renewable resources and non-emitting dispatchable capacity. Subsequently, on August 31, 2022, the OPUC issued its order, memorializing its July 14, 2022 acknowledgement, with conditions. Following the passage of the Inflation Reduction Act, PGE provided an opportunity for all bidders selected to the final shortlist to refresh their pricing. Updated pricing was received in August 2022 and PGE, in collaboration with an Independent Evaluator, updated scoring and ranking to reflect pricing changes from bidders. An updated Independent Evaluator's report was filed as an informational update to the OPUC on September 30, 2022.

Pursuant to the 2021 All-Source RFP process, PGE has entered into agreements to acquire the following:

•Clearwater Wind Development—PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. entered into agreements to construct a 311 MW wind energy facility, which will be part of the larger Clearwater Wind development in Eastern Montana. PGE will own 208 MW of production capacity of the 311 MW in these agreements, with an investment of approximately $415 million, excluding an allowance for funds used during construction (AFUDC). Subsidiaries of NextEra Energy Resources, LLC will own the remaining 103 MW of production capacity and will sell their portion of the output to PGE under a 30-year PPA. Subsidiaries of NextEra Energy Resources, LLC plan to design, build and operate the facility. The project has an estimated commercial operation date of December 31, 2023.

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•Seaside Grid—PGE and Eolian, L.P. entered into an agreement to construct a 200 MW BESS in Portland, Oregon. PGE will own the resource, with an investment of approximately $360 million, excluding AFUDC. The project has an estimated commercial operation date of June 30, 2025.

•Troutdale Grid—PGE and Eolian L.P. entered into a storage capacity agreement for a 200 MW BESS in Troutdale, Oregon. The project was subsequently acquired by NextEra Energy Resources, LLC, who will own the resource and will sell the capacity to PGE under a 20-year storage capacity agreement. The project has an estimated commercial operation date of December 31, 2024.

PGE continues to negotiate with a remaining 2021 All-Source RFP short-list bidder that could result in an agreement to construct a company-owned 75 MW BESS project. If parties are able to reach a definitive agreement, the Clearwater agreements and all BESS agreements would represent the final projects to be procured from the 2021 All-Source RFP. Resources required to meet the remaining 2030 need are anticipated to be procured through future acquisition processes, including, but not limited, to the 2023 All-Source RFP and future RFPs.

All BESS projects will be emissions-free dispatchable capacity resources directly interconnected to PGE’s system. Company-owned BESS agreements will qualify for the federal investment tax credit (ITC). The Clearwater agreements will qualify for the federal production tax credit (PTC) and will be eligible under Oregon’s Renewable Portfolio Standard (RPS). The agreements will be subject to prudency review by the OPUC.

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 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. After receiving multiple extensions, NewSun filed its opening brief in the appeal in February 2023. On October 28, 2022, NewSun filed a petition in Deschutes County Circuit Court seeking review of the OPUC order acknowledging, with conditions, PGE’s 2021 All-Source RFP shortlist. PGE has intervened in this case and, on March 16, 2023, filed a motion to dismiss. PGE cannot predict the outcome of these proceedings or potential impact, if any, to its ongoing 2021 All-Source RFP process.

2023 All-Source RFP

PGE filed notice with the OPUC on January 31, 2023 that an RFP in 2023 is needed to procure resources to meet a forecasted 2026 capacity shortfall and to make continued progress toward HB 2021’s decarbonization targets. These actions are consistent with the 2023 IRP Action Plan and CEP. The filing includes PGE’s request for a partial waiver of the OPUC’s competitive bidding rules, which was approved by the OPUC on April 18, 2023, and outlines PGE’s recommended timeline for obtaining necessary regulatory approvals and issuing the RFP to the market in the third quarter of 2023. PGE desires to select a final shortlist and submit a request for acknowledgment to the OPUC simultaneously with potential Commission acknowledgment of an energy or capacity need within the IRP/CEP, which is currently projected to be in the first quarter of 2024.

Building a resilient grid—To serve communities with clean energy, PGE’s grid of the future will need to be smart and adaptive. Highlights of PGE’s key investments and plans for building a resilient grid include:

•Wildfire Mitigation—PGE’s Wildfire Mitigation & Resiliency organization plans and implements the Wildfire Mitigation Program, developing and coordinating activities across the company.

•Virtual Power Plant (VPP)—PGE’s customer offerings related to energy efficiency and flexible load programs, rooftop solar, battery storage and electric vehicle charging solutions aim to support grid reliability and increase portfolio flexibility and resource diversity. These distributed energy resources are the foundation of PGE’s VPP that will provide a growing suite of grid and system services over time. When

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coordinated through a VPP platform, distributed energy resources and flexible loads can help the Company achieve cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enable PGE’s distribution system plan (DSP) vision of a dynamic two-way system.

•Distribution System Plan—In 2021, PGE filed its inaugural 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 accepted by the OPUC on March 8, 2022. Part Two was filed on August 15, 2022 and accepted by the OPUC on February 28, 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 increasing electrification of buildings and supports the accelerating pace of vehicle electrification for our customers, as well as our own vehicle fleet.

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 GHG emissions 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. PGE made a request to the OPUC to delay the filing of its next full Transportation Electrification plan until no later than June 1, 2023 to allow for time for review and evaluation of the plan in the context of the Company’s IRP and CEP filings. This request was approved by the OPUC on February 7, 2023.

Businesses and families continue to turn to electricity to serve their home and workplace needs. PGE 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.

Laws and Regulations

Infrastructure Investment and Jobs Act—On November 15, 2021, President Biden signed into law the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA), which includes approximately $550 billion of new federal spending. PGE is pursuing multiple areas under the IIJA for potential grant funding of projects. These projects target improvements in electrical system reliability and resiliency, wildfire situational awareness and mitigation, greater communications capabilities, advancements in customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, and regional transmission capacity constraints. As of March 31, 2023, PGE has submitted five full applications. PGE cannot predict the ultimate timing and success of securing funding from programs under the IIJA.

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Inflation Reduction Act of 2022—The Inflation Reduction Act of 2022 (IRA) was signed into law by President Biden on August 16, 2022 with a majority of the provisions effective for tax years beginning after December 31, 2022. Among other provisions, the bill includes:

•implementation of a new corporate alternative minimum tax (CAMT) for applicable corporations with average adjusted financial statement income over a three-year period in excess of $1 billion per year;

•an excise tax of 1% of the fair market value of any stock which is repurchased, reduced by any stock issued during the taxable year; and

•significant tax incentives for energy and climate initiatives, including:

◦A three-year extension and modification of PTCs for facilities that begin construction before December 31, 2024;

◦An opt-out of Investment Tax Credit (ITC) normalization requirements on certain stand-alone storage projects;

◦The ability to transfer or sell PTCs and ITCs to other taxpayers;

◦Reestablished solar PTC which would allow PGE the opportunity to be competitive in owning solar resources in renewable RFPs;

◦Beginning January 1, 2025, the traditional resource-specific PTCs and ITCs are replaced with technology-neutral clean electricity credits. Critical normalization alternatives are retained with these credits; and

◦Several provisions supporting expanded transportation electrification.

The Company does not expect the excise tax on stock repurchases and the new CAMT to have an impact on the Company’s results of operations. PGE will be closely monitoring guidance from the IRS regarding the enhanced energy credits available under the IRA. Compared to previous resource planning processes, the Company believes the new tax incentives will provide additional investment opportunities for PGE and result in lower customer prices. Increased capital expenditures in such investment opportunities would likely result in additional financing needs through debt and equity instruments.

HB 2021—In June 2021, the Oregon Legislature passed HB 2021, which, among other things, requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. The baseline levels for PGE are the average annual emissions for the years 2010, 2011, and 2012 associated with the electricity sold to its 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 each IRP, and to develop a DSP at reasonable costs to retail electricity consumers. In reviewing a CEP, the OPUC must ensure that utilities plan for equitable implementation and demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions. Regulated entities will continue to report annual GHG emissions to the ODEQ, as they do today. In threshold years, and every year thereafter, the OPUC will use the data reported to the ODEQ for that compliance year to determine whether the reduction targets are met.

Utilizing the methodology per the ODEQ’s Greenhouse Gas Reporting Protocol for investor-owned utilities, the preliminary percentage of 2023 retail load served by non-emitting resources is 32 percent as of March 31, 2023. This amount excludes generation and purchases associated with power delivered outside of PGE service territory.

Governor executive order—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

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encourage electric companies to support transportation electrification infrastructure that supports GHG emissions reductions and zero-emission vehicle 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. In December 2021, the ODEQ adopted the Climate Protection Plan, which provided an exemption for electricity generation from the Company’s natural gas-fired resources. The executive order also modified 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 by 2025, to a 25 percent reduction 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, 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.

PGE ceased coal fired operation at its Boardman generating facility in 2020 and continues the process of decommissioning the plant. The Company has a 20% ownership share in Colstrip Units 3 and 4 and in response to SB 1547, the Company filed a tariff request in 2016 with the OPUC and received approval 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 units, ongoing operations of Units 3 and 4 utilize certain common facilities with Units 1 and 2.

Effective May 9, 2022, PGE’s depreciation rates and associated customer prices changed as approved by the OPUC in the Company’s 2022 General Rate Case (2022 GRC) to reflect further accelerated depreciation of Colstrip Units 3 and 4 from 2030 to December 31, 2025. In order to meet PGE’s regulatory and legislative requirements, the Company continues to evaluate the possibility of exiting ownership of Units 3 and 4 to meet PGE’s regulatory and legislative requirements. 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 an approximate 15% ownership interest in, and capacity on, the Colstrip transmission facilities. See “Investing in a Clean Energy Future” in this Overview for information regarding development in eastern Montana.

Other provisions of SB 1547 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 opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s Renewable Adjustment Clause (RAC) filings.

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

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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—On February 15, 2023, PGE filed with the OPUC a GRC based on a 2024 test year (2024 GRC) requesting an increase that, when including Colstrip-related adjustments through a supplemental tariff, results in an overall average increase of approximately 14.0% in customer prices for 2024. The requested price increase includes an approximate 4.5% increase as a result of higher NVPC expected in 2024. The NVPC projection will be updated periodically during 2023.

The Company’s 2024 GRC filing seeks recovery of capital investments made across the business to meet growing demand, improve reliability, resiliency, and capability to deliver safe, reliable, clean electricity to customers. A significant portion of the Company’s capital is related to the continued investment in the transmission and distribution system to meet evolving customer expectations and growing demand while also replacing aging infrastructure. PGE’s request also includes recovery of the capital costs associated with the project to repower the original 1907 Faraday hydro facility. The upgrade project was placed into service January 31, 2023.

PGE is seeking operations and maintenance increases critical for maintaining the ability to deliver safe, reliable, affordable power amid a period of record inflation. The Company has seen cost pressures in various areas of the business, including labor, wholesale electricity and natural gas commodity prices, and the increased cost-of-debt associated with higher interest rates on its long-term debt.

The Company is also proposing key changes to its power cost adjustment mechanism (PCAM) and modifications to the AUT to better address highly dynamic and volatile power market uncertainties and evolving regional fundamental drivers.

PGE has requested a:

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

•return on equity of 9.8%;

•cost of capital of 7.06%, which reflects updates for actual and forecasted debt costs; and

•rate base of $6.3 billion.

Regulatory review of the 2024 GRC (OPUC Docket UE 416) will continue throughout 2023, with a final order expected to be issued by the OPUC in December 2023, for new customer prices effective January 1, 2024.

COVID-19 impacts—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. 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 both March 31, 2023 and December 31, 2022, PGE’s deferred balance was $22 million, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. The Company released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for 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. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. During the March 14, 2023 public meeting, Staff recommended the Commission approve PGE's filing of Advice No. 22-45 associated with the recovery of the COVID-19 deferral.

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On March 21, 2023, Advice No. 22-45 was approved by the Commission, allowing for amortization of deferred amounts over a two-year period beginning April 1, 2023.

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 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 2022. 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 March 31, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $31 million and $28 million, respectively. 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.

PGE submitted a tariff filing on August 19, 2022 for an automatic adjustment clause for incremental wildfire mitigation spending, as allowed under SB 762. The filing included a proposal to report semi-annually to show PGE’s progress relative to its Wildfire Mitigation Plan, which is filed under docket UM 2208. On September 9, 2022, the OPUC suspended the tariff and opened docket UE 412 to investigate the filing. On January 13, 2023, PGE, Staff, and certain intervenors entered into a partial stipulation that would establish a Wildfire Mitigation Mechanism that would allow recovery of PGE’s prudently incurred wildfire mitigation costs, subject to a prudency review. The partial stipulation also supports the deferral of PGE’s wildfire mitigation costs related to 2022 and 2023 that exceed the amount currently granted in customer prices, subject to a prudency review. The partial stipulation is pending OPUC approval which is targeted for May 10, 2023.

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.

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 2023 AUT included a final increase in power costs for 2023, and a corresponding increase in annual revenue requirement, of $186 million from 2022 levels, which were reflected in customer prices effective January 1, 2023.

Portland Harbor Environmental Remediation Account (PHERA) mechanism—The 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 March 31, 2023, 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

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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 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.

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 not occur after 2022, although amortization of then previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices. In the 2024 GRC filing, the Company has included a concept proposal that could lead to resuming decoupling January 1, 2024, with certain modifications.

For the year ended December 31, 2022, PGE had recorded a total estimated collection of $3 million that, subject to OPUC approval, will be refunded to customers over a one-year period beginning January 1, 2024.

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. PGE estimated the revenue requirement for Boardman to be $14 million for the year ended December 31, 2020, an additional $66 million for the year ended December 31, 2021, and $23 million for the year ended December 31, 2022.

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, showed 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. Although still subject to OPUC review, PGE does not believe it exceeded its regulated return on equity under the earnings test for 2022.

On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and states that no refund remains necessary for that year. The stipulation remains subject to OPUC approval. Review and determination of potential refund for the periods related to 2020 and 2022 remain outstanding. In November 2022, the OPUC granted a motion by PGE to suspend the procedural schedule and directed the Company to file a status update no later than February 16, 2023. In granting the ruling the OPUC noted that it expects to resolve this matter, addressing both the 2020 and 2022 deferrals, within the first half of 2023.

The status update on February 16, 2023 stated that a settlement conference had been scheduled and parties anticipated filing with the OPUC a status update, settlement agreement, or proposed procedural schedule by March

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14, 2023. On March 13, 2023, PGE notified the OPUC that settlement discussions had been productive and the parties anticipated resolution of the matter before the end of the first half of 2023.

Based on the application of an earnings test, PGE has not recorded a refund related to Boardman for 2020, 2021, or 2022. PGE believes the range of reasonably possible refund is limited to the Boardman revenue requirement for the year 2020. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could require additional refunds that would be recognized as a charge to earnings, 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. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a GRC. There have been no significant filings made under the RAC during 2023.

In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. PGE is requesting within its 2024 GRC that the OPUC clarify that energy storage used to integrate renewables on a utility’s system qualifies as associated energy storage.

Operating Activities

In addition to electricity provided by PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, the Company purchases and sells electricity in the wholesale market. PGE also performs portfolio management and wholesale market sales services for third parties in the region. The Company participates in the western Energy Imbalance Market, which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. In its ongoing effort to benefit retail and wholesale customers, PGE is now participating in the Western Power Pool’s resource adequacy program for the region known as the WRAP, the binding period for which could start in 2025 at the earliest. The WRAP represents an effort to increase reliability and clean energy in the region through resource diversification and load sharing while managing overall costs. The Company also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.

PGE 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 and did record a new winter peak load in December 2022. Summer peak deliveries have continued to exceed those of the winter months for several years, generally resulting from air conditioning demand and the trend toward a warmer overall climate. During the summer of 2021, demand reached a new all-time high, surpassing the previous mark, which was a winter peak. Retail customer price changes and customer usage patterns, which can be affected by the economy and recently, by changes resulting from COVID-19, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to help ensure the availability of supply chain-constrained items that are needed to serve new and existing customers, such as advance ordering of critical materials, pre-securing manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. PGE has also taken measures to help mitigate cost increases through long term agreements, supplier engagement and expanding the supply base.

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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 March 31,		% Increase (Decrease) in Energy Deliveries
	2023	2022
Energy deliveries (MWhs in thousands):
Retail:
Residential	2,327	2,216	5	%
Commercial	1,657	1,634	1	%
Industrial	1,071	974	10	%
Subtotal	5,055	4,824	5	%
Direct access:
Commercial	129	131	(2)	%
Industrial	436	413	6	%
Subtotal	565	544	4	%
Total retail energy deliveries	5,620	5,368	5	%
Wholesale energy deliveries	1,396	1,507	(7)	%
Total energy deliveries	7,016	6,875	2	%

	Three Months Ended March 31,
	2023			2022
Average number of retail customers:
Residential	813,955	88	%	806,553	88	%
Commercial	112,475	12		111,668	12
Industrial	194	—		192	—
Direct access	542	—		550	—
Total	927,166	100	%	918,963	100	%

Total retail energy deliveries for the three months ended March 31, 2023 increased 5% compared with the three months ended March 31, 2022, driven by higher demand from the industrial customer class.

The industrial class continues to show growth in energy deliveries, due primarily to ongoing strength in the high-tech and digital services sectors. The impact of weather was positive with colder than normal temperatures experienced in the three-month period ended March 31, 2023 compared to the same three months of 2022.

The following table indicates the number of heating degree-days for the three months ended March 31, 2023 and 2022, 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
	2023		2022		Avg.
January	667		710		713
February	658		591		599
March	602		460		528
Year-to-date	1,927		1,761		1,840
Increase/(decrease) from the 15-year average	5	%	(4)	%

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After adjusting for the effects of weather, total retail energy deliveries for the three months ended March 31, 2023 increased 1.9% compared to the same period of 2022. The increase reflects 8% higher industrial delivery volumes, commercial delivery volumes that were up less than one percent, and are partially offset by 1% lower residential deliveries when compared to the prior year. Residential weather-adjusted deliveries saw average usage per customer 1.8% lower during the first three months of 2023 compared with 2022, while the average number of residential customers was 0.9% greater during 2023 than 2022.

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. Had the cap limit been fully subscribed and utilized, 12% of PGE’s total retail energy deliveries for the first three months of 2023 would have been to these customers.

In 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 16% of the Company’s energy deliveries could have been supplied by ESSs to Direct Access customers. Actual deliveries to Direct Access customers of energy supplied by ESSs represented 10% of PGE’s total retail energy deliveries for the first three months of 2023 and 2022.

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 three months ended March 31, 2023 and 2022:

	Plant availability (1)				Actual energy provided compared to projected levels (2)				Actual energy provided as a percentage of total retail load
	2023		2022		2023		2022		2023		2022
Generation:
Thermal:
Natural gas	91	%	92	%	102	%	79	%	54	%	42	%
Coal (3)	94		96		108		110		11		12
Wind (4)	88		74		101		83		9		8
Hydro	97		96		47		81		5		5

(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 three months ended March 31, 2023 compared to 2022 increased 27%. This increase is primarily driven by economic dispatch decisions. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices,

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variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, decreased 25% during the three months ended March 31, 2023 compared to 2022 primarily due to less favorable hydro conditions in the current period. Energy purchased from mid-Columbia and other regional hydroelectric projects decreased 31% while energy generated by the Company-owned facilities increased 8% in the three months ended March 31, 2023. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See “Purchased power and fuel” in the Results of Operations section in this Item 2, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 21% during the three months ended March 31, 2023 compared to 2022 primarily due to unplanned plant outages in 2022 that did not reoccur. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available.

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 three months ended March 31, 2023 and 2022, respectively:

•For the three months ended March 31, 2023, actual NVPC was $13 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2023 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 2023.

•For the three months ended March 31, 2022, actual NVPC was $10 million below baseline NVPC. For the year ended December 31, 2022, actual NVPC was $23 million above baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded for 2022.

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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 March 31,				% Increase (Decrease)
	2023		2022
Total revenues	$	748	$	626	19	%
Operating expenses:
Purchased power and fuel	304		202		50
Generation, transmission and distribution	93		90		3
Administrative and other	80		89		(10)
Depreciation and amortization	111		99		12
Taxes other than income taxes	43		40		8
Total operating expenses	631		520		21
Income from operations	117		106		10
Interest expense, net*	44		38		16
Other income:
Allowance for equity funds used during construction	3		3		—
Miscellaneous income, net	12		—		—
Other income, net	15		3		400
Income before income tax expense	88		71		24
Income tax expense	14		11		27
Net income	$	74	$	60	23	%

* Includes an allowance for borrowed funds used during construction of $2 million for both the three months ended March 31, 2023 and 2022.

Net income for the three months ended March 31, 2023 increased $14 million over the three months ended March 31, 2022. Income from operations improved 10%, as Total revenues and Purchased power and fuel expenses both increased. Retail revenues were up 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, and a 5% increase in total retail energy deliveries over the prior year quarter. Wholesale revenues also increased, driven by considerably higher market prices in 2023. Total operating expenses increased compared to the prior year quarter, reflecting the higher Purchased power and fuel expense largely driven by higher natural gas prices. An increase in Depreciation and amortization expense resulted from the accelerated depreciation of Colstrip, which is offset in retail revenues, and was approved by the OPUC in the Company’s 2022 GRC, which took effect in the second quarter of 2022. Operating expenses in the three months ended March 31, 2022 included a $17 million charge for previously deferred items that were disallowed as a result of the 2022 GRC order from the OPUC. Other income, net increased in 2023 as a result of gains on non qualified benefit trust plan assets and higher interest income recorded on regulatory assets.

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

	Three Months Ended March 31,
	2023				2022
Retail:
Residential	$	362	48	%	$	308	49	%
Commercial	197		27		178		29
Industrial	82		11		69		11
Direct Access*	6		1		8		1
Subtotal	647		87		563		90
Alternative revenue programs, net of amortization	3		—		1		—
Other accrued revenues, net	1		—		—		—
Total retail revenues	651		87		564		90
Wholesale revenues	88		12		56		9
Other operating revenues	9		1		6		1
Total revenues	$	748	100	%	$	626	100	%

*Commercial revenues from Direct Access customers for the three months ended March 31, 2023 were $2 million. For the comparable three-month period of 2022, revenues were $3 million. Industrial revenues from Direct Access customers for the three months ended March 31, 2023 were $4 million. For the comparable three-month period of 2022, revenues were $5 million.

Total retail revenues—The following items contributed to the increase in Total retail revenues for the three months ended March 31, 2023 compared to the same periods in 2022 as follows (in millions):

	Three Months Ended
March 31, 2022	$	564
Change as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)	35
Higher retail energy deliveries driven by customer load growth	26
Average price of energy deliveries due primarily to customer price increases and the relative mix of deliveries among customer classes	4
Colstrip plant life adjustment	6
Wildfire mitigation revenue (offset in generation, transmission and distribution)	6
Recovery in Revenues of deferrals for 2020 Wildfire and 2021 ice storm	5
Alternative revenue programs related to the decoupling mechanism due primarily to prorated elimination of the mechanism in 2022	2
Combination of various supplemental tariffs and adjustments	3
March 31, 2023	$	651
Change in Total retail revenues	$	87

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 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.

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For the three months ended March 31, 2023, Wholesale revenues increased $32 million, or 57%, from the three months ended March 31, 2022 as a $36 million increase from 70% higher average wholesale sales price was partially offset by a $4 million decrease due to a 7% decrease in sales volumes. Although prices were high in the three months ended March 31, 2022, prices have continued to increase during 2023 due to the overall economic recovery, strong demand in part due to the unusually cool weather during the 2023 quarter, the impact on natural gas prices resulting from global energy issues, and ongoing capacity limitations in the region.

Other operating revenues increased $3 million for the three months ended March 31, 2023 compared with the same period in 2022. Market conditions resulted in the Company selling excess natural gas at a loss in 2022 while differences in transmission and wheeling revenues partially offset the year over year increase.

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 months ended March 31, 2023 compared to the same period in 2022 (dollars in millions, except for average variable power cost per Megawatt hour (MWh)):

	Three Months Ended
March 31, 2022	$	202
Average variable power cost per MWh	119
Total system load	(21)
2021 PCAM deferral amortization	4
March 31, 2023	304
Change in Purchased power and fuel	$	102
Average variable power cost per MWh:
March 31, 2022	$	30.34
March 31, 2023	$	44.25
Total system load (MWhs in thousands):
March 31, 2022	6,648
March 31, 2023	6,784

For the three months ended March 31, 2023, the $119 million increase related to the change in average variable power cost per MWh was driven by a 71% increase in the average cost of purchased power and a 58% increase in the average cost for the Company’s own generation. The $21 million decrease related to total system load was primarily due to a 22% decrease in deliveries of energy obtained from purchased power, offset by a 25% increase in the Company’s own generation.

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

	Three Months Ended March 31,
	2023			2022
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	2,896	43	%	2,149	32	%
Coal	596	9		610	9
Total thermal	3,492	52		2,759	41
Hydro	295	4		273	4
Wind	481	7		392	6
Total generation	4,268	63		3,424	51
Purchased power:
Hydro	1,080	16		1,562	23
Wind	232	3		195	3
Solar	145	2		113	2
Natural Gas	11	—		2	—
Waste, Wood and Landfill Gas	43	1		37	1
Source not specified	1,005	15		1,315	20
Total purchased power	2,516	37		3,224	49
Total system load	6,784	100	%	6,648	100	%
Less: wholesale sales	(1,396)			(1,507)
Retail load requirement	5,388			5,141

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 March 31,
	2023	2022
Sources of energy (MWhs in thousands):
PURPA purchased power:
Hydro	8	6
Wind	5	6
Solar	102	104
Waste, Wood and Landfill Gas	28	20
Total	143	136

The following table presents the forecast April-to-September 2023 and actual 2022 runoff at particular points of major rivers relevant to PGE’s hydro resources:

	Runoff as a Percent of Normal*
Location	2023 Forecast		2022 Actual
Columbia River at The Dalles, Oregon	86	%	107	%
Mid-Columbia River at Grand Coulee, Washington	85		110
Clackamas River at Estacada, Oregon	104		139
Deschutes River at Moody, Oregon	93		92

* 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 months ended March 31, 2023 increased compared to the same period in 2022 as follows (in millions):

	Three Months Ended
March 31, 2022	$	146
Purchased power and fuel expense	98
Wholesale revenues	(32)
2021 PCAM deferral amortization	4
March 31, 2023	$	216
Change in NVPC	$	70

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 March 31, 2023 and 2022, actual NVPC was $13 million above and $10 million below baseline NVPC, respectively.

Based on forecast data, NVPC for the year ending December 31, 2023 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 2023.

Generation, transmission and distribution increased $3 million for the three months ended March 31, 2023 compared to the same period in 2022 (in millions):

	Three Months Ended
March 31, 2022	$	90
Higher distribution vegetation management, inspection, wildfire mitigation, and maintenance expenses	6
Amortizations from collections of previously deferred 2020 wildfire and 2021 ice storm costs	5
Higher generating facility expenses from higher run hours and increased maintenance costs	3
Higher service restoration and storm response costs	2
2022 release of previously deferred amounts pursuant to earnings test created in OPUC Q1 2022 GRC Order	(16)
Miscellaneous expenses	3
March 31, 2023	$	93
Change in Generation, transmission and distribution	$	3

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Administrative and other decreased $9 million for the three months ended March 31, 2023 compared to the same period in 2022 as follows (in millions):

	Three Months Ended
March 31, 2022	$	89
Lower professional service expenses	(5)
Lower employee compensation and benefits expenses	(3)
Lower bad debt expense	(2)
Miscellaneous expenses	1
March 31, 2023	$	80
Change in Administrative and other	$	(9)

Depreciation and amortization expense increased $12 million for three months ended March 31, 2023 compared to the same period in 2022. The increase was driven by regulatory amortizations as well as accelerated depreciation of the Colstrip facility as approved by the OPUC’s April 2022 GRC Order and commenced in May 2022.

Taxes other than income taxes expense increased $3 million in the three months ended March 31, 2023, compared to the same period in 2022. The increase was driven by higher property tax expenses.

Interest expense, net increased $6 million in the three months ended March 31, 2023 compared to the same period in 2022 primarily due to higher long-term debt balances.

Other income, net increased $12 million for the three months ended March 31, 2023 compared to the same period in 2022. The increase was primarily driven by $6 million in favorable market changes on the non-qualified benefit trust and the recognition of $5 million of previously deferred equity interest income in conjunction with amortization of regulatory deferrals that began in 2023.

Income tax expense increased $3 million for the three months ended March 31, 2023, compared to the same period in 2022, driven by higher pre-tax income.

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, 2022, filed with the SEC on February 16, 2023.

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.

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

	Three Months Ended March 31,
	2023		2022
Cash and cash equivalents, beginning of period	$	165	$	52
Net cash provided by (used in):
Operating activities	(39)		249
Investing activities	(276)		(154)
Financing activities	162		(37)
Increase (decrease) in cash and cash equivalents	(153)		58
Cash and cash equivalents, end of period	$	12	$	110

Cash Flows from Operating Activities—Cash flows used in operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the three months ended March 31, 2023 compared with the three months ended March 31, 2022 (in millions):

	Increase/ (Decrease)
Net income	$	14
2020 Labor Day wildfire earnings test reserve non-cash adjustment to Net income	(15)
Accounts receivable and Unbilled revenue	13
Margin deposits activity	(176)
Accounts payable	(130)
Other miscellaneous changes	6
Net change in cash flow from operations	$	(288)

For the three months ended March 31, 2023 operating cash flows were significantly impacted by changes in working capital from December 31, 2022, primarily related to Accounts payable for purchased power and fuel costs and related margin deposits activity. In December 2022, PGE experienced elevated natural gas and power prices due to volatility in the wholesale markets, which led to increased cash used in operating activities for the quarter ended March 31, 2023 as cash payments for physical commodity purchases and related margin activity were made.

PGE estimates that non-cash charges for depreciation and amortization in 2023 will range from $445 million to $465 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $550 million to $600 million.

Cash Flows from Investing Activities—Net cash used in investing activities for the three months ended March 31, 2023 increased $122 million when compared with the three months ended March 31, 2022. 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 $107 million, and $10 million related to proceeds from the sale of property.

Excluding AFUDC, the Company plans to make capital expenditures of $1.3 billion in 2023, which it expects to fund with cash to be generated from operations during 2023, as discussed above, the issuance of short- and long-term debt securities, and issuances of shares pursuant to an equity forward sale agreement (EFSA). For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

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Cash Flows from Financing Activities—During the three months ended March 31, 2023, net cash provided by financing activities was primarily the result of $300 million in proceeds from the issuance of common stock pursuant to the EFSA, funding of $100 million in FMBs, and $68 million due to the issuance of commercial paper offset by a $260 million repayment of a term loan and payment of $40 million of dividends.

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2023 through 2027, excluding AFUDC (in millions).

	2023		2024		2025		2026		2027
Ongoing capital expenditures(1)	$	840	$	780	$	800	$	800	$	800
Clearwater Wind project	415		—		—		—		—
BESS projects	70		130		160		—		—
Total capital expenditures(2)	$	1,325	$	910	$	960	$	800	$	800
Long-term debt maturities	$	260	$	80	$	—	$	—	$	160

(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 inflationary pressures and interest rate increases by the federal reserve. 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 2023, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $550 million to $600 million and issuances of long-term debt securities of up to $400 million. PGE plans to fund the balance through the combination of issuance of common stock and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt, equity 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 March 31, 2023 (in millions):

	As of March 31, 2023
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	650	$	68	$	582
Letters of credit (2)	220		135		85
Total credit	$	870	$	203	$	667
Cash and cash equivalents					12
Total liquidity					$	679

(1)Scheduled to expire September 2027.

(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 2022, PGE amended its existing revolving credit facility. As of March 31, 2023, PGE had a $650 million unsecured revolving credit facility scheduled to expire in September 2027. 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 March 31, 2023, PGE had $68 million of commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $582 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 March 31, 2023, PGE’s total long-term debt outstanding, net of $13 million of unamortized debt expense, was $3,485 million.

On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in FMBs. The Bonds consist of:

•a series, due in 2029, in the amount of $100 million that will bear interest at an annual rate of 5.47%; and

•a series, due in 2033, in the amount of $100 million that will bear interest at an annual rate of 5.56%.

The 2029 and 2033 Bonds were issued in 2022 and funded in full on November 30, 2022 and January 13, 2023, respectively.

On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bore interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 87.5 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 1, 2023, this term loan was repaid in full with proceeds from the Equity Forward Sale Agreement described below.

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Equity—In 2022, PGE entered into an EFSA in connection with the public offering of 10,100,000 shares of its common stock. Effective October 28, 2022, pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock with an initial value of $499 million, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters. PGE receives proceeds from the sale of the common stock when the EFSA is physically settled. In March 2023, the Company issued 7,178,016 shares pursuant to the EFSA and received net proceeds of $300 million.

As of March 31, 2023, the Company could have physically settled the EFSA by delivering 4,436,984 shares of PGE common stock to the forward counterparty in exchange for cash of $184 million. The Company anticipates physical settlement of the EFSA by delivery of newly issued shares on or before October 25, 2024. For additional information on the EFSA, see Note 7, Shareholders’ Equity, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

At-the-market Offering Program—PGE anticipates entering into an at-the-market offering program in the second quarter of 2023. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 46.7% and 43.3% as of March 31, 2023 and December 31, 2022 respectively.

Credit Ratings and Debt Covenants

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

	Moody’s	S&P
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 March 31, 2023, PGE had posted $99 million of collateral with these counterparties, consisting of $30 million in cash and $69 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2023, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $39 million, and decreases to $6 million by December 31, 2023. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $170 million and decreases to $114 million by December 31, 2023 and to $75 million by December 31, 2024.

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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 March 31, 2023, under the most restrictive issuance test in the Indenture, the Company could have issued up to $741 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 March 31, 2023, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 54.2%.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations, or cash flows. There have been no material changes to market risks, or credit risk, affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 16, 2023.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2023, 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.

59

Item 1A. Risk Factors.

There have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 16, 2023.

Item 6. Exhibits.

Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
10.1	Portland General Electric Company Stock Incentive Plan as Amended and Restated Effective April 21, 2023, (incorporated by reference to Appendix A to Portland General Electric Company’s definitive proxy statement on Schedule 14A filed March 10, 2023).
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 April 28, 2023, 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.

60

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)
Date:	April 27, 2023	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President Finance CFO, Treasurer & Corporate Compliance Officer
			(duly authorized officer and principal financial officer)

61

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	April 27, 2023	By:	/s/ Maria M. Pope
			Maria M. Pope
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James A. Ajello, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	April 27, 2023	By:	/s/ James A. Ajello
			James A. Ajello
			Senior Vice President Finance CFO, Treasurer & Corporate Compliance Officer

EX-32.1

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 March 31, 2023, as filed with the Securities and Exchange Commission on April 28, 2023 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:	April 27, 2023	Date:	April 27, 2023

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2023	Apr. 20, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
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		96,621,298
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
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
	Mar. 31, 2023	Mar. 31, 2022
Revenue, net	$ 745	$ 625
Alternative revenue programs, net of amortization	3	1
Total revenues	748	626
Operating expenses:
Purchased power and fuel	304	202
Generation, transmission and distribution	93	90
Administrative and other	80	89
Depreciation and amortization	111	99
Taxes other than income taxes	43	40
Total operating expenses	631	520
Income from operations	117	106
Interest expense, net	44	38
Other income:
Allowance for equity funds used during construction	3	3
Miscellaneous income (loss), net	12	0
Other income, net	15	3
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	88	71
Income tax expense	14	11
Net income	74	60
Comprehensive Income	$ 74	$ 60
Weighted-average common shares outstanding (in thousands):
Basic	91,840	89,396
Diluted	92,571	89,527
Basic	$ 0.81	$ 0.67
Diluted	$ 0.80	$ 0.67

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Current assets:
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 12	$ 165
Accounts receivable, net	362	398
Inventories	95	95
Regulatory assets - current	65	54
Other current assets	232	498
Total current assets	766	1,210
Electric utility plant, net	8,611	8,465
Regulatory assets - noncurrent	481	473
Nuclear decommissioning trust	38	39
Non-qualified benefit plan trust	38	38
Other noncurrent assets	217	234
Total assets	10,151	10,459
Current liabilities:
Accounts payable	242	457
Liabilities from price risk mangement activities - current	100	118
Short-term debt	68	0
Current portion of long-term debt	0	260
Current portion of finance lease obligation	20	20
Accrued expenses and other current liabilities	321	641
Total current liabilities	751	1,496
Long-term debt, net of current portion	3,485	3,386
Regulatory liabilities-noncurrent	1,398	1,389
Deferred income taxes	447	439
Unfunded status of pension and psotretirement plans	170	170
Liabilities from price risk management activities-noncurrent	70	75
Asset retirement obligations	250	257
Non-qualified benefit plan liabilities	81	83
Finance lease obligations, net of current portion	293	294
Other noncurrent liabilities	94	91
Total liabilities	7,039	7,680
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	1,548	1,249
Accumulated other comprehensive loss	(4)	(4)
Retained earnings	1,568	1,534
Total shareholders' equity	3,112	2,779
Total liabilities and shareholders' equity	$ 10,151	$ 10,459

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2023	Dec. 31, 2022
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	96,620,972	89,283,353
Common stock, shares outstanding	96,620,972	89,283,353

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash flows from operating activities:
Net income	$ 74	$ 60
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	111	99
Deferred income taxes	4	4
Pension and other postretirement benefits	1	3
Allowance for equity funds used during construction	(3)	(3)
Decoupling mechanism deferrals, net of amortization	(3)	(1)
2020 Labor Day wildfire earnings test reserve	0	15
Other non-cash income and expenses, net	10	15
Changes in working capital:
Decrease in accounts receivable, net	34	21
(Increase) in inventories	0	6
(Increase)/decrease in margin deposits	86	23
(Decrease) in accounts payable and accrued liabilities	(174)	(44)
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(140)	99
Other working capital items, net	(27)	(27)
Other, net	(14)	(11)
Net cash provided by operating activities	(39)	249
Cash flows from investing activities:
Capital expenditures	(274)	(167)
Sales of Nuclear decommissioning trust securities	0	2
Purchases of Nuclear decommissioning trust securities	0	(2)
Proceeds from Sale of Property, Plant, and Equipment	2	12
Other, net	(4)	1
Net cash used in investing activities	(276)	(154)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Payments on long-term debt	(260)	0
Proceeds from Issuance of long-term debt	100	0
Issuance of commercial paper, net	68	0
Proceeds from failed sale-leaseback transactions	0	25
Dividends paid	(40)	(38)
Repurchase of common stock	0	(18)
Other	(6)	(6)
Net cash provided by (used in) financing activities	162	(37)
Increase (Decrease) in cash and cash equivalents	(153)	58
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	12	110
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	22	18
Cash paid for income taxes, net	2	2
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	0	29
Proceeds from Issuance or Sale of Equity	300
Increase (Decrease) in Other Regulatory Assets	(6)	(15)
Increase (Decrease) in Regulatory Liabilities	8	5
Common Stock Including Additional Paid in Capital [Member]
Net Cash Provided by (Used in) Financing Activities [Abstract]
Repurchase of common stock		(5)
Supplemental cash flow information is as follows:
Proceeds from Issuance or Sale of Equity	$ 300	$ 0

XML

Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2023

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 (State). 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 , 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 approximately 4,000 square mile, State-approved service area, entirely within the State, encompasses 51 incorporated cities. As of March 31, 2023, PGE served 928,000 retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

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

The financial information included herein as of and for the three months ended March 31, 2023 and 2022 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, 2022 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2022, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 16, 2023, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three months ended March 31, 2023 and 2022.

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.

XML

Revenue Recognition (Notes)

3 Months Ended

Mar. 31, 2023

Revenue Recognition and Deferred Revenue [Abstract]

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

REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended March 31,
	2023		2022
Retail:
Residential	$	362	$	308
Commercial	197		178
Industrial	82		69
Direct access customers	6		8
Subtotal	647		563
Alternative revenue programs, net of amortization	3		1
Other accrued revenues, net	1		—
Total retail revenues	651		564
Wholesale revenues*	88		56
Other operating revenues	9		6
Total revenues	$	748	$	626

* Wholesale revenues include $34 million and $19 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2023 and 2022, 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 Revenues, net on the condensed consolidated statements of income.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon, among other things, 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.

XML

Balance Sheet Components (Notes)

3 Months Ended

Mar. 31, 2023

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 $115 million and $131 million of unbilled revenues as of March 31, 2023 and December 31, 2022, respectively. Accounts receivable, net includes an allowance for credit losses of $13 million and $12 million as of March 31, 2023 and December 31, 2022, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended March 31,
	2023
Balance as of beginning of period	$	12
Increase in provision	3
Amounts written off	(3)
Recoveries	1
Balance as of end of period	$	13

Other Current Assets

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

	March 31, 2023		December 31, 2022
Prepaid expenses	$	89	$	69
Assets from price risk management activities	113		313
Margin deposits	30		116
Other current assets	$	232	$	498

Assets from price risk management activities and related unrealized gains as well as Margin deposits decreased during the three months ended March 31, 2023 due to decreases 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):             

	March 31, 2023		December 31, 2022
Electric utility plant in-service	$	12,704	$	12,421
Construction work-in-progress	411		467
Total cost	13,115		12,888
Less: accumulated depreciation and amortization	(4,504)		(4,423)
Electric utility plant, net	$	8,611	$	8,465

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $513 million and $499 million as of March 31, 2023 and December 31, 2022, respectively. Amortization expense related to intangible assets was $14 million and $15 million for the three months ended March 31, 2023 and 2022, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Battery storage agreement—On April 26, 2023, PGE entered into a battery storage purchased power agreement (PPA) that will be accounted for as a lease upon commencement. The lease is expected to commence in December 2024 and has a term of 20 years. The expected total fixed contract consideration will approximate $737 million over the lease term.

Regulatory Assets and Liabilities

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

	March 31, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	22	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			133		—			133
February 2021 ice storm and damage	12			61		10			64
Power cost adjustment mechanism	16			10		14			14
2020 Labor Day wildfire	5			26		4			27
COVID-19	12			10		—			22
Wildfire mitigation	—			31		—			28
Other	20			72		26			68
Total regulatory assets	$	65		$	481	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,145	$	—		$	1,136
Deferred income taxes	—			190		—			194
Asset retirement obligations	—			9		—			7
Price risk management	12			—		195			—
Other	34			54		39			52
Total regulatory liabilities	$	46	*	$	1,398	$	234	*	$	1,389

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

Wildfire Mitigation represents incremental costs and investments made by PGE under 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 execute a wildfire protection plan, in which reasonable costs can be recovered through the prices to 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 March 31, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $31 million and $28 million, respectively. 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, or application of a potential 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 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 which may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of those discussions was an Energy Term Sheet (Term Sheet), which

dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of both March 31, 2023 and December 31, 2022, PGE’s deferred balance was $22 million, 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 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. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. During the March 14, 2023 public meeting, Staff recommended the Commission approve PGE's filing of Advice No. 22-45 associated with the recovery of the COVID-19 deferral. On March 21, 2023, Advice No. 22-45 was approved by the Commission, allowing for amortization of deferred amounts over a two-year period, which began April 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. PGE estimated the revenue requirement for Boardman to be $14 million for the year ended December 31, 2020, an additional $66 million for the year ended December 31, 2021, and $23 million for the year ended December 31, 2022. 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, showed 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. Although still subject to OPUC review, PGE does not believe it exceeded its regulated return on equity under the earnings test for 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and states that no refund remains necessary for that year. The stipulation remains subject to OPUC approval. Review and determination of potential refund for the periods related to 2020 and 2022 remain outstanding.

In November 2022, the OPUC granted a motion by PGE to suspend the procedural schedule and directed the Company to file a status update no later than February 16, 2023. In granting the ruling the OPUC noted that it expects to resolve this matter, addressing both the 2020 and 2022 deferrals, within the first half of 2023. The status update on February 16, 2023 stated that a settlement conference had been scheduled and parties anticipated filing with the OPUC another status update, settlement agreement, or proposed procedural schedule by March 14, 2023. On March 13, 2023, PGE notified the OPUC that settlement discussions had been productive and the parties are progressing toward resolution of the matter before the end of the first half of 2023. Based on the application of an earnings test, PGE has not recorded a refund related to Boardman for 2020, 2021, or 2022. PGE believes the range of reasonably possible refund is limited to the Boardman revenue requirement for the year 2020. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could require additional refunds that would be recognized as a charge to earnings, which could be material.

Accrued Expenses and Other Current Liabilities

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

	March 31, 2023		December 31, 2022
Accrued employee compensation and benefits	$	52	$	66
Accrued taxes payable	30		29
Accrued interest payable	46		31
Accrued dividends payable	42		42
Regulatory liabilities—current	46		234
Margin deposits from wholesale counterparties	—		140
Other	105		99
Total accrued expenses and other current liabilities	$	321	$	641

The current portion of Regulatory liabilities and Margin deposits from wholesale counterparties decreased during the three months ended March 31, 2023 due to decreases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

Credit Facilities

As of March 31, 2023, PGE had a $650 million revolving credit facility scheduled to expire in September 2027. 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 March 31, 2023, PGE was in compliance with this covenant with a 54.2% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $582 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 March 31, 2023, PGE had $68 million 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 $135 million were outstanding as of March 31, 2023. 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.

Long-term Debt

On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bore interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and applicable margin of 87.5 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 1, 2023, this term loan was repaid in full with proceeds from the Equity Forward Sale Agreement described in Note 7, Shareholders’ Equity.

On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in First Mortgage Bonds (FMBs), $100 million of which were funded in full on January 13, 2023.

Defined Benefit Retirement Plan Costs

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

	Three Months Ended March 31,
	2023		2022
Service cost	$	3	$	4
Interest cost*	9		7
Expected return on plan assets*	(11)		(12)
Amortization of net actuarial loss*	—		4
Net periodic benefit cost	$	1	$	3

* 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)

3 Months Ended

Mar. 31, 2023

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE estimated the fair value of financial asset and liability instruments as of March 31, 2023 and December 31, 2022, and classified these financial instruments based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

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

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

categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.

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

	As of March 31, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	10		10		—		—		20
Corporate credit	—		11		—		—		11
Money market funds	—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	3		—		—		—		3
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		45		—		84
Natural gas	—		71		6		—		77
	$	19	$	131	$	51	$	7	$	208
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	41	$	72	$	—	$	113
Natural gas	—		50		7		—		57
	$	—	$	91	$	79	$	—	$	170

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

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

(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.

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

	As of December 31, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds	—		—		—		11		11
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	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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.

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 March 31, 2023
Electricity physical forwards	$	44	$	69	Discounted cash flow	Electricity forward price (per MWh)	$	39.21	$	245.00	$	96.46
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.81		9.36		4.02
Electricity financial futures	1		2		Discounted cash flow	Electricity forward price (per MWh)	40.00		209.00		108.12
	$	51	$	79
As of December 31, 2022
Electricity physical forwards	$	52	$	93	Discounted cash flow	Electricity forward price (per MWh)	$	35.00	$	270.00	$	101.27
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.71		24.71		4.42
Electricity financial futures	11		—		Discounted cash flow	Electricity forward price (per MWh)	54.17		143.70		104.21
	$	69	$	101

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller under the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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

	Three Months Ended March 31,
	2023		2022
Balance as of the beginning of the period	$	32	$	85
Net realized and unrealized (gains)*	(11)		(37)
Transfers from Level 3 to Level 2	7		4
Balance as of the end of the period	$	28	$	52

* 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 $5 million in net realized losses for the three months ended March 31, 2023 and $1 million in net realized gains for the three months ended March 31, 2022.

Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter.

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

As of March 31, 2023, the carrying amount of PGE’s long-term debt was $3,485 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,110 million. As of December 31, 2022, the carrying amount of PGE’s long-term debt was $3,646 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $2,984 million.

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Risk Management (Notes)

3 Months Ended

Mar. 31, 2023

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):

	March 31, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	52	$	112
Natural gas	61		201
Total current derivative assets (1)	113		313
Noncurrent assets:
Commodity contracts:
Electricity	32		44
Natural gas	16		30
Total noncurrent derivative assets (1)	48		74
Total derivative assets (2)	$	161	$	387
Current liabilities:
Commodity contracts:
Electricity	$	69	$	93
Natural gas	31		25
Total current derivative liabilities	100		118
Noncurrent liabilities:
Commodity contracts:
Electricity	44		53
Natural gas	26		22
Total noncurrent derivative liabilities	70		75
Total derivative liabilities (2)	$	170	$	193

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

(2) As of March 31, 2023 and December 31, 2022, no derivative assets or liabilities were designated as hedging instruments.

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

	March 31, 2023			December 31, 2022
Commodity contracts:
Electricity	4		MWhs	6		MWhs
Natural gas	208		Decatherms	211		Decatherms
Foreign currency	$	8	Canadian	$	10	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of March 31, 2023, gross amounts included as Price risk management liabilities subject to master netting agreements were $7 million, entirely for natural gas, for which PGE has posted no collateral. As of

December 31, 2022, gross amounts included as Price risk management liabilities subject to master netting agreements were $5 million, entirely for natural gas, for which PGE posted no collateral.

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

	Three Months Ended March 31,
	2023		2022
Commodity contracts:
Electricity	$	(35)	$	(40)
Natural Gas	132		(211)
Foreign currency exchange	—		—

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended March 31, 2023 and 2022, net losses of $206 million and net gains of $198 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2023 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2023		2024		2025		2026		2027		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	12	$	19	$	(4)	$	(2)	$	(15)	$	29
Natural gas	(18)		(2)		(4)		4		—		—		(20)
Net unrealized loss/(gain)	$	1	$	10	$	15	$	—	$	(2)	$	(15)	$	9

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2023 was $153 million, for which PGE has posted $16 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2023, the cash requirement to either post as collateral or settle the instruments immediately would have been $106 million. As of March 31, 2023, PGE had $14 million cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheets.

As of March 31, 2023, PGE received from counterparties $8 million in collateral, consisting entirely of letters of credit. 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.

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

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Earnings Per Share (Notes)

3 Months Ended

Mar. 31, 2023

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; ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the Equity Forward Sale Agreement (EFSA). See Note 7, Shareholders’ Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three months ended March 31, 2023, unvested performance-based restricted stock units and related dividend equivalent rights of 413 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 385 thousand shares excluded for the three months ended March 31, 2022.

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 March 31,
	2023	2022
Weighted-average common shares outstanding—basic	91,840	89,396
Dilutive effect of potential common shares	731	131
Weighted-average common shares outstanding—diluted	92,571	89,527

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Equity (Notes)

3 Months Ended

Mar. 31, 2023

Equity [Abstract]

Equity

SHAREHOLDERS’ EQUITY

The activity in equity during the three-month periods ended March 31, 2023 and 2022 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, 2022	89,283,353	$	1,249	$	(4)	$	1,534	$	2,779
Issuances of shares pursuant to equity-based plans	159,603	—		—		—		—
Issuances of shares pursuant to equity forward sales agreement	7,178,016	300		—		—		300
Stock-based compensation		(1)		—		—		(1)
Dividends declared ($0.4525 per share)	—	—		—		(40)		(40)
Net income	—	—		—		74		74
Balances as of March 31, 2023	96,620,972	$	1,548	$	(4)	$	1,568	$	3,112
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	—		—		—		—
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

Equity Forward Sale Agreement—In 2022, PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 10,100,000 shares of its common stock. In March 2023, the Company issued 7,178,016 shares pursuant to the EFSA and received net proceeds of $300 million.

Pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters for $43.00 per share, less an underwriting discount equal to $1.23625 per share. PGE receives proceeds from the sale of common stock when the EFSA is settled (described above), and at that time PGE records the proceeds, if any, in equity.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to October 25, 2024, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $43.00 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

PGE concluded that the EFSA was an equity instrument and that it qualified for an exception from derivative accounting because the EFSA was indexed to its own stock. PGE anticipates settling the EFSA through physical settlement on or before October 25, 2024.

At March 31, 2023, the Company could have physically settled the EFSA by delivering 4,436,984 shares to the forward counterparty in exchange for cash of $184 million.

Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of PGE’s stock during the reporting period is higher than the average forward sale price during the reporting period. As of March 31, 2023, 577,479 incremental shares were included in the calculation of diluted EPS related to the securities under the EFSA. For additional information concerning the Company’s diluted earnings per share, see Note 6, Earnings Per Share.

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Contingencies (Notes)

3 Months Ended

Mar. 31, 2023

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 that 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 was 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, 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. 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 estimated liabilities and recover incurred 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.

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 predict the eventual scope or outcome of these matters.

Colstrip-Related 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). In May 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. Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. An arbitration process has been initiated to address such business disagreements and has resulted in several legal proceedings, which, along with other matters related to Colstrip, are summarized below.

Arbitration—In March 2021, co-owner NorthWestern Corporation (NorthWestern) initiated arbitration against all other co-owners of Colstrip to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or, alternatively, 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. This arbitration process was initially stayed as a result of the bankruptcy filing of Talen’s parent company, but that stay was lifted in August 2022, by a voluntary stipulation. The arbitration has been stayed through June 16, 2023, by agreement of the parties. PGE cannot predict the ultimate outcome of the arbitration process.

Petition to compel arbitration—In April 2021, co-owners Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and PGE (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 that is described above. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Following a hearing in July 2021, Talen’s motion to transfer the case to the U.S. District Court for the District of Montana was granted. This matter is stayed, because of the bankruptcy filing of Talen’s parent company.

Challenge to constitutionality of Montana Senate Bills 265 and 266 (MSB 265 and MSB 266)—On May 4, 2021, the Petitioners filed a claim against NorthWestern and Talen (the Defendants) in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of MSB 265, which attempted to void contractual arbitration provisions within the O&O Agreement if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. 

The 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 MSB 266, which purportedly gave the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, and authority to penalize any co-owner who fails or refuses to pay the costs to maintain the plant.

The Petitioners filed motions for summary judgment on their claims and on September 29, 2022, the Magistrate Judge issued Findings and Recommendations, which were adopted in full by the Court on October 19, 2022, granting the summary judgment motions by finding that MSB 266 was unconstitutional, and MSB 265 was unconstitutional and in the alternative preempted by the Federal Arbitration Act.

Complaint to implement Montana SB 265—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 MSB 265. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. This matter is stayed, because of the bankruptcy filing of Talen’s parent company.

Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. In December 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. In August 2021, the claim was amended to add PGE as a defendant. 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. This matter was stayed for a time as a result of the bankruptcy filing of Talen’s parent company, but litigation has resumed and the parties are working through discovery issues.

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)	3 Months Ended
	Mar. 31, 2023
Guarantees [Abstract]
GUARANTEES	GUARANTEESPGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2023, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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Income tax Income tax (Notes)

3 Months Ended

Mar. 31, 2023

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 March 31,
	2023		2022
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(9.3)		(10.5)
State and local taxes, net of federal tax benefit	9.0		8.9
Flow-through depreciation and cost basis differences	1.0		0.7
Amortization of excess deferred income tax	(3.7)		(4.5)
Other	(2.1)		(0.1)
Effective tax rate	15.9	%	15.5	%

* 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 PTC generation will end at various dates through 2033.

Carryforwards

Federal tax credit carryforwards as of both March 31, 2023 and December 31, 2022 were $102 million. These credits primarily consist of PTCs, which will expire at various dates through 2043. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2023 will be realized; accordingly, no valuation allowance has been recorded. As of March 31, 2023, and December 31, 2022, PGE had no material unrecognized tax benefits.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2023

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 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)

3 Months Ended

Mar. 31, 2023

Revenue Recognition and Deferred Revenue [Abstract]

Disaggregation of Revenue [Table Text Block]

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

	Three Months Ended March 31,
	2023		2022
Retail:
Residential	$	362	$	308
Commercial	197		178
Industrial	82		69
Direct access customers	6		8
Subtotal	647		563
Alternative revenue programs, net of amortization	3		1
Other accrued revenues, net	1		—
Total retail revenues	651		564
Wholesale revenues*	88		56
Other operating revenues	9		6
Total revenues	$	748	$	626

* Wholesale revenues include $34 million and $19 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2023 and 2022, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2023

Balance Sheet Components [Abstract]

Allowance for Credit Losses [Text Block]

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

	Three Months Ended March 31,
	2023
Balance as of beginning of period	$	12
Increase in provision	3
Amounts written off	(3)
Recoveries	1
Balance as of end of period	$	13

Schedule of Other Current Assets [Table Text Block]

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

	March 31, 2023		December 31, 2022
Prepaid expenses	$	89	$	69
Assets from price risk management activities	113		313
Margin deposits	30		116
Other current assets	$	232	$	498

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

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

	March 31, 2023		December 31, 2022
Electric utility plant in-service	$	12,704	$	12,421
Construction work-in-progress	411		467
Total cost	13,115		12,888
Less: accumulated depreciation and amortization	(4,504)		(4,423)
Electric utility plant, net	$	8,611	$	8,465

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	March 31, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	22	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			133		—			133
February 2021 ice storm and damage	12			61		10			64
Power cost adjustment mechanism	16			10		14			14
2020 Labor Day wildfire	5			26		4			27
COVID-19	12			10		—			22
Wildfire mitigation	—			31		—			28
Other	20			72		26			68
Total regulatory assets	$	65		$	481	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,145	$	—		$	1,136
Deferred income taxes	—			190		—			194
Asset retirement obligations	—			9		—			7
Price risk management	12			—		195			—
Other	34			54		39			52
Total regulatory liabilities	$	46	*	$	1,398	$	234	*	$	1,389

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

Other Liabilities Disclosure [Text Block]

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

	March 31, 2023		December 31, 2022
Accrued employee compensation and benefits	$	52	$	66
Accrued taxes payable	30		29
Accrued interest payable	46		31
Accrued dividends payable	42		42
Regulatory liabilities—current	46		234
Margin deposits from wholesale counterparties	—		140
Other	105		99
Total accrued expenses and other current liabilities	$	321	$	641

Pension and Other Postretirement Benefits Disclosure [Text Block]

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

	Three Months Ended March 31,
	2023		2022
Service cost	$	3	$	4
Interest cost*	9		7
Expected return on plan assets*	(11)		(12)
Amortization of net actuarial loss*	—		4
Net periodic benefit cost	$	1	$	3

* 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)

3 Months Ended

Mar. 31, 2023

Fair Value of Financial Instruments [Abstract]

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

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

	As of March 31, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	10		10		—		—		20
Corporate credit	—		11		—		—		11
Money market funds	—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	3		—		—		—		3
Equity securities	3		—		—		—		3
Price risk management activities: (1) (4)
Electricity	—		39		45		—		84
Natural gas	—		71		6		—		77
	$	19	$	131	$	51	$	7	$	208
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	41	$	72	$	—	$	113
Natural gas	—		50		7		—		57
	$	—	$	91	$	79	$	—	$	170

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

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

(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.

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

	As of December 31, 2022
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds	—		—		—		11		11
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	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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.

Fair Value Option, Disclosures [Table Text Block]

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2023
Electricity physical forwards	$	44	$	69	Discounted cash flow	Electricity forward price (per MWh)	$	39.21	$	245.00	$	96.46
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.81		9.36		4.02
Electricity financial futures	1		2		Discounted cash flow	Electricity forward price (per MWh)	40.00		209.00		108.12
	$	51	$	79
As of December 31, 2022
Electricity physical forwards	$	52	$	93	Discounted cash flow	Electricity forward price (per MWh)	$	35.00	$	270.00	$	101.27
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Decatherm)	2.71		24.71		4.42
Electricity financial futures	11		—		Discounted cash flow	Electricity forward price (per MWh)	54.17		143.70		104.21
	$	69	$	101

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

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

	Three Months Ended March 31,
	2023		2022
Balance as of the beginning of the period	$	32	$	85
Net realized and unrealized (gains)*	(11)		(37)
Transfers from Level 3 to Level 2	7		4
Balance as of the end of the period	$	28	$	52

* 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 $5 million in net realized losses for the three months ended March 31, 2023 and $1 million in net realized gains for the three months ended March 31, 2022.

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Price Risk Management (Tables)

3 Months Ended

Mar. 31, 2023

Derivative [Line Items]

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

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

	March 31, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	52	$	112
Natural gas	61		201
Total current derivative assets (1)	113		313
Noncurrent assets:
Commodity contracts:
Electricity	32		44
Natural gas	16		30
Total noncurrent derivative assets (1)	48		74
Total derivative assets (2)	$	161	$	387
Current liabilities:
Commodity contracts:
Electricity	$	69	$	93
Natural gas	31		25
Total current derivative liabilities	100		118
Noncurrent liabilities:
Commodity contracts:
Electricity	44		53
Natural gas	26		22
Total noncurrent derivative liabilities	70		75
Total derivative liabilities (2)	$	170	$	193

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

(2) As of March 31, 2023 and December 31, 2022, no derivative assets or liabilities were designated as hedging instruments.

Schedule of Derivative Instruments [Table Text Block]

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

	March 31, 2023			December 31, 2022
Commodity contracts:
Electricity	4		MWhs	6		MWhs
Natural gas	208		Decatherms	211		Decatherms
Foreign currency	$	8	Canadian	$	10	Canadian

Derivatives Not Designated as Hedging Instruments [Table Text Block]

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

	Three Months Ended March 31,
	2023		2022
Commodity contracts:
Electricity	$	(35)	$	(40)
Natural Gas	132		(211)
Foreign currency exchange	—		—

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 March 31, 2023 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2023		2024		2025		2026		2027		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	12	$	19	$	(4)	$	(2)	$	(15)	$	29
Natural gas	(18)		(2)		(4)		4		—		—		(20)
Net unrealized loss/(gain)	$	1	$	10	$	15	$	—	$	(2)	$	(15)	$	9

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2023

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

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

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

	Three Months Ended March 31,
	2023	2022
Weighted-average common shares outstanding—basic	91,840	89,396
Dilutive effect of potential common shares	731	131
Weighted-average common shares outstanding—diluted	92,571	89,527

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Equity (Tables)

3 Months Ended

Mar. 31, 2023

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three-month periods ended March 31, 2023 and 2022 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, 2022	89,283,353	$	1,249	$	(4)	$	1,534	$	2,779
Issuances of shares pursuant to equity-based plans	159,603	—		—		—		—
Issuances of shares pursuant to equity forward sales agreement	7,178,016	300		—		—		300
Stock-based compensation		(1)		—		—		(1)
Dividends declared ($0.4525 per share)	—	—		—		(40)		(40)
Net income	—	—		—		74		74
Balances as of March 31, 2023	96,620,972	$	1,548	$	(4)	$	1,568	$	3,112
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	—		—		—		—
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

Equity Forward Sale Agreement—In 2022, PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 10,100,000 shares of its common stock. In March 2023, the Company issued 7,178,016 shares pursuant to the EFSA and received net proceeds of $300 million.

Pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters for $43.00 per share, less an underwriting discount equal to $1.23625 per share. PGE receives proceeds from the sale of common stock when the EFSA is settled (described above), and at that time PGE records the proceeds, if any, in equity.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to October 25, 2024, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $43.00 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

PGE concluded that the EFSA was an equity instrument and that it qualified for an exception from derivative accounting because the EFSA was indexed to its own stock. PGE anticipates settling the EFSA through physical settlement on or before October 25, 2024.

At March 31, 2023, the Company could have physically settled the EFSA by delivering 4,436,984 shares to the forward counterparty in exchange for cash of $184 million.

Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of PGE’s stock during the reporting period is higher than the average forward sale price during the reporting period. As of March 31, 2023, 577,479 incremental shares were included in the calculation of diluted EPS related to the securities under the EFSA. For additional information concerning the Company’s diluted earnings per share, see Note 6, Earnings Per Share.

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Income tax Income tax (Tables)

3 Months Ended

Mar. 31, 2023

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 March 31,
	2023		2022
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(9.3)		(10.5)
State and local taxes, net of federal tax benefit	9.0		8.9
Flow-through depreciation and cost basis differences	1.0		0.7
Amortization of excess deferred income tax	(3.7)		(4.5)
Other	(2.1)		(0.1)
Effective tax rate	15.9	%	15.5	%

* 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 PTC generation will end at various dates through 2033.

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Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) mi² retail_customers	Mar. 31, 2022 USD ($)
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	928
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities | $	$ (140)	$ 99

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Disaggregation of Revenue [Line Items]
Subtotal	$ 647	$ 563
Alternative revenue programs, net of amortization	3	1
Other accrued (deferred) revenues, net	1	0
Total retail revenues	651	564
Wholesale revenues	88	56
Other operating revenue	9	6
Total revenues	748	626
Gain on Derivative Instruments, Pretax	34	19
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	362	308
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	197	178
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	82	69
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 6	$ 8

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Balance Sheet Components Allowance for Credit Losses (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 12
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	3
Accounts Receivable, Allowance for Credit Loss, Writeoff	(3)
Accounts Receivable, Allowance for Credit Loss, Recovery	1
Accounts Receivable, Allowance for Credit Loss	$ 13

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Other Current Assets [Line Items]
Prepaid expenses	$ 89	$ 69
Assets from price risk management activities	113	313
Margin deposits	30	116
Other current assets	$ 232	$ 498

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 12,704	$ 12,421
Construction work-in-progress	411	467
Total cost	13,115	12,888
Less: accumulated depreciation and amortization	(4,504)	(4,423)
Electric utility plant, net	$ 8,611	$ 8,465

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 65		$ 54
Regulatory assets - noncurrent	481		473
Regulatory Liability, Current	46		234
Regulatory liabilities-noncurrent	1,398		1,389
Purchased power and fuel	304	$ 202
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	1,145		1,136
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	190		194
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0
Regulatory liabilities-noncurrent	9		7
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	0		0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	34		39
Regulatory liabilities-noncurrent	54		52
Regulatory Clause Revenues, under-recovered
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	12		195
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	22		1
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	95		95
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	21		21
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	133		133
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	20		26
Regulatory assets - noncurrent	72		68
Storm Costs
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	12		10
Regulatory assets - noncurrent	61		64
Fire
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	5		4
Regulatory assets - noncurrent	26		27
pandemic
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	12		0
Regulatory assets - noncurrent	10		22
wildfire
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0
Regulatory assets - noncurrent	31		28
Deferred Fuel Costs
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	16		14
Regulatory assets - noncurrent	$ 10		$ 14

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Accrued employee compensation and benefits	$ 52	$ 66
Accrued taxes payable	30	29
Accrued interest payable	46	31
Accrued dividends payable	42	42
Regulatory liabilities—current	46	234
Deposits, Wholesale	0	140
Other	105	99
Total accrued expenses and other current liabilities	$ 321	$ 641

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 3	$ 4
Interest cost	9	7
Expected return on plan assets	(11)	(12)
Amortization of net actuarial loss	0	4
Net periodic benefit cost	$ 1	$ 3

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Balance Sheet Components (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 13		$ 12
Unbilled Receivables, Current	115		131
Finite-Lived Intangible Assets, Accumulated Amortization	513		$ 499
Amortization of Intangible Assets	14	$ 15
Line of Credit Facility, Maximum Borrowing Capacity	$ 750
Debt Instrument, Covenant Description	65.00%
Ratio of Indebtedness to Net Capital	0.542
Line of Credit Facility, Remaining Borrowing Capacity	$ 582
Line of Credit Facility, Current Borrowing Capacity	650
Authorized Short-Term Debt	900
Purchased power and fuel	304	202
Repayments of Long-term Debt	260	0
Amount above baseline net variable power costs	13
Proceeds from failed sale-leaseback transactions	0	$ 25
Letters of Credit Outstanding, Amount	135
Tangible Asset Impairment Charges	2
Line of Credit, Current	220
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Commercial paper	$ 68

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Assets:
Cash equivalents	$ 0	$ 150
Debt securities:
Domestic government	20	19
Corporate credit	11	9
Money market funds measured at NAV (2)	7	11
Non-qualified benefit plan trust: (2)
Money market funds	3	1
Equity securities - domestic	3	3
Debt securities—domestic government	3	3
Assets from price risk management activities: (1) (3)
Electricity	84	156
Natural gas	77	231
Total	7	11
Assets, Fair Value Disclosure	208	583
Liabilities from price risk management activities: (1) (3)
Electricity	113	146
Natural gas	57	47
Total	170	193
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	0	150
Debt securities:
Domestic government	10	9
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	3	1
Equity securities - domestic	3	3
Debt securities—domestic government	3	3
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	19	166
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	10	10
Corporate credit	11	9
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	93
Natural gas	71	225
Total	131	337
Liabilities from price risk management activities: (1) (3)
Electricity	41	53
Natural gas	50	39
Total	91	92
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	45	63
Natural gas	6	6
Total	51	69
Liabilities from price risk management activities: (1) (3)
Electricity	72	93
Natural gas	7	8
Total	$ 79	$ 101

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Mar. 31, 2023	Dec. 31, 2022
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 39.21	$ 35.00
Natural gas financial swaps	2.81	2.71
Financial swaps - electricity	40.00	54.17
High [Member]
Commodity Contracts
Electricity physical forwards	245.00	270.00
Natural gas financial swaps	9.36	24.71
Financial swaps - electricity	209.00	143.70
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	96.46	101.27
Natural gas financial swaps	4.02	4.42
Financial swaps - electricity	108.12	104.21
Assets [Member]
Commodity Contracts
Electricity physical forwards	44,000,000	52,000,000
Natural gas financial swaps	6,000,000	6,000,000
Financial swaps - electricity	1,000,000	11,000,000
Total commodity contracts	51,000,000	69,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	69,000,000	93,000,000
Natural gas financial swaps	8,000,000	8,000,000
Financial swaps - electricity	2,000,000	0
Total commodity contracts	$ 79,000,000	$ 101,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 32	$ 85
Net realized and unrealized (gains)/losses	(11)	(37)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3		4
Transfers out of Level 3 to Level 2	7
Balance as of the end of the period	$ 28	$ 52

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 29		$ 31
net realized loss	5
Long-term Debt	3,485		3,646
Unamortized Debt Issuance Expense	13		13
Long-term Debt, Fair Value	3,110		$ 2,984
Net gain or loss recognized in the statement of income offset by regulatory accounting	$ (206)	$ (198)

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Current Assets, Commodity Contracts:
Electricity	$ 52	$ 112
Natural gas	61	201
Total current derivative assets	113	313
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	32	44
Commodity Contract Asset, Noncurrent, Natural Gas	16	30
Derivative Asset, Noncurrent	48	74
Total derivative assets	161	387
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	69	93
Natural gas	31	25
Total current derivative liabilities	100	118
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	44	53
Natural gas	26	22
Total noncurrent derivative liabilities	70	75
Total derivative liabilities	$ 170	$ 193

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2023 CAD ($) MWh MMBTU	Dec. 31, 2022 CAD ($) MMBTU MWh
Commodity contracts:
Electricity | MWh	4	6
Natural gas | MMBTU	208	211
Foreign currency | $	$ 8	$ 10

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Commodity contracts:
Electricity	$ (35)	$ (40)
Natural Gas	132	(211)
Foreign currency exchange	$ 0	$ 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	Mar. 31, 2023 USD ($)
Electricity [Member]
Commodity contracts:
2022	$ 19
2023	12
2024	19
2025	(4)
2026	(2)
Thereafter	(15)
Total	29
Natural Gas [Member]
Commodity contracts:
2022	18
2023	2
2024	4
2025	(4)
2026	0
Thereafter	0
Total	20
Net Unrealized Loss/(gain)[Member]
Commodity contracts:
2022	1
2023	10
2024	15
2025	0
2026	(2)
Thereafter	(15)
Total	$ 9

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ 206	$ 198
Derivative, Net Liability Position, Aggregate Fair Value	153
Collateral Already Posted, Aggregate Fair Value	16
Collateral cash requirement	106
Purchased power and fuel	304	$ 202
Deposits, Wholesale	0		$ 140
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	5
Letters of Credit Outstanding, Amount	135
Derivative Asset, Fair Value, Amount Offset Against Collateral	$ 8

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	91,840	89,396
Dilutive effect of potential common shares	731	131
Weighted Average Number of Shares Outstanding, Diluted	92,571	89,527

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	413	385

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Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Common Stock, Shares, Outstanding beginning of period	89,283,353
Issuance of shares pursuant to equity-based plans	$ 0	$ 0
Stock Issued During Period, Shares, New Issues	7,178,016
Proceeds from Issuance or Sale of Equity	$ 300
Stockholders' Equity	2,779	2,707	$ 2,707
Dividends declared	(40)	(40)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 74	60
Common Stock, Shares, Outstanding end of period	96,620,972
Stockholders' Equity	$ 3,112	2,709		$ 2,707
Common Stock, Dividends, Per Share, Declared			$ 0.4525	$ 0.4300
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	(1)
Repurchase of common stock	$ 0	$ (18)
Stock Repurchased and Retired During Period, Shares		(350,000)
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,283,353	89,410,612	89,410,612
Issuances of shares pursuant to equity-based plans	159,603	163,291
Common Stock, Shares, Outstanding end of period	96,620,972	89,223,903		89,410,612
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 0	$ 0
Proceeds from Issuance or Sale of Equity	300	0
Stockholders' Equity	1,249	1,241	$ 1,241
Dividends declared	0
Stockholders' Equity	1,548	1,236		$ 1,241
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	(1)
Repurchase of common stock		(5)
AOCI Attributable to Parent [Member]
Stockholders' Equity	(4)	(10)	(10)
Dividends declared	0
Stockholders' Equity	(4)	(10)		(10)
Retained Earnings [Member]
Stockholders' Equity	1,534	1,476	$ 1,476
Dividends declared	40	40
Stockholders' Equity	$ 1,568	1,483		$ 1,476
Repurchase of common stock		$ (13)

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Contingencies (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) party
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties | party	100
Litigation Settlement, Expense	$ 115
Loss Contingency, Estimate of Possible Loss	1,700
Loss Contingency, Damages Sought, Value	1,200
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
Environmental Remediation Expense	6
lower range of costs	1,900
upper range of costs	$ 3,500

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%
Federal tax credits	(9.30%)	(10.50%)
State and local taxes, net of federal tax benefit	9.00%	8.90%
Flow through depreciation and cost basis differences	1.00%	0.70%
Excess deferred tax amortization	(3.70%)	(4.50%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(2.10%)	(0.10%)
Effective tax rate	15.90%	15.50%

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Income tax Income tax (Details)	Mar. 31, 2023 USD ($)
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 102,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0