10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 July 20, 2023 is 101,094,514 shares.

1

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	65
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 6.	Exhibits	65
SIGNATURE		66

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
EFSA	Equity Forward Sale Agreement
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

3

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)                            

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues:
Revenues, net	$	646	$	588	$	1,391	$	1,213
Alternative revenue programs, net of amortization	2		3		5		4
Total revenues	648		591		1,396		1,217
Operating expenses:
Purchased power and fuel	220		168		524		370
Generation, transmission and distribution	101		85		194		175
Administrative and other	93		84		173		173
Depreciation and amortization	113		103		224		202
Taxes other than income taxes	40		39		83		79
Total operating expenses	567		479		1,198		999
Income from operations	81		112		198		218
Interest expense, net	41		38		85		76
Other income:
Allowance for equity funds used during construction	4		3		7		6
Miscellaneous income, net	5		—		17		—
Other income, net	9		3		24		6
Income before income tax expense	49		77		137		148
Income tax expense	10		13		24		24
Net income	39		64		113		124
Other comprehensive income	1		1		1		1
Net income and Comprehensive income	$	40	$	65	$	114	$	125
Weighted-average common shares outstanding (in thousands):
Basic	97,087		89,225		94,478		89,310
Diluted	97,630		89,371		94,950		89,449
Earnings per share—basic and diluted	$	0.39	$	0.72	$	1.19	$	1.39
See accompanying notes to condensed consolidated financial statements.

    

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)                            

	June 30, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	13	$	165
Accounts receivable, net	310		398
Inventories	108		95
Regulatory assets—current	88		54
Other current assets	157		498
Total current assets	676		1,210
Electric utility plant, net	8,841		8,465
Regulatory assets—noncurrent	593		473
Nuclear decommissioning trust	35		39
Non-qualified benefit plan trust	36		38
Other noncurrent assets	189		234
Total assets	$	10,370	$	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)                        

	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	227	$	457
Liabilities from price risk management activities—current	98		118
Short-term debt	140		—
Current portion of long-term debt	—		260
Current portion of finance lease obligation	20		20
Accrued expenses and other current liabilities	276		641
Total current liabilities	761		1,496
Long-term debt, net of current portion	3,486		3,386
Regulatory liabilities—noncurrent	1,409		1,389
Deferred income taxes	452		439
Unfunded status of pension and postretirement plans	171		170
Liabilities from price risk management activities—noncurrent	159		75
Asset retirement obligations	263		257
Non-qualified benefit plan liabilities	79		83
Finance lease obligations, net of current portion	292		294
Other noncurrent liabilities	98		91
Total liabilities	7,170		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, 2023 and December 31, 2022	—		—
Common stock, no par value, 160,000,000 shares authorized; 98,863,827 and 89,283,353 shares issued and outstanding as of June 30, 2023 and December 31, 2022, respectively	1,647		1,249
Accumulated other comprehensive loss	(3)		(4)
Retained earnings	1,556		1,534
Total shareholders’ equity	3,200		2,779
Total liabilities and shareholders’ equity	$	10,370	$	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)    

	Six Months Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	113	$	124
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	224		202
Deferred income taxes	6		9
Pension and other postretirement benefits	3		7
Allowance for equity funds used during construction	(7)		(6)
Decoupling mechanism deferrals, net of amortization	(5)		(4)
Regulatory assets	(10)		(35)
Regulatory liabilities	12		9
2020 Labor Day wildfire earnings test reserve	—		15
Other non-cash income and expenses, net	28		26
Changes in working capital:
Accounts receivable, net	82		37
Inventories	(13)		(19)
Margin deposits	90		3
Accounts payable and accrued liabilities	(233)		(55)
Margin deposits from wholesale counterparties	(135)		149
Other working capital items, net	9		6
Other, net	(21)		(17)
Net cash provided by operating activities	143		451
See accompanying notes to condensed consolidated financial statements.

7

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)        

	Six Months Ended June 30,
	2023		2022
Cash flows from investing activities:
Capital expenditures	(573)		(345)
Sales of Nuclear decommissioning trust securities	—		3
Purchases of Nuclear decommissioning trust securities	—		(3)
Proceeds from sale of properties	2		12
Other, net	(3)		(1)
Net cash used in investing activities	(574)		(334)
Cash flows from financing activities:
Proceeds from issuance of common stock	$	392	$	—
Proceeds from issuance of long-term debt	100		—
Payments on long-term debt	(260)		—
Issuance of commercial paper, net	140		—
Proceeds from Pelton/Round Butte financing arrangement	—		25
Dividends paid	(84)		(77)
Repurchase of common stock	—		(18)
Other	(9)		(8)
Net cash provided by (used in) financing activities	279		(78)
(Decrease) Increase in cash and cash equivalents	(152)		39
Cash and cash equivalents, beginning of period	165		52
Cash and cash equivalents, end of period	$	13	$	91
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	70	$	63
Cash paid for income taxes	16		16
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 operates as a cost-based, regulated electric utility with revenue requirements and customer prices determined based on the forecasted cost to serve retail customers and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). The Company participates in the wholesale market under the regulation and authority of the Federal Energy Regulatory Commission (FERC) 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. PGE also performs portfolio management and wholesale market sales services for third parties in the region. 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 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 June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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.

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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.

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Retail:
Residential	$	279	$	250	$	641	$	558
Commercial	196		168		393		346
Industrial	87		73		169		142
Direct access customers	7		9		13		17
Subtotal	569		500		1,216		1,063
Alternative revenue programs, net of amortization	2		3		5		4
Other accrued revenues, net	(4)		—		(3)		—
Total retail revenues	567		503		1,218		1,067
Wholesale revenues*	62		65		150		121
Other operating revenues	19		23		28		29
Total revenues	$	648	$	591	$	1,396	$	1,217

* Wholesale revenues include $22 million and $14 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2023 and 2022, respectively, and $56 million and $33 million for the six months ended June 30, 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 OPUC. Additionally, the

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 and records the revenue earned from energy deliveries that have not yet been billed to customers. This amount, which is classified as unbilled revenues and 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, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. 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 $117 million and $131 million of unbilled revenues as of June 30, 2023 and December 31, 2022, respectively. Accounts receivable, net includes an allowance for credit losses of $13 million and $12 million as of June 30, 2023 and December 31, 2022, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2023		2023
Balance as of beginning of period	$	13	$	12
Increase in provision	1		4
Amounts written off	(3)		(6)
Recoveries	2		3
Balance as of end of period	$	13	$	13

Other Current Assets

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

	June 30, 2023		December 31, 2022
Prepaid expenses	$	56	$	69
Assets from price risk management activities	75		313
Margin deposits	26		116
Other current assets	$	157	$	498

Assets from price risk management activities and related unrealized gains as well as Margin deposits decreased during the six months ended June 30, 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):             

	June 30, 2023		December 31, 2022
Electric utility plant in-service	$	12,868	$	12,421
Construction work-in-progress	568		467
Total cost	13,436		12,888
Less: accumulated depreciation and amortization	(4,595)		(4,423)
Electric utility plant, net	$	8,841	$	8,465

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $530 million and $499 million as of June 30, 2023 and December 31, 2022, respectively. Amortization expense related to intangible assets was $15 million and $14 million for the three months ended June 30, 2023 and 2022, respectively, and $29 million for the six months ended June 30, 2023 and 2022. 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 total fixed contract consideration is expected to be $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):

	June 30, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	23		$	136	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			134		—			133
February 2021 ice storm and damage	12			60		10			64
Power cost adjustment mechanism	16			7		14			14
2020 Labor Day wildfire	5			25		4			27
COVID-19	12			7		—			22
Wildfire mitigation	—			32		—			28
Other	20			76		26			68
Total regulatory assets	$	88		$	593	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,154	$	—		$	1,136
Deferred income taxes	—			187		—			194
Asset retirement obligations	—			10		—			7
Price risk management	—			—		195			—
Boardman Refund	4			3		—			—
Other	21			55		39			52
Total regulatory liabilities	$	25	*	$	1,409	$	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 Oregon Senate Bill (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 for recovery of operating expenses related to wildfire mitigation efforts beginning May 9, 2022. As of June 30, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation operating expenses was $32 million and $28 million, respectively. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs that exceed the amount granted in base rates.

On May 10, 2023, in Order No. 23-173, the OPUC approved an automatic adjustment clause mechanism to recover wildfire mitigation costs (capital and expense). PGE submitted its tariff filing on May 17, 2023, for new rates to take effect September 1, 2023, to recover: i) incremental expense and capital-related costs that has been deferred under OPUC Docket UM 2019 and ii) forecasted costs based on a 2024 test year (in PGE’s next general rate case it will remove collections related to wildfire mitigation costs from base rates and include within the automatic adjustment clause). This is currently undergoing prudence review by the OPUC. The OPUC’s conclusions of overall prudence could result in a portion of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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. 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’s deferral application was approved by the OPUC in October 2020 with final stipulations approved in November 2020.

As June 30, 2023 and December 31, 2022, PGE’s deferred balance was $19 million and $22 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE filed a request for amortization of deferred amounts in December 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. During a March 14, 2023 public meeting, Staff recommended the OPUC 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 OPUC, 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 included any revenue requirement related to Boardman after new customer prices took effect on May 9, 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. Based on the application of an earnings test, PGE had not previously recorded a refund related to Boardman for 2020, 2021, or 2022.

On May 30, 2023, PGE and parties submitted a second stipulation with the OPUC reflecting an agreement that resolved all matters related to 2020 and 2022 under this deferral. Parties agreed that PGE would refund $6.5 million to customers related to 2020. The refund amount, plus interest, will be amortized into customer prices over a two-year period beginning July 1, 2023. All parties agreed that there are no amounts to amortize for the 2022 deferral period. On June 5, 2023, the OPUC issued Order 23-195, which approved the stipulations.

Establishing the Boardman refund deferral resulted in an increase to regulatory liabilities with an offsetting charge to the condensed consolidated statements of income for the three months ended June 30, 2023.

Accrued Expenses and Other Current Liabilities

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

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(Unaudited)

	June 30, 2023		December 31, 2022
Accrued employee compensation and benefits	$	58	$	66
Accrued taxes payable	25		29
Accrued interest payable	33		31
Accrued dividends payable	48		42
Regulatory liabilities—current	25		234
Margin deposits from wholesale counterparties	5		140
Other	82		99
Total accrued expenses and other current liabilities	$	276	$	641

The current portion of Regulatory liabilities and Margin deposits from wholesale counterparties decreased during the six months ended June 30, 2023 due to decreases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

Credit Facilities

As of June 30, 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 June 30, 2023, PGE was in compliance with this covenant with a 54.0% debt-to-total capital ratio and had no outstanding balance on the revolving credit facility. As a result of the policy to backup commercial paper borrowings, the aggregate unused available credit capacity under the credit facility was $510 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 commercial paper that may be outstanding at the time. As of June 30, 2023, PGE had $140 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 $92 million were outstanding as of June 30, 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.

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(Unaudited)

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), the first half of which funded in 2022 and the remaining $100 million 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Service cost	$	3	$	4	$	6	$	8
Interest cost*	9		7		18		14
Expected return on plan assets*	(11)		(12)		(22)		(24)
Amortization of net actuarial loss*	—		4		—		8
Net periodic benefit cost	$	1	$	3	$	2	$	6

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

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE estimated the fair value of financial asset and liability instruments as of June 30, 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

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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.

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(Unaudited)

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

	As of June 30, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		10		—		—		10
Money market funds	—		—		—		6		6
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	2		—		—		—		2
Equity securities	2		—		—		—		2
Price risk management activities: (1) (4)
Electricity	—		29		23		—		52
Natural gas	—		43		3		—		46
	$	16	$	92	$	26	$	6	$	140
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	36	$	141	$	—	$	177
Natural gas	—		57		23		—		80
	$	—	$	93	$	164	$	—	$	257

(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 net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.

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

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

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(Unaudited)

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of June 30, 2023
Electricity physical forwards	$	22	$	140	Discounted cash flow	Electricity forward price (per MWh)	$	31.90	$	208.00	$	93.59
Natural gas financial swaps	3		23		Discounted cash flow	Natural gas forward price (per Decatherm)	2.35		9.35		3.47
Electricity financial futures	1		1		Discounted cash flow	Electricity forward price (per MWh)	57.00		206.00		97.99
	$	26	$	164
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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Balance as of the beginning of the period	$	28	$	52	$	32	$	85
Net realized and unrealized losses/(gains)*	110		(19)		99		(56)
Transfers from Level 3 to Level 2	—		2		7		6
Balance as of the end of the period	$	138	$	35	$	138	$	35

* 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 no net realized gains or losses for the three months ended June 30, 2023 and $2 million in net realized gains for the three months ended June 30, 2022. For the six-month periods ended June 30, 2023 and 2022, includes $3 million in net realized losses and $3 million in net realized gains, respectively.

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

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

As of June 30, 2023, the carrying amount of PGE’s long-term debt was $3,486 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,014 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, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. The Company 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, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. The Company may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not intend to engage in trading activities for non-retail purposes.

23

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(Unaudited)

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

	June 30, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	37	$	112
Natural gas	38		201
Total current derivative assets (1)	75		313
Noncurrent assets:
Commodity contracts:
Electricity	15		44
Natural gas	8		30
Total noncurrent derivative assets (1)	23		74
Total derivative assets (2)	$	98	$	387
Current liabilities:
Commodity contracts:
Electricity	$	59	$	93
Natural gas	39		25
Total current derivative liabilities	98		118
Noncurrent liabilities:
Commodity contracts:
Electricity	118		53
Natural gas	41		22
Total noncurrent derivative liabilities	159		75
Total derivative liabilities (2)	$	257	$	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 June 30, 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):

	June 30, 2023			December 31, 2022
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	219		Decatherms	211		Decatherms
Foreign currency	$	15	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 June 30, 2023 and December 31, 2022, gross amounts included as Price risk

24

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(Unaudited)

management liabilities subject to master netting agreements were $12 million and $5 million, respectively, entirely for natural gas, for which PGE has 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Commodity contracts:
Electricity	$	88	$	(14)	$	53	$	(54)
Natural Gas	65		(27)		197		(238)
Foreign currency exchange	—		1		—		1

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2023 and 2022, net losses of $157 million and $15 million, respectively, have been offset. Net losses of $363 million and net gains of $183 million have been offset for the six-month periods ended June 30, 2023 and 2022, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 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	$	20	$	12	$	17	$	(2)	$	(2)	$	80	$	125
Natural gas	(7)		19		9		13		—		—		34
Net unrealized loss/(gain)	$	13	$	31	$	26	$	11	$	(2)	$	80	$	159

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

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of June 30, 2023 was $244 million, for which PGE has posted $42 million in collateral, consisting of $26 million of letters of credit and $16 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2023, the cash requirement to either post as collateral or settle the instruments immediately would have been $170 million. As of June 30, 2023, PGE had $9 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.

25

PORTLAND GENERAL ELECTRIC COMPANY

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(Unaudited)

As of June 30, 2023, PGE held from counterparties $16 million in collateral, consisting of $11 million of letters of credit and $5 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.

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

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) and at the market offering program. See Note 7, Shareholders’ Equity, for additional information on the EFSA and at the market offering program and the resulting 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 and six months ended June 30, 2023, unvested performance-based restricted stock units and related dividend equivalent rights of 440 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 337 thousand shares excluded for the three and six months ended June 30, 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 June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
Weighted-average common shares outstanding—basic	97,087	89,225	94,478	89,310
Dilutive effect of potential common shares	543	146	472	139
Weighted-average common shares outstanding—diluted	97,630	89,371	94,950	89,449

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three- and six-month periods ended June 30, 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
Issuances of shares pursuant to equity-based plans	30,245	1		—		—		1
Issuances of shares pursuant to equity forward sales agreement	2,212,610	92		—		—		92
Stock-based compensation	—	6		—		—		6
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4750 per share)	—	—		—		(51)		(51)
Net income	—	—		—		39		39
Balances as of June 30, 2023	98,863,827	$	1,647	$	(3)	$	1,556	$	3,200
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
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738

27

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

At the Market Offering Program—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at the market offering programs. As of June 30, 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties and under such agreements, the Company could have physically settled by delivering 172,033 shares to the counterparty in exchange for cash of $8 million. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

Equity Forward Sale Agreement—In 2022, PGE entered into an 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. In June 2023, the Company issued 2,212,610 shares pursuant to the EFSA and received net proceeds of $92 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 June 30, 2023, the Company could have physically settled the EFSA by delivering 2,224,374 shares to the forward counterparty in exchange for cash of $92 million.

On July 12, 2023, the Company issued 2,224,374 shares pursuant to the EFSA and received net proceeds of $92 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 the three and six months ended June 30, 2023, an incremental 335,507 and 291,550 shares, respectively, 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.

28

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 8: CONTINGENCIES

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

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

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

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

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

EPA Investigation of Portland Harbor

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

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

29

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

The EPA finalized a feasibility study, along with a remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor 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 entirety of Portland Harbor is under an active engineering design phase.

PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including conclusion of remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position.

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

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. 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.

30

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 September 29, 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 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 was temporarily stayed, during the bankruptcy proceeding of Talen’s parent company.

Complaint to implement Montana Senate Bill 265 (MSB 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

31

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 was temporarily stayed, during the bankruptcy proceeding 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. 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. The Court has entered a procedural schedule that leads to a trial, which would begin November 6, 2024.

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

Westmoreland Mine Permits—Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending the decision not take effect for 365 days from the date of a final order. Both decisions may be subject to appellate review. PGE is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

Regulatory Matters

Faraday—On February 15, 2023, PGE filed with the OPUC a General Rate Case 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 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 $188 million in capital costs associated with the project to repower the original 1907 Faraday hydro facility. The upgrade project was placed into service January 31, 2023. Certain parties to the 2024 GRC proceeding have challenged the prudence of aspects of PGE’s investment in the Faraday project and have recommended rate base reductions and disallowances. The Company cannot predict the ultimate outcome of the remaining regulatory process, nor can PGE estimate a range of reasonably possible disallowance. The OPUC has significant discretion in making the final determination of the GRC that may result in the disallowance of certain costs for recovery in customer prices, which could be material to PGE’s financial position, results of operations, and cash flows. Costs directly disallowed for recovery in customer prices, if any, would be charged to expense at the time such disallowance becomes probable and reasonably estimable. 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.

32

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Other Matters

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

NOTE 9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of June 30, 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.

33

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(11.2)		(9.5)		(10.0)		(10.0)
State and local taxes, net of federal tax benefit	8.3		9.0		8.8		9.0
Flow-through depreciation and cost basis differences	(0.6)		0.6		0.5		0.6
Amortization of excess deferred income tax	(3.8)		(4.1)		(3.7)		(4.3)
Other	7.1		(0.1)		0.9		(0.1)
Effective tax rate	20.8	%	16.9	%	17.5	%	16.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s PTC generation will end at various dates through 2033.

Carryforwards

Federal tax credit carryforwards as of June 30, 2023 and December 31, 2022 were $100 million and $102 million, respectively. 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 June 30, 2023 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 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 on August 16, 2022. There was no immediate impact of the IRA to PGE’s results of operations for the three and six months ended June 30, 2023. PGE is 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.

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, events or performance, and other matters. Words or phrases such as “anticipates,” “believes,”

34

“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 United States 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 volatility in interest rates;

•changing customer expectations and choices that may reduce customer demand for PGE’s services may impact the Company’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 PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, access the wholesale energy market, or operate its generating facilities and transmission and distribution systems, and 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, the inability of which could lead to potential liability if energized systems are involved in wildfires that cause harm;

35

•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 fuel, 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 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

36

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;

•social attitudes regarding the electric utility and power industries;

•political and economic conditions;

•the impact of widespread health developments 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 current or future All-Source Request For Proposals (RFP) 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 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, manage risk, and administer its long-term wholesale contracts. 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.

Company Strategy

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

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

•Decarbonize Power—Reduce greenhouse gas (GHG) 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 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 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 235 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 either PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.

As of June 30, 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 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.

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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. 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 filed an Addendum to the 2023 CEP and IRP with the OPUC on July 7, 2023. This addendum includes a portfolio analysis refresh. As part of the CEP and IRP refresh, PGE estimates a total resource need of approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to meet the Company’s 2030 emissions reduction target. Through the 2021 All-Source RFP, PGE procured 311 MW of wind resources and 475 MW of capacity, leaving a remaining need to procure approximately 2,700 to 3,700 MW.

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.

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 initial expected 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.

•Seaside Grid—PGE entered into an agreement to construct a 200 MW Battery Energy Storage System (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 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.

•Evergreen Facility—PGE entered into an agreement to construct a 75 MW BESS in Hillsboro, Oregon. PGE will own the resource, with an investment of approximately $150 million, excluding AFUDC. The project has an estimated commercial operation date of December 31, 2024.

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The Clearwater agreements and all BESS agreements 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. 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 the NewSun proceedings or potential impact, if any.

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. PGE filed the draft 2023 All-Source RFP with the OPUC on May 19, 2023.

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. PGE strives to improve regional safety by reducing the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. As of June 30, 2023, PGE completed approximately $12 million in capital projects related to wildfire mitigation and resiliency and utility asset management in the current year, consistent with the 2023 Wildfire Mitigation Plan.

•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 coordinated through a VPP platform, distributed energy resources and flexible loads can help the Company

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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 its 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 (TE) 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.

On June 1, 2023, PGE filed with the OPUC its draft 2023 TE plan, which represents a continuation of the approach, strategy, and programmatic efforts found within PGE’s 2019 TE plan. In the 2023-2025 period covered by the 2023 TE Plan, capital expenditures are expected to be approximately $24 million, pending regulatory approval. PGE anticipates an OPUC decision of acceptance of the 2023 TE plan in the fourth quarter of 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

HB 3143—On June 25, 2023, the Oregon Legislature passed HB 3143, which, if signed by the Governor, would allow the OPUC to authorize the State’s investor-owned utilities, including PGE, to issue bonds and securitize debt for expenses associated with declared emergency events. The bill would enable PGE, after a public process and rigorous review and approval by the OPUC, to issue the highest-rated, lowest-interest bonds to pay for the unexpected costs of declared emergencies.

Federal Grants—In November 2021, the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA), which includes approximately $550 billion of new federal spending, was signed into law. 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

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customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, and regional transmission capacity constraints.

Building Resilient Infrastructure and Communities (BRIC) is a Federal Emergency Management Agency (FEMA) grant program that supports states, local communities, tribes and territories as they undertake hazard mitigation projects, reducing the risks they face from disasters and natural hazards. PGE is pursuing federal grant funding for projects under the FEMA (BRIC) program. Current areas of focus for these projects include wildfire mitigation. grid resiliency, and grid modernization.

As of June 30, 2023, PGE has submitted seven full federal grant applications. PGE cannot predict the ultimate timing and success of securing funding from federal programs.

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

•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 ITC normalization requirements on certain stand-alone storage projects;

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

◦Reestablishment of solar PTCs; which would allow PGE the opportunity to be competitive in owning solar resources in renewable RFPs;

◦Replacement of the traditional resource-specific PTCs and ITCs beginning January 1, 2025, with technology-neutral clean electricity credits, which would retain critical normalization alternatives; 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 closely monitor 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.

On June 14, 2023, the United States Treasury and the Internal Revenue Service released extensive rules addressing credit transfer eligibility and application, including but not limited to, required registration, filing, and documentation for transferors and transferees to elect and claim a credit transfer. PGE believes it has qualified credits that can be transferred and intends to monetize them in line with options available under the IRA. However, PGE cannot currently estimate the impact it may have to 2023.

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. For PGE, the baseline levels 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).

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HB 2021 requires utilities to develop a CEP for meeting the targets, concurrent with each IRP, and to develop a DSP that establishes reasonable costs for retail electricity consumers. In reviewing a CEP, the OPUC must ensure that utilities plan for equitable implementation, demonstrate continual progress, and take 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 are required to 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, PGE’s preliminary percentage of 2023 retail load served by non-emitting resources is 40 percent as of June 30, 2023.

Governor executive order—In 2020, the Governor of Oregon issued Executive Order 20-04 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, Executive Order 20-04, which remains in place until withdrawn or superseded:

•directed the OPUC to encourage electric companies to support transportation electrification infrastructure;

•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 response, in 2021, the ODEQ adopted the Climate Protection Plan, which among various provisions, included an exemption for electricity generation from the Company’s natural gas-fired resources; and

•modified the reduction goals of the State’s Clean Fuels Program and extended the program while increasing the required reduction in average carbon intensity of transportation fuels.

PGE continues to monitor activities of State agencies that have utilized Executive Order 20-04 to shape State policy or seek to implement it through their own regulatory authority.

RPS standards and other laws—In 2016, Oregon Senate Bill (SB) 1547 set a benchmark for the percentage of electricity that must come from renewable sources and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers no later than 2030.

PGE ceased coal fired operation at its Boardman generating facility (Boardman) in 2020 and continues the process of decommissioning the plant. The Company has a 20% ownership share in Colstrip Units 3 and 4 coal-fired generation plant (Colstrip) and, in response to SB 1547, PGE filed a tariff request in 2016 with the OPUC and received approval to accelerate recovery of the Company’s investment in Colstrip from 2042 to 2030.

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 (GRC) to reflect further accelerated depreciation of Colstrip 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 in Colstrip. 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 additional capacity availability 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:

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•establish RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;

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

•provide 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 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 net variable power costs (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 investments is related to continued improvement in the transmission and distribution system to meet evolving customer expectations and growing demand while also replacing aging infrastructure.

PGE is seeking recovery of operations and maintenance expenses critical for preserving 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 Annual Power Cost Update Tariff (AUT) to better address highly dynamic and volatile power market uncertainties and evolving regional fundamental drivers.

With the 2024 GRC, 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.

Settlement discussions in the 2024 GRC have been productive and PGE and parties have arrived at several agreements in principle that would settle items related to a portion of PGE’s transmission and distribution capital request, a capital structure of 50% debt and 50% equity, several core business issues, such as the treatment of the transfer and sale of PTCs, and certain NVPC matters. Parties are preparing the respective term sheets and testimony related to the partial stipulations, which the Company expects to file with the OPUC in the third quarter. Remaining unresolved issues include cost of capital, adjustments to the PCAM, and recovery of certain other capital projects.

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Among the matters that remain unresolved is PGE’s request to recover $188 million in capital costs associated with the repowering of the original 1907 Faraday hydro facility. The upgrade project was placed into service January 31, 2023. Certain parties to the 2024 GRC proceeding have challenged the prudence of aspects of PGE’s investment in the Faraday project and have recommended rate base reductions and disallowances. The Company cannot predict the ultimate outcome of the remaining regulatory process, nor can PGE estimate a range of reasonably possible disallowance. The OPUC has significant discretion in making the final determination of the GRC that may result in the disallowance of certain costs for recovery in customer prices, which could be material to PGE’s financial position, results of operations, and cash flows. Costs directly disallowed for recovery in customer prices, if any, would be charged to expense at the time such disallowance becomes probable and reasonably estimable.

Regulatory review, including approval of any related stipulations, 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’s deferral application was approved by the OPUC in October 2020 with final stipulations approved in November 2020.

As of June 30, 2023 and December 31, 2022, PGE’s deferred balance was $19 million and $22 million, respectively, comprised primarily of bad debt expense in excess of what was collected in customer prices. 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 OPUC 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 OPUC, 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 mitigate the risk of wildfire and improve resiliency to wildfire damage under SB 762, enacted in July 2021. These efforts include enhanced tree and brush clearing, hardening 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 its 2023 risk-based wildfire mitigation plan to the OPUC in December 2022 and it was approved in Order 23-221 on June 26, 2023.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. As of June 30, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $32 million and $28 million, respectively. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs that exceed the amount granted in base rates.

On May 10, 2023, in Order No. 23-173, the OPUC approved an automatic adjustment clause mechanism to recover wildfire mitigation costs (capital and expense). PGE submitted its tariff filing on May 17, 2023, for new rates to take effect September 1, 2023, to recover: i) incremental expense and capital-related costs that has been deferred under OPUC Docket UM 2019 and ii) forecasted costs based on a 2024 test year (in PGE’s next general rate case it will remove collections related to wildfire mitigation costs from base rates and include within the automatic adjustment clause). This is currently undergoing prudence review by the OPUC. The OPUC’s conclusions of overall prudence could result in a portion of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

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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 June 30, 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 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 eliminated PGE’s decoupling mechanism upon the effective date of new customer prices that resulted in May 2022. Pursuant to the 2022 GRC Order, the OPUC adopted the agreement such that deferrals would not occur after 2022, although amortization of then previously recorded deferrals is to 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, is expected to 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 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,

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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 included any revenue requirement related to Boardman after new customer prices took effect on May 9, 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. Based on the application of an earnings test, PGE had not previously recorded a refund related to Boardman for 2020, 2021, or 2022.

On May 30, 2023, PGE and parties submitted a second stipulation with the OPUC reflecting an agreement that resolved all matters related to 2020 and 2022 under this deferral. Parties agreed that PGE would refund $6.5 million to customers related to 2020. The refund amount, plus interest, will be amortized over a two-year period beginning July 1, 2023. All parties agreed that there are no amounts to amortize for the 2022 deferral period. On June 5, 2023, the OPUC issued Order 23-195, which approved the stipulations.

Establishing the Boardman refund deferral resulted in an increase to regulatory liabilities with an offsetting charge to the condensed consolidated statements of income for the three months ended June 30, 2023.

Renewable recovery framework—As previously authorized by the OPUC, the RAC is a primary method available to recover costs associated with renewable resources. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a GRC. Although no significant filings have been made under the RAC during 2023, the Company expects to submit a RAC filing for the Clearwater Wind Development before the end of 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 standalone 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,

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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.

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

	Three Months Ended June 30,		% Increase (Decrease) in Energy Deliveries		Six Months Ended June 30,		% Increase (Decrease) in Energy Deliveries
	2023	2022			2023	2022
Energy deliveries (MWhs in thousands):
Retail:
Residential	1,730	1,724	—	%	4,057	3,940	3	%
Commercial	1,595	1,552	3	%	3,252	3,186	2	%
Industrial	1,140	998	14	%	2,211	1,972	12	%
Subtotal	4,465	4,274	4	%	9,520	9,098	5	%
Direct access:
Commercial	154	133	16	%	283	264	7	%
Industrial	430	441	(2)	%	866	854	1	%
Subtotal	584	574	2	%	1,149	1,118	3	%
Total retail	5,049	4,848	4	%	10,669	10,216	4	%
Wholesale	1,453	1,425	2	%	2,849	2,932	(3)	%
Total	6,502	6,273	4	%	13,518	13,148	3	%

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Average number of retail customers:
Residential	814,419	88	%	809,002	88	%	814,187	88	%	807,777	88	%
Commercial	112,190	12		112,090	12		112,333	12		111,879	12
Industrial	196	—		193	—		195	—		192	—
Direct access	539	—		553	—		541	—		552	—
Total	927,344	100	%	921,838	100	%	927,256	100	%	920,400	100	%

Total retail energy deliveries for the six months ended June 30, 2023 increased 4% compared with the six months ended June 30, 2022, driven by continued growth in demand from the industrial customer class.

The industrial class continues to show growth in energy deliveries, up 14% in the three months ended June 30 compared to the same period in 2022, due primarily to ongoing strength in the high-tech and digital services sectors. The impact of weather on Total Retail deliveries 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. In the three-month

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period ended June 30, 2023, weather again increased deliveries, as a greater number of cooling degree-days more than offset the decline in heating degree-days, compared to the same three months of 2022.

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The following table indicates the number of heating and cooling degree-days for the three and six months ended June 30, 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					Cooling Degree-days
	2023		2022		Avg.	2023		2022		Avg.
First Quarter	1,927		1,761		1,840	—		—		—
April	404		454		371	12		—		2
May	105		242		185	87		—		23
June	45		65		73	96		75		76
Second Quarter	554		761		629	195		75		101
Year-to-date	2,481		2,522		2,469	195		75		101
Increase/(decrease) from the 15-year average	—	%	2	%		93	%	(26)	%

After adjusting for the effects of weather, total retail energy deliveries for the six months ended June 30, 2023 increased 2.4% compared to the same period of 2022. The increase reflects 8.3% higher industrial delivery volumes, commercial delivery volumes that were up 1.0%, and are partially offset by 0.7% lower residential deliveries when compared to the prior year. Residential weather-adjusted deliveries saw average usage per customer 1.5% lower during the first six months of 2023 compared with 2022, while the average number of residential customers was 0.8% 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 six months of 2023 would have been to these customers.

In 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 17% 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 11% of PGE’s total retail energy deliveries for the first six 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.

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The following table provides information regarding the performance of the Company’s generating resources for the six months ended June 30, 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	80	%	84	%	93	%	78	%	45	%	33	%
Coal (3)	89		83		93		91		10		10
Wind (4)	98		74		97		80		11		9
Hydro	91		96		65		81		7		6

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

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

(3)Plant availability reflects Colstrip, which PGE does not operate.

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

Energy received from PGE-owned and jointly-owned thermal plants during the six months ended June 30, 2023 compared to 2022 increased 32%. 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, 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 23% during the six months ended June 30, 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 30% while energy generated by the Company-owned facilities increased 18% in the six months ended June 30, 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 15% during the six months ended June 30, 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

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following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for the six months ended June 30, 2023 and 2022, respectively:

•For the six months ended June 30, 2023, actual NVPC was $19 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 six months ended June 30, 2022, actual NVPC was $32 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.

Results of Operations

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

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

	Three Months Ended June 30,				% Increase (Decrease)		Six Months Ended June 30,				% Increase (Decrease)
	2023		2022				2023		2022
Total revenues	$	648	$	591	10	%	$	1,396	$	1,217	15	%
Operating expenses:
Purchased power and fuel	220		168		31		524		370		42
Generation, transmission and distribution	101		85		19		194		175		11
Administrative and other	93		84		11		173		173		—
Depreciation and amortization	113		103		10		224		202		11
Taxes other than income taxes	40		39		3		83		79		5
Total operating expenses	567		479		18		1,198		999		20
Income from operations	81		112		(28)		198		218		(9)
Interest expense, net*	41		38		8		85		76		12
Other income:
Allowance for equity funds used during construction	4		3		33		7		6		17
Miscellaneous income, net	5		—		—		17		—		—
Other income, net	9		3		200		24		6		300
Income before income tax expense	49		77		(36)		137		148		(7)
Income tax expense	10		13		(23)		24		24		—
Net income	39		64		(39)		113		124		(9)
Other comprehensive income	1		1		—		1		1		—
Net income and Comprehensive income	$	40	$	65	(38)	%	$	114	$	125	(9)	%

* Includes an allowance for borrowed funds used during construction of $3 million and $1 million for the three months ended June 30, 2023 and 2022, respectively, and $5 million and $3 million for the six months ended June 30, 2023 and 2022, respectively.

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Net income for the three months ended June 30, 2023 declined compared to the three months ended June 30, 2022. Total Revenues were higher, although increases in various Operating expenses also occurred. 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 4% increase in total retail energy deliveries over the prior year quarter. Total operating expenses increased compared to the prior year, reflecting higher Purchased power and fuel expense, more run hours at PGE’s generation facilities, and increased bad debt expense that is partially attributable to amortization of the Covid-19 deferral, which began in 2023 and is offset in revenues. An increase in Depreciation and amortization expense resulted from higher depreciable asset balances and the accelerated depreciation of Colstrip, which is offset in retail revenues, and was approved by the OPUC in the Company’s 2022 GRC. 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.

Net income for the six months ended June 30, 2023 was slightly lower than during the same period of 2022. Retail revenues increased due to both higher prices and a 4% increase in Total Retail deliveries. In 2023, increases in Retail revenues reflect the increase in customer prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT, which were anticipated to be offset by higher power costs. The impact of higher natural gas and electricity prices coupled with increased customer demand also drove Purchased power and fuel expense up. In 2022, Operating expenses reflect the additional charges that resulted pursuant to the earnings tests outlined in OPUC Order 22-129 related to prior deferrals.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2023				2022				2023				2022
Retail:
Residential	$	279	44	%	$	250	42	%	$	641	46	%	$	558	46	%
Commercial	196		30		168		28		393		28		346		29
Industrial	87		13		73		12		169		12		142		12
Subtotal	562		87		491		82		1,203		86		1,046		87
Direct access:
Commercial	2		—		3		1		4		—		6		—
Industrial	5		1		6		1		9		1		11		1
Subtotal	7		1		9		2		13		1		17		1
Subtotal Retail	569		88		500		84		1,216		87		1,063		88
Alternative revenue programs, net of amortization	2		—		3		1		5		—		4		—
Other accrued revenues, net	(4)		(1)		—		—		(3)		—		—		—
Total retail revenues	567		87		503		85		1,218		87		1,067		88
Wholesale revenues	62		10		65		11		150		11		121		10
Other operating revenues	19		3		23		4		28		2		29		2
Total revenues	$	648	100	%	$	591	100	%	$	1,396	100	%	$	1,217	100	%

Total retail revenues—The following items contributed to the increase in Total retail revenues for the three and six months ended June 30, 2023 compared to the same periods in 2022 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2022	$	503	$	1,067
Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)	32		67
Retail energy deliveries driven by customer load growth	16		42
Average price of energy deliveries due primarily to customer price increases and the relative mix of deliveries among customer classes	2		6
Colstrip depreciation life adjustment	2		8
Wildfire mitigation revenue (offset in Generation, transmission and distribution)	2		8
Recovery of deferrals for 2020 Wildfire and 2021 ice storm	6		11
Boardman settlement refund	(7)		(7)
PCAM collection, offset in Purchased power and fuel expense	4		7
Combination of various supplemental tariffs and adjustments	7		9
June 30, 2023	$	567	$	1,218
Change in Total retail revenues	$	64	$	151

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 June 30, 2023, Wholesale revenues decreased $3 million, or 5%, from the three months ended June 30, 2022 as a $4 million decrease from a 7% decline in average wholesale sales price was partially offset by a $1 million increase due to a 2% increase in sales volumes.

Wholesale revenues for the six months ended June 30, 2023 increased $29 million, or 24%, from the six months ended June 30, 2022, as the average wholesale sales price was up 27%, contributing $32 million toward the increase. Partially offsetting the increase was a 3% decline in sales volumes, which reduced revenues by $3 million. The higher sales prices have resulted from several factors that have contributed to overall higher market prices during 2023, including reduced hydro generation in the region, the economic recovery, strong demand, ongoing capacity limitations in the region, and the ongoing impact on natural gas prices resulting from global macroeconomic factors impacting the energy commodity markets.

Other operating revenues decreased $4 million for the three months ended June 30, 2023 compared with the same period in 2022. Market conditions resulted in the Company selling excess natural gas at a greater gain in the three months ended June 30, 2022 than in the comparable period of 2023.

In the six months ended June 30, 2023, Other operating revenues decreased $1 million compared to the same period of 2022 as market conditions allowed the Company to sell excess natural gas at a greater gain in 2022 than in 2023.

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

The following items contributed to the change in Purchased power and fuel for the three and six months ended June 30, 2023 compared to the same periods in 2022 (dollars in millions, except for average variable power cost per Megawatt hour (MWh)):

	Three Months Ended		Six Months Ended
June 30, 2022	$	168	$	370
Average variable power cost per MWh	67		185
Total system load	(19)		(38)
2021 PCAM deferral amortization	4		7
June 30, 2023	220		524
Change in Purchased power and fuel	$	52	$	154
Average variable power cost per MWh:
June 30, 2022	$	28.40	$	29.43
June 30, 2023	$	35.19	$	40.01
Total system load (MWhs in thousands):
June 30, 2022	5,946		12,594
June 30, 2023	6,138		12,922

For the three months ended June 30, 2023, the $67 million increase related to the change in average variable power cost per MWh was driven by a 21% increase in the average cost of purchased power and a 179% increase in the average cost for the Company’s own generation, driven primarily by price risk management activity. The $19 million decrease resulting from the overall mix of purchased power and generation used to meet total system load

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was primarily due to a 16% decrease in deliveries of energy obtained from purchased power, offset by a 35% increase in the Company’s own generation.

For the six months ended June 30, 2023, the $185 million increase related to the change in average variable power cost per MWh was driven by a 45% increase in the average cost of purchased power and an 88% increase in the average cost for the Company’s own generation, driven primarily by higher natural gas costs. The $38 million decrease related to total system load was primarily due to a 19% decrease in deliveries of energy obtained from purchased power, offset by a 29% increase in the Company’s own generation.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	1,624	26	%	1,086	18	%	4,520	35	%	3,235	26	%
Coal	432	7		356	6		1,028	8		966	8
Total thermal	2,056	33		1,442	24		5,548	43		4,201	34
Hydro	374	6		293	5		669	5		566	4
Wind	602	10		516	9		1,083	8		908	7
Total generation	3,032	49		2,251	38		7,300	56		5,675	45
Purchased power:
Hydro	1,412	23		2,002	33		2,492	19		3,564	27
Wind	244	4		250	4		476	4		445	4
Solar	394	6		216	4		539	4		329	3
Natural Gas	—	—		—	—		11	—		2	—
Waste, Wood, and Landfill Gas	38	1		42	1		81	1		79	1
Source not specified	1,018	17		1,185	20		2,023	16		2,500	20
Total purchased power	3,106	51		3,695	62		5,622	44		6,919	55
Total system load	6,138	100	%	5,946	100	%	12,922	100	%	12,594	100	%
Less: wholesale sales	(1,453)			(1,425)			(2,849)			(2,932)
Retail load requirement	4,685			4,521			10,073			9,662

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
Sources of energy (MWhs in thousands):
PURPA purchased power:
Hydro	11	8	19	14
Wind	8	8	14	13
Solar	201	178	303	282
Waste, Wood, and Landfill Gas	30	24	58	45
Total	250	218	394	354

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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	83	%	107	%
Mid-Columbia River at Grand Coulee, Washington	78		110
Clackamas River at Estacada, Oregon	100		139
Deschutes River at Moody, Oregon	100		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.

Actual NVPC for the three and six months ended June 30, 2023 increased compared to the same periods in 2022 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2022	$	103	$	249
Purchased power and fuel expense	48		147
Wholesale revenues	3		(29)
2021 PCAM deferral amortization	$	4	7
June 30, 2023	$	158	$	374
Change in NVPC	$	55	$	125

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

For the three months ended June 30, 2023 and 2022, actual NVPC was $5 million above and $23 million below baseline NVPC, respectively. For the six months ended June 30, 2023 and 2022, actual NVPC was $19 million above and $32 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.

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Generation, transmission and distribution increased as follows for the three and six months ended June 30, 2023 compared to the same periods in 2022 (in millions):

	Three Months Ended		Six Months Ended
June 30, 2022	$	85	$	175
Generating facility expenses driven by increased run hours and major maintenance activities	8		12
Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses	4		10
Amortizations of previously deferred 2020 wildfire and 2021 ice storm costs	4		11
Service restoration and storm response costs	(3)		(3)
Release of deferred amounts pursuant to earnings test in 2022	—		(16)
Miscellaneous expenses	3		5
June 30, 2023	$	101	$	194
Change in Generation, transmission and distribution	$	16	$	19

Administrative and other increased $9 million for the three months ended June 30, 2023 and remained flat for the six months ended June 30, 2023 compared to the same periods in 2022 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2022	$	84	$	173
Professional services	—		(3)
Employee compensation and benefits	1		(3)
Bad debt expense	6		4
Miscellaneous expenses	2		2
June 30, 2023	$	93	$	173
Change in Administrative and other	$	9	$	—

Depreciation and amortization expense increased $10 million for three months ended June 30, 2023 compared to the same periods in 2022. The increase was primarily due to higher utility plant balances, accelerated depreciation of Colstrip as approved by the OPUC’s 2022 GRC Order and commenced in May 2022, and regulatory amortizations. The $22 million increase for the six months ended June 30, 2023, compared to the same period in 2022, was driven by accelerated depreciation of Colstrip, regulatory amortizations and deferral activity, and higher plant in-service balances resulting from capital additions.

Taxes other than income taxes increased $1 million and $4 million, respectively, in the three and six months ended June 30, 2023, compared to the same periods in 2022. The increases were driven by higher property taxes and franchise fees.

Interest expense, net increased $3 million and $9 million, respectively, in the three and six months ended June 30, 2023 compared to the same periods in 2022 primarily due to higher long-term debt and commercial paper balances.

Other income, net increased $6 million and $18 million for the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022. The three-month increase was primarily driven by $4 million in favorable market changes on the non-qualified benefit trust. The six-month increase was primarily driven by $10 million in favorable market changes on the non-qualified benefit trust as well as the recognition of $5 million of

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previously deferred equity interest income in conjunction with amortization of regulatory deferrals that began in 2023.

Income tax expense decreased $3 million for the three months ended June 30, 2023, compared to the same period in 2022, driven by lower pre-tax income. For the six months ended June 30, 2023, income tax expense was comparable to the same period of 2022.

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.

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

	Six Months Ended June 30,
	2023		2022
Cash and cash equivalents, beginning of period	$	165	$	52
Net cash provided by (used in):
Operating activities	143		451
Investing activities	(574)		(334)
Financing activities	279		(78)
(Decrease) increase in cash and cash equivalents	(152)		39
Cash and cash equivalents, end of period	$	13	$	91

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Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the six months ended June 30, 2023 compared with the six months ended June 30, 2022 (in millions):

	Increase/ (Decrease)
Net income	$	(11)
Accounts receivable and Unbilled revenue	45
Margin deposits activity	(197)
Accounts payable	(178)
Regulatory deferral activity	28
Depreciation and amortization	22
Other miscellaneous changes	(17)
Net change in cash flow from operations	$	(308)

For the six months ended June 30, 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 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 $525 million to $575 million.

Cash Flows from Investing Activities—Net cash used in investing activities for the six months ended June 30, 2023 increased $240 million when compared with the six months ended June 30, 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 $228 million, and $10 million related to proceeds from the sale of property.

Excluding AFUDC, the Company plans to make capital expenditures of $1.5 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 the at the market offering program or the EFSA. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—During the six months ended June 30, 2023, net cash provided by financing activities was primarily the result of $392 million in proceeds from the issuance of common stock pursuant to the EFSA, funding of $100 million in First Mortgage Bonds (FMBs), and $140 million due to the issuance of commercial paper, partially offset by a $260 million repayment of a term loan and payment of $84 million of dividends.

61

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)	$	945	$	810	$	800	$	800	$	800
Clearwater Wind project	415		—		—		—		—
BESS projects	115		240		155		—		—
Total capital expenditures(2)	$	1,475	$	1,050	$	955	$	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, credit ratings, 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 $525 million to $575 million, and issuances of long-term debt securities of up to $600 million. PGE plans to fund any shortfall 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.

Short-term Debt. Pursuant to an order issued by the FERC in January 2022, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2024. The following table shows available liquidity as of June 30, 2023 (in millions):

	As of June 30, 2023
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	650	$	140	$	510
Letters of credit (2)	220		92		128
Total credit	$	870	$	232	$	638
Cash and cash equivalents					13
Total liquidity					$	651

(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.

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As of June 30, 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. As of June 30, 2023, PGE had no outstanding balance on the revolving credit facility.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of June 30, 2023, PGE had $140 million of commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $510 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.

Long-term Debt. As of June 30, 2023, PGE’s total long-term debt outstanding, net of $13 million of unamortized debt expense, was $3,486 million.

In November 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 bear interest at an annual rate of 5.47%; and

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

The 2029 and 2033 series 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.

Equity—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at the market offering programs. As of June 30, 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties and under such agreements, the Company could have physically settled by delivering 172,033 shares to the counterparty in exchange for cash of $8 million. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

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. In June 2023, the Company issued 2,212,610 shares pursuant to the EFSA and received net proceeds of $92 million.

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As of June 30, 2023, the Company could have physically settled the EFSA by delivering 2,224,374 shares of PGE common stock to the forward counterparty in exchange for cash of $92 million. On July 12, 2023, the Company issued 2,224,374 shares pursuant to the EFSA and received net proceeds of $92 million. For additional information on the EFSA, see Note 7, Shareholders’ Equity, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

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 46.9% and 43.3% as of June 30, 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 June 30, 2023, PGE had posted $51 million of collateral with these counterparties, consisting of $25 million in cash and $26 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of June 30, 2023, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $22 million, and decreases to $16 million by December 31, 2023. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $93 million and decreases to $88 million by December 31, 2023 and to $65 million by December 31, 2024.

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

The indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on June 30, 2023, under the most restrictive issuance test in the Indenture, the Company could have issued up to $814 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

64

property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of June 30, 2023, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 54.0%.

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 June 30, 2023, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

In April 2023, PGE implemented a major upgrade to our customer information system that stores customer data and processes metering, billing and payment transactions. This system implementation improves the efficiency of PGE’s retail billing processes and resulted in a material change in PGE’s internal control over financial reporting. Other than PGE’s upgraded customer information system, there were no changes in PGE’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

There have been no material changes to PGE’s risk factors set forth in 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.

65

Item 6. Exhibits.

Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed July 28, 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.

SIGNATURE

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

		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)
Date:	July 27, 2023	By:	/s/ Joseph R. Trpik
			Joseph R. Trpik
			Senior Vice President, Finance and Chief Financial Officer
			(duly authorized officer and principal financial officer)

66

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Joseph R. Trpik, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	July 27, 2023	By:	/s/ Joseph R. Trpik
			Joseph R. Trpik
			Senior Vice President, Finance and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

We, Maria M. Pope, President and Chief Executive Officer, and Joseph R. Trpik, Senior Vice President, Finance and Chief Financial Officer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2023, as filed with the Securities and Exchange Commission on July 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/ Joseph R. Trpik
Maria M. Pope		Joseph R. Trpik
President and Chief Executive Officer		Senior Vice President, Finance and Chief Financial Officer
Date:	July 27, 2023	Date:	July 27, 2023

XML

Cover Page - shares	6 Months Ended
	Jun. 30, 2023	Jul. 20, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 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		101,094,514
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Revenue, net	$ 646	$ 588	$ 1,391	$ 1,213
Alternative revenue programs, net of amortization	2	3	5	4
Total revenues	648	591	1,396	1,217
Operating expenses:
Purchased power and fuel	220	168	524	370
Generation, transmission and distribution	101	85	194	175
Administrative and other	93	84	173	173
Depreciation and amortization	113	103	224	202
Taxes other than income taxes	40	39	83	79
Total operating expenses	567	479	1,198	999
Income from operations	81	112	198	218
Interest expense, net	41	38	85	76
Other income:
Allowance for equity funds used during construction	4	3	7	6
Miscellaneous income (loss), net	5	0	17	0
Other income, net	9	3	24	6
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	49	77	137	148
Income tax expense	10	13	24	24
Net income	39	64	113	124
Other comprehensive Income	1	1	1	1
Comprehensive Income	$ 40	$ 65	$ 114	$ 125
Weighted-average common shares outstanding (in thousands):
Basic	97,087	89,225	94,478	89,310
Diluted	97,630	89,371	94,950	89,449
Diluted	$ 0.39	$ 0.72	$ 1.19	$ 1.39

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Current assets:
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 13	$ 165
Accounts receivable, net	310	398
Inventories	108	95
Regulatory assets - current	88	54
Other current assets	157	498
Total current assets	676	1,210
Electric utility plant, net	8,841	8,465
Regulatory assets - noncurrent	593	473
Nuclear decommissioning trust	35	39
Non-qualified benefit plan trust	36	38
Other noncurrent assets	189	234
Total assets	10,370	10,459
Current liabilities:
Accounts payable	227	457
Liabilities from price risk mangement activities - current	98	118
Short-term debt	140	0
Current portion of long-term debt	0	260
Current portion of finance lease obligation	20	20
Accrued expenses and other current liabilities	276	641
Total current liabilities	761	1,496
Long-term debt, net of current portion	3,486	3,386
Regulatory liabilities-noncurrent	1,409	1,389
Deferred income taxes	452	439
Unfunded status of pension and psotretirement plans	171	170
Liabilities from price risk management activities-noncurrent	159	75
Asset retirement obligations	263	257
Non-qualified benefit plan liabilities	79	83
Finance lease obligations, net of current portion	292	294
Other noncurrent liabilities	98	91
Total liabilities	7,170	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	1,647	1,249
Accumulated other comprehensive loss	(3)	(4)
Retained earnings	1,556	1,534
Total shareholders' equity	3,200	2,779
Total liabilities and shareholders' equity	$ 10,370	$ 10,459

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 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	98,863,827	89,283,353
Common stock, shares outstanding	98,863,827	89,283,353

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022
Cash flows from operating activities:
Net income	$ 113	$ 124
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	224	202
Deferred income taxes	6	9
Pension and other postretirement benefits	3	7
Allowance for equity funds used during construction	(7)	(6)
Decoupling mechanism deferrals, net of amortization	(5)	(4)
2020 Labor Day wildfire earnings test reserve	0	15
Other non-cash income and expenses, net	28	26
Changes in working capital:
Decrease in accounts receivable, net	82	37
(Increase) in inventories	(13)	(19)
(Increase)/decrease in margin deposits	90	3
(Decrease) in accounts payable and accrued liabilities	(233)	(55)
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(135)	149
Other working capital items, net	9	6
Other, net	(21)	(17)
Net cash provided by operating activities	143	451
Cash flows from investing activities:
Capital expenditures	(573)	(345)
Sales of Nuclear decommissioning trust securities	0	3
Purchases of Nuclear decommissioning trust securities	0	(3)
Proceeds from Sale of Property, Plant, and Equipment	2	12
Other, net	(3)	(1)
Net cash used in investing activities	(574)	(334)
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	140	0
Proceeds from failed sale-leaseback transactions	0	25
Dividends paid	(84)	(77)
Repurchase of common stock	0	(18)
Other	(9)	(8)
Net cash provided by (used in) financing activities	279	(78)
Increase (Decrease) in cash and cash equivalents	(152)	39
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	13	91
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	70	63
Cash paid for income taxes, net	16	16
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	0	29
Proceeds from Issuance or Sale of Equity	392
Increase (Decrease) in Other Regulatory Assets	(10)	(35)
Increase (Decrease) in Regulatory Liabilities	$ 12	9
Common Stock Including Additional Paid in Capital [Member]
Supplemental cash flow information is as follows:
Proceeds from Issuance or Sale of Equity		$ 0

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Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 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 operates as a cost-based, regulated electric utility with revenue requirements and customer prices determined based on the forecasted cost to serve retail customers and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). The Company participates in the wholesale market under the regulation and authority of the Federal Energy Regulatory Commission (FERC) 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. PGE also performs portfolio management and wholesale market sales services for third parties in the region. 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 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 June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Retail:
Residential	$	279	$	250	$	641	$	558
Commercial	196		168		393		346
Industrial	87		73		169		142
Direct access customers	7		9		13		17
Subtotal	569		500		1,216		1,063
Alternative revenue programs, net of amortization	2		3		5		4
Other accrued revenues, net	(4)		—		(3)		—
Total retail revenues	567		503		1,218		1,067
Wholesale revenues*	62		65		150		121
Other operating revenues	19		23		28		29
Total revenues	$	648	$	591	$	1,396	$	1,217

* Wholesale revenues include $22 million and $14 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2023 and 2022, respectively, and $56 million and $33 million for the six months ended June 30, 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 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 and records the revenue earned from energy deliveries that have not yet been billed to customers. This amount, which is classified as unbilled revenues and 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, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

Arrangements with Multiple Performance Obligations

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

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Balance Sheet Components (Notes)

6 Months Ended

Jun. 30, 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 $117 million and $131 million of unbilled revenues as of June 30, 2023 and December 31, 2022, respectively. Accounts receivable, net includes an allowance for credit losses of $13 million and $12 million as of June 30, 2023 and December 31, 2022, respectively. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30,		Six Months Ended June 30,
	2023		2023
Balance as of beginning of period	$	13	$	12
Increase in provision	1		4
Amounts written off	(3)		(6)
Recoveries	2		3
Balance as of end of period	$	13	$	13

Other Current Assets

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

	June 30, 2023		December 31, 2022
Prepaid expenses	$	56	$	69
Assets from price risk management activities	75		313
Margin deposits	26		116
Other current assets	$	157	$	498

Assets from price risk management activities and related unrealized gains as well as Margin deposits decreased during the six months ended June 30, 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):             

	June 30, 2023		December 31, 2022
Electric utility plant in-service	$	12,868	$	12,421
Construction work-in-progress	568		467
Total cost	13,436		12,888
Less: accumulated depreciation and amortization	(4,595)		(4,423)
Electric utility plant, net	$	8,841	$	8,465

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $530 million and $499 million as of June 30, 2023 and December 31, 2022, respectively. Amortization expense related to intangible assets was $15 million and $14 million for the three months ended June 30, 2023 and 2022, respectively, and $29 million for the six months ended June 30, 2023 and 2022. 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 total fixed contract consideration is expected to be $737 million over the lease term.

Regulatory Assets and Liabilities

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

	June 30, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	23		$	136	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			134		—			133
February 2021 ice storm and damage	12			60		10			64
Power cost adjustment mechanism	16			7		14			14
2020 Labor Day wildfire	5			25		4			27
COVID-19	12			7		—			22
Wildfire mitigation	—			32		—			28
Other	20			76		26			68
Total regulatory assets	$	88		$	593	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,154	$	—		$	1,136
Deferred income taxes	—			187		—			194
Asset retirement obligations	—			10		—			7
Price risk management	—			—		195			—
Boardman Refund	4			3		—			—
Other	21			55		39			52
Total regulatory liabilities	$	25	*	$	1,409	$	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 Oregon Senate Bill (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 for recovery of operating expenses related to wildfire mitigation efforts beginning May 9, 2022. As of June 30, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation operating expenses was $32 million and $28 million, respectively. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs that exceed the amount granted in base rates.

On May 10, 2023, in Order No. 23-173, the OPUC approved an automatic adjustment clause mechanism to recover wildfire mitigation costs (capital and expense). PGE submitted its tariff filing on May 17, 2023, for new rates to take effect September 1, 2023, to recover: i) incremental expense and capital-related costs that has been deferred under OPUC Docket UM 2019 and ii) forecasted costs based on a 2024 test year (in PGE’s next general rate case it will remove collections related to wildfire mitigation costs from base rates and include within the automatic adjustment clause). This is currently undergoing prudence review by the OPUC. The OPUC’s conclusions of overall prudence could result in a portion 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. 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’s deferral application was approved by the OPUC in October 2020 with final stipulations approved in November 2020.

As June 30, 2023 and December 31, 2022, PGE’s deferred balance was $19 million and $22 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE filed a request for amortization of deferred amounts in December 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. During a March 14, 2023 public meeting, Staff recommended the OPUC 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 OPUC, 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 included any revenue requirement related to Boardman after new customer prices took effect on May 9, 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. Based on the application of an earnings test, PGE had not previously recorded a refund related to Boardman for 2020, 2021, or 2022.

On May 30, 2023, PGE and parties submitted a second stipulation with the OPUC reflecting an agreement that resolved all matters related to 2020 and 2022 under this deferral. Parties agreed that PGE would refund $6.5 million to customers related to 2020. The refund amount, plus interest, will be amortized into customer prices over a two-year period beginning July 1, 2023. All parties agreed that there are no amounts to amortize for the 2022 deferral period. On June 5, 2023, the OPUC issued Order 23-195, which approved the stipulations.

Establishing the Boardman refund deferral resulted in an increase to regulatory liabilities with an offsetting charge to the condensed consolidated statements of income for the three months ended June 30, 2023.

Accrued Expenses and Other Current Liabilities

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

	June 30, 2023		December 31, 2022
Accrued employee compensation and benefits	$	58	$	66
Accrued taxes payable	25		29
Accrued interest payable	33		31
Accrued dividends payable	48		42
Regulatory liabilities—current	25		234
Margin deposits from wholesale counterparties	5		140
Other	82		99
Total accrued expenses and other current liabilities	$	276	$	641

The current portion of Regulatory liabilities and Margin deposits from wholesale counterparties decreased during the six months ended June 30, 2023 due to decreases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management.

Credit Facilities

As of June 30, 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 June 30, 2023, PGE was in compliance with this covenant with a 54.0% debt-to-total capital ratio and had no outstanding balance on the revolving credit facility. As a result of the policy to backup commercial paper borrowings, the aggregate unused available credit capacity under the credit facility was $510 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 commercial paper that may be outstanding at the time. As of June 30, 2023, PGE had $140 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 $92 million were outstanding as of June 30, 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), the first half of which funded in 2022 and the remaining $100 million 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Service cost	$	3	$	4	$	6	$	8
Interest cost*	9		7		18		14
Expected return on plan assets*	(11)		(12)		(22)		(24)
Amortization of net actuarial loss*	—		4		—		8
Net periodic benefit cost	$	1	$	3	$	2	$	6

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

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Fair Value of Financial Instruments (Notes)

6 Months Ended

Jun. 30, 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 June 30, 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 June 30, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		10		—		—		10
Money market funds	—		—		—		6		6
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	2		—		—		—		2
Equity securities	2		—		—		—		2
Price risk management activities: (1) (4)
Electricity	—		29		23		—		52
Natural gas	—		43		3		—		46
	$	16	$	92	$	26	$	6	$	140
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	36	$	141	$	—	$	177
Natural gas	—		57		23		—		80
	$	—	$	93	$	164	$	—	$	257

(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 net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.

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

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

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of June 30, 2023
Electricity physical forwards	$	22	$	140	Discounted cash flow	Electricity forward price (per MWh)	$	31.90	$	208.00	$	93.59
Natural gas financial swaps	3		23		Discounted cash flow	Natural gas forward price (per Decatherm)	2.35		9.35		3.47
Electricity financial futures	1		1		Discounted cash flow	Electricity forward price (per MWh)	57.00		206.00		97.99
	$	26	$	164
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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Balance as of the beginning of the period	$	28	$	52	$	32	$	85
Net realized and unrealized losses/(gains)*	110		(19)		99		(56)
Transfers from Level 3 to Level 2	—		2		7		6
Balance as of the end of the period	$	138	$	35	$	138	$	35

* 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 no net realized gains or losses for the three months ended June 30, 2023 and $2 million in net realized gains for the three months ended June 30, 2022. For the six-month periods ended June 30, 2023 and 2022, includes $3 million in net realized losses and $3 million in net realized gains, respectively.

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

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

As of June 30, 2023, the carrying amount of PGE’s long-term debt was $3,486 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,014 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)

6 Months Ended

Jun. 30, 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, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. The Company 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, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. The Company may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not intend to engage in trading activities for non-retail purposes.

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

	June 30, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	37	$	112
Natural gas	38		201
Total current derivative assets (1)	75		313
Noncurrent assets:
Commodity contracts:
Electricity	15		44
Natural gas	8		30
Total noncurrent derivative assets (1)	23		74
Total derivative assets (2)	$	98	$	387
Current liabilities:
Commodity contracts:
Electricity	$	59	$	93
Natural gas	39		25
Total current derivative liabilities	98		118
Noncurrent liabilities:
Commodity contracts:
Electricity	118		53
Natural gas	41		22
Total noncurrent derivative liabilities	159		75
Total derivative liabilities (2)	$	257	$	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 June 30, 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):

	June 30, 2023			December 31, 2022
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	219		Decatherms	211		Decatherms
Foreign currency	$	15	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 June 30, 2023 and December 31, 2022, gross amounts included as Price risk

management liabilities subject to master netting agreements were $12 million and $5 million, respectively, entirely for natural gas, for which PGE has 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Commodity contracts:
Electricity	$	88	$	(14)	$	53	$	(54)
Natural Gas	65		(27)		197		(238)
Foreign currency exchange	—		1		—		1

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2023 and 2022, net losses of $157 million and $15 million, respectively, have been offset. Net losses of $363 million and net gains of $183 million have been offset for the six-month periods ended June 30, 2023 and 2022, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 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	$	20	$	12	$	17	$	(2)	$	(2)	$	80	$	125
Natural gas	(7)		19		9		13		—		—		34
Net unrealized loss/(gain)	$	13	$	31	$	26	$	11	$	(2)	$	80	$	159

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

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of June 30, 2023 was $244 million, for which PGE has posted $42 million in collateral, consisting of $26 million of letters of credit and $16 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2023, the cash requirement to either post as collateral or settle the instruments immediately would have been $170 million. As of June 30, 2023, PGE had $9 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 June 30, 2023, PGE held from counterparties $16 million in collateral, consisting of $11 million of letters of credit and $5 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.

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

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

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Earnings Per Share (Notes)

6 Months Ended

Jun. 30, 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) and at the market offering program. See Note 7, Shareholders’ Equity, for additional information on the EFSA and at the market offering program and the resulting 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 and six months ended June 30, 2023, unvested performance-based restricted stock units and related dividend equivalent rights of 440 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 337 thousand shares excluded for the three and six months ended June 30, 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 June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
Weighted-average common shares outstanding—basic	97,087	89,225	94,478	89,310
Dilutive effect of potential common shares	543	146	472	139
Weighted-average common shares outstanding—diluted	97,630	89,371	94,950	89,449

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Equity (Notes)

6 Months Ended

Jun. 30, 2023

Equity [Abstract]

Equity

SHAREHOLDERS’ EQUITY

The activity in equity during the three- and six-month periods ended June 30, 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
Issuances of shares pursuant to equity-based plans	30,245	1		—		—		1
Issuances of shares pursuant to equity forward sales agreement	2,212,610	92		—		—		92
Stock-based compensation	—	6		—		—		6
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4750 per share)	—	—		—		(51)		(51)
Net income	—	—		—		39		39
Balances as of June 30, 2023	98,863,827	$	1,647	$	(3)	$	1,556	$	3,200
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
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738

At the Market Offering Program—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at the market offering programs. As of June 30, 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties and under such agreements, the Company could have physically settled by delivering 172,033 shares to the counterparty in exchange for cash of $8 million. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

Equity Forward Sale Agreement—In 2022, PGE entered into an 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. In June 2023, the Company issued 2,212,610 shares pursuant to the EFSA and received net proceeds of $92 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 June 30, 2023, the Company could have physically settled the EFSA by delivering 2,224,374 shares to the forward counterparty in exchange for cash of $92 million.

On July 12, 2023, the Company issued 2,224,374 shares pursuant to the EFSA and received net proceeds of $92 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 the three and six months ended June 30, 2023, an incremental 335,507 and 291,550 shares, respectively, 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)

6 Months Ended

Jun. 30, 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 entirety of Portland Harbor is under an active engineering design phase.

PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including conclusion of remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position.

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

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. 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 September 29, 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 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 was temporarily stayed, during the bankruptcy proceeding of Talen’s parent company.

Complaint to implement Montana Senate Bill 265 (MSB 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 was temporarily stayed, during the bankruptcy proceeding 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. 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. The Court has entered a procedural schedule that leads to a trial, which would begin November 6, 2024.

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

Westmoreland Mine Permits—Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending the decision not take effect for 365 days from the date of a final order. Both decisions may be subject to appellate review. PGE is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

Regulatory Matters

Faraday—On February 15, 2023, PGE filed with the OPUC a General Rate Case 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 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 $188 million in capital costs associated with the project to repower the original 1907 Faraday hydro facility. The upgrade project was placed into service January 31, 2023. Certain parties to the 2024 GRC proceeding have challenged the prudence of aspects of PGE’s investment in the Faraday project and have recommended rate base reductions and disallowances. The Company cannot predict the ultimate outcome of the remaining regulatory process, nor can PGE estimate a range of reasonably possible disallowance. The OPUC has significant discretion in making the final determination of the GRC that may result in the disallowance of certain costs for recovery in customer prices, which could be material to PGE’s financial position, results of operations, and cash flows. Costs directly disallowed for recovery in customer prices, if any, would be charged to expense at the time such disallowance becomes probable and reasonably estimable. 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.

Other Matters

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

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Guarantees (Notes)	6 Months Ended
	Jun. 30, 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 June 30, 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)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(11.2)		(9.5)		(10.0)		(10.0)
State and local taxes, net of federal tax benefit	8.3		9.0		8.8		9.0
Flow-through depreciation and cost basis differences	(0.6)		0.6		0.5		0.6
Amortization of excess deferred income tax	(3.8)		(4.1)		(3.7)		(4.3)
Other	7.1		(0.1)		0.9		(0.1)
Effective tax rate	20.8	%	16.9	%	17.5	%	16.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s PTC generation will end at various dates through 2033.

Carryforwards

Federal tax credit carryforwards as of June 30, 2023 and December 31, 2022 were $100 million and $102 million, respectively. 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 June 30, 2023 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 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 on August 16, 2022. There was no immediate impact of the IRA to PGE’s results of operations for the three and six months ended June 30, 2023. PGE is 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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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 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 net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.

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

Assets and liabilities from price risk management activities classified as Level 3 consist of 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, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. The Company 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, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. The Company may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not intend to engage in trading activities for non-retail purposes.

Commitments and Contingencies, Policy [Policy Text Block]

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

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

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

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

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

Guarantees, Indemnifications and Warranties Policies [Policy Text Block]

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

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Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Retail:
Residential	$	279	$	250	$	641	$	558
Commercial	196		168		393		346
Industrial	87		73		169		142
Direct access customers	7		9		13		17
Subtotal	569		500		1,216		1,063
Alternative revenue programs, net of amortization	2		3		5		4
Other accrued revenues, net	(4)		—		(3)		—
Total retail revenues	567		503		1,218		1,067
Wholesale revenues*	62		65		150		121
Other operating revenues	19		23		28		29
Total revenues	$	648	$	591	$	1,396	$	1,217

* Wholesale revenues include $22 million and $14 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2023 and 2022, respectively, and $56 million and $33 million for the six months ended June 30, 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)

6 Months Ended

Jun. 30, 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 June 30,		Six Months Ended June 30,
	2023		2023
Balance as of beginning of period	$	13	$	12
Increase in provision	1		4
Amounts written off	(3)		(6)
Recoveries	2		3
Balance as of end of period	$	13	$	13

Schedule of Other Current Assets [Table Text Block]

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

	June 30, 2023		December 31, 2022
Prepaid expenses	$	56	$	69
Assets from price risk management activities	75		313
Margin deposits	26		116
Other current assets	$	157	$	498

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

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

	June 30, 2023		December 31, 2022
Electric utility plant in-service	$	12,868	$	12,421
Construction work-in-progress	568		467
Total cost	13,436		12,888
Less: accumulated depreciation and amortization	(4,595)		(4,423)
Electric utility plant, net	$	8,841	$	8,465

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	June 30, 2023					December 31, 2022
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	23		$	136	$	—		$	1
Pension and other postretirement plans	—			95		—			95
Debt issuance costs	—			21		—			21
Trojan decommissioning activities	—			134		—			133
February 2021 ice storm and damage	12			60		10			64
Power cost adjustment mechanism	16			7		14			14
2020 Labor Day wildfire	5			25		4			27
COVID-19	12			7		—			22
Wildfire mitigation	—			32		—			28
Other	20			76		26			68
Total regulatory assets	$	88		$	593	$	54		$	473
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,154	$	—		$	1,136
Deferred income taxes	—			187		—			194
Asset retirement obligations	—			10		—			7
Price risk management	—			—		195			—
Boardman Refund	4			3		—			—
Other	21			55		39			52
Total regulatory liabilities	$	25	*	$	1,409	$	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):

	June 30, 2023		December 31, 2022
Accrued employee compensation and benefits	$	58	$	66
Accrued taxes payable	25		29
Accrued interest payable	33		31
Accrued dividends payable	48		42
Regulatory liabilities—current	25		234
Margin deposits from wholesale counterparties	5		140
Other	82		99
Total accrued expenses and other current liabilities	$	276	$	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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Service cost	$	3	$	4	$	6	$	8
Interest cost*	9		7		18		14
Expected return on plan assets*	(11)		(12)		(22)		(24)
Amortization of net actuarial loss*	—		4		—		8
Net periodic benefit cost	$	1	$	3	$	2	$	6

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

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		10		—		—		10
Money market funds	—		—		—		6		6
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	2		—		—		—		2
Equity securities	2		—		—		—		2
Price risk management activities: (1) (4)
Electricity	—		29		23		—		52
Natural gas	—		43		3		—		46
	$	16	$	92	$	26	$	6	$	140
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	36	$	141	$	—	$	177
Natural gas	—		57		23		—		80
	$	—	$	93	$	164	$	—	$	257

(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 June 30, 2023
Electricity physical forwards	$	22	$	140	Discounted cash flow	Electricity forward price (per MWh)	$	31.90	$	208.00	$	93.59
Natural gas financial swaps	3		23		Discounted cash flow	Natural gas forward price (per Decatherm)	2.35		9.35		3.47
Electricity financial futures	1		1		Discounted cash flow	Electricity forward price (per MWh)	57.00		206.00		97.99
	$	26	$	164
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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Balance as of the beginning of the period	$	28	$	52	$	32	$	85
Net realized and unrealized losses/(gains)*	110		(19)		99		(56)
Transfers from Level 3 to Level 2	—		2		7		6
Balance as of the end of the period	$	138	$	35	$	138	$	35

* 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 no net realized gains or losses for the three months ended June 30, 2023 and $2 million in net realized gains for the three months ended June 30, 2022. For the six-month periods ended June 30, 2023 and 2022, includes $3 million in net realized losses and $3 million in net realized gains, respectively.

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Price Risk Management (Tables)

6 Months Ended

Jun. 30, 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):

	June 30, 2023		December 31, 2022
Current assets:
Commodity contracts:
Electricity	$	37	$	112
Natural gas	38		201
Total current derivative assets (1)	75		313
Noncurrent assets:
Commodity contracts:
Electricity	15		44
Natural gas	8		30
Total noncurrent derivative assets (1)	23		74
Total derivative assets (2)	$	98	$	387
Current liabilities:
Commodity contracts:
Electricity	$	59	$	93
Natural gas	39		25
Total current derivative liabilities	98		118
Noncurrent liabilities:
Commodity contracts:
Electricity	118		53
Natural gas	41		22
Total noncurrent derivative liabilities	159		75
Total derivative liabilities (2)	$	257	$	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 June 30, 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):

	June 30, 2023			December 31, 2022
Commodity contracts:
Electricity	5		MWhs	6		MWhs
Natural gas	219		Decatherms	211		Decatherms
Foreign currency	$	15	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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Commodity contracts:
Electricity	$	88	$	(14)	$	53	$	(54)
Natural Gas	65		(27)		197		(238)
Foreign currency exchange	—		1		—		1

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

Schedule of Risk Derivatives [Table Text Block]

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 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	$	20	$	12	$	17	$	(2)	$	(2)	$	80	$	125
Natural gas	(7)		19		9		13		—		—		34
Net unrealized loss/(gain)	$	13	$	31	$	26	$	11	$	(2)	$	80	$	159

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 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 June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
Weighted-average common shares outstanding—basic	97,087	89,225	94,478	89,310
Dilutive effect of potential common shares	543	146	472	139
Weighted-average common shares outstanding—diluted	97,630	89,371	94,950	89,449

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Equity (Tables)

6 Months Ended

Jun. 30, 2023

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three- and six-month periods ended June 30, 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
Issuances of shares pursuant to equity-based plans	30,245	1		—		—		1
Issuances of shares pursuant to equity forward sales agreement	2,212,610	92		—		—		92
Stock-based compensation	—	6		—		—		6
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4750 per share)	—	—		—		(51)		(51)
Net income	—	—		—		39		39
Balances as of June 30, 2023	98,863,827	$	1,647	$	(3)	$	1,556	$	3,200
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
Issuances of shares pursuant to equity-based plans	18,769	1		—		—		1
Stock-based compensation	—	4		—		—		4
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.4525 per share)	—	—		—		(41)		(41)
Net income	—	—		—		64		64
Balances as of June 30, 2022	89,242,672	$	1,241	$	(9)	$	1,506	$	2,738

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Income tax Income tax (Tables)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(11.2)		(9.5)		(10.0)		(10.0)
State and local taxes, net of federal tax benefit	8.3		9.0		8.8		9.0
Flow-through depreciation and cost basis differences	(0.6)		0.6		0.5		0.6
Amortization of excess deferred income tax	(3.8)		(4.1)		(3.7)		(4.3)
Other	7.1		(0.1)		0.9		(0.1)
Effective tax rate	20.8	%	16.9	%	17.5	%	16.2	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s 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	6 Months Ended
	Jun. 30, 2023 USD ($) mi² retail_customers	Jun. 30, 2022 USD ($)
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 | $	$ (135)	$ 149

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Disaggregation of Revenue [Line Items]
Subtotal	$ 569	$ 500	$ 1,216	$ 1,063
Alternative revenue programs, net of amortization	2	3	5	4
Other Cost of Operating Revenue	(4)
Other accrued (deferred) revenues, net		0	(3)	0
Total retail revenues	567	503	1,218	1,067
Wholesale revenues	62	65	150	121
Other operating revenue	19	23	28	29
Total revenues	648	591	1,396	1,217
Gain on Derivative Instruments, Pretax	22	14	56	33
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	279	250	641	558
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	196	168	393	346
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	87	73	169	142
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 7	$ 9	$ 13	$ 17

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Balance Sheet Components Allowance for Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2023	Jun. 30, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 13	$ 12
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	1	4
Accounts Receivable, Allowance for Credit Loss, Writeoff	(3)	(6)
Accounts Receivable, Allowance for Credit Loss, Recovery	2	3
Accounts Receivable, Allowance for Credit Loss	$ 13	$ 13

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Other Current Assets [Line Items]
Prepaid expenses	$ 56	$ 69
Assets from price risk management activities	75	313
Margin deposits	26	116
Other current assets	$ 157	$ 498

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 12,868		$ 12,868		$ 12,421
Construction work-in-progress	568		568		467
Total cost	13,436		13,436		12,888
Less: accumulated depreciation and amortization	(4,595)		(4,595)		(4,423)
Electric utility plant, net	8,841		8,841		$ 8,465
Amortization of Intangible Assets	$ 15	$ 14	$ 29	$ 29

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 88		$ 88		$ 54
Regulatory assets - noncurrent	593		593		473
Regulatory Liability, Current	25		25		234
Regulatory liabilities-noncurrent	1,409		1,409		1,389
Purchased power and fuel	220	$ 168	524	$ 370
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	1,154		1,154		1,136
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	187		187		194
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	10		10		7
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	0		0		0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	21		21		39
Regulatory liabilities-noncurrent	55		55		52
Regulatory Clause Revenues, under-recovered
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		195
us-gaap_revenuerefund
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	4		4		0
Regulatory liabilities-noncurrent	3		3		0	$ 66	$ 14
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	23		23		0
Regulatory assets - noncurrent	136		136		1
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	95		95		95
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	21		21		21
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	134		134		133
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	20		20		26
Regulatory assets - noncurrent	76		76		68
Storm Costs
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	12		12		10
Regulatory assets - noncurrent	60		60		64
Fire
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	5		5		4
Regulatory assets - noncurrent	25		25		27
pandemic
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	12		12		0
Regulatory assets - noncurrent	7		7		22
wildfire
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	32		32		28
Deferred Fuel Costs
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	16		16		14
Regulatory assets - noncurrent	$ 7		$ 7		$ 14

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Accrued employee compensation and benefits	$ 58	$ 66
Accrued taxes payable	25	29
Accrued interest payable	33	31
Accrued dividends payable	48	42
Regulatory liabilities—current	25	234
Deposits, Wholesale	5	140
Other	82	99
Total accrued expenses and other current liabilities	$ 276	$ 641

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 3	$ 4	$ 6	$ 8
Interest cost	9	7	18	14
Expected return on plan assets	(11)	(12)	(22)	(24)
Amortization of net actuarial loss	0	4	0	8
Net periodic benefit cost	$ 1	$ 3	$ 2	$ 6

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Balance Sheet Components (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2022 USD ($)	Mar. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 13		$ 13		$ 13	$ 12
Unbilled Receivables, Current	117		117			131
Finite-Lived Intangible Assets, Accumulated Amortization	530		530			499
Amortization of Intangible Assets	15	$ 14	29	$ 29
Line of Credit Facility, Maximum Borrowing Capacity	$ 750		$ 750
Debt Instrument, Covenant Description			65.00%
Ratio of Indebtedness to Net Capital	0.540		0.540
Line of Credit Facility, Remaining Borrowing Capacity	$ 510		$ 510
Line of Credit Facility, Current Borrowing Capacity	650		650
Authorized Short-Term Debt	900		900
Purchased power and fuel	220	168	524	370
Repayments of Long-term Debt			260	0
Amount above baseline net variable power costs			19
Proceeds from failed sale-leaseback transactions			0	25
Revenues	648	591	1,396	1,217
Letters of Credit Outstanding, Amount	92		92
Line of Credit, Current	220		220
Finance Lease, Liability, to be Paid	737		737
Revenues	648	$ 591	1,396	$ 1,217
Regulatory assets - noncurrent	593		593			473
Regulatory liabilities-noncurrent	1,409		1,409			1,389
Fire
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Regulatory assets - noncurrent	25		25			27
pandemic
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	19		19
Regulatory assets - noncurrent	7		7			22
wildfire
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Revenues			24
Revenues			24
Regulatory assets - noncurrent	32		32			$ 28
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Commercial paper	$ 140		$ 140

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Assets:
Cash equivalents	$ 0	$ 150
Debt securities:
Domestic government	19	19
Corporate credit	10	9
Money market funds measured at NAV (2)	6	11
Non-qualified benefit plan trust: (2)
Money market funds	2	1
Equity securities - domestic	2	3
Debt securities—domestic government	3	3
Assets from price risk management activities: (1) (3)
Electricity	52	156
Natural gas	46	231
Total	6	11
Assets, Fair Value Disclosure	140	583
Liabilities from price risk management activities: (1) (3)
Electricity	177	146
Natural gas	80	47
Total	257	193
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	0	150
Debt securities:
Domestic government	9	9
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	2	1
Equity securities - domestic	2	3
Debt securities—domestic government	3	3
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	16	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	10	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	29	93
Natural gas	43	225
Total	92	337
Liabilities from price risk management activities: (1) (3)
Electricity	36	53
Natural gas	57	39
Total	93	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	23	63
Natural gas	3	6
Total	26	69
Liabilities from price risk management activities: (1) (3)
Electricity	141	93
Natural gas	23	8
Total	$ 164	$ 101

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Jun. 30, 2023	Dec. 31, 2022
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 31.90	$ 35.00
Natural gas financial swaps	2.35	2.71
Financial swaps - electricity	57.00	54.17
High [Member]
Commodity Contracts
Electricity physical forwards	208.00	270.00
Natural gas financial swaps	9.35	24.71
Financial swaps - electricity	206.00	143.70
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	93.59	101.27
Natural gas financial swaps	3.47	4.42
Financial swaps - electricity	97.99	104.21
Assets [Member]
Commodity Contracts
Electricity physical forwards	22,000,000	52,000,000
Natural gas financial swaps	3,000,000	6,000,000
Financial swaps - electricity	1,000,000	11,000,000
Total commodity contracts	26,000,000	69,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	140,000,000	93,000,000
Natural gas financial swaps	23,000,000	8,000,000
Financial swaps - electricity	1,000,000	0
Total commodity contracts	$ 164,000,000	$ 101,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 28	$ 52	$ 32	$ 85
Net realized and unrealized (gains)/losses	110	(19)	99	(56)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3		(2)		6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0
Transfers out of Level 3 to Level 2			7
Balance as of the end of the period	138	35	138	35
Gain (Loss) from Price Risk Management Activity	$ 0	$ 2	$ 3	$ 3

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 29	$ 31
Long-term Debt	3,486	3,646
Unamortized Debt Issuance Expense	13	13
Long-term Debt, Fair Value	$ 3,014	$ 2,984

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Current Assets, Commodity Contracts:
Electricity	$ 37	$ 112
Natural gas	38	201
Total current derivative assets	75	313
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	15	44
Commodity Contract Asset, Noncurrent, Natural Gas	8	30
Derivative Asset, Noncurrent	23	74
Total derivative assets	98	387
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	59	93
Natural gas	39	25
Total current derivative liabilities	98	118
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	118	53
Natural gas	41	22
Total noncurrent derivative liabilities	159	75
Total derivative liabilities	$ 257	$ 193

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2023 CAD ($) MWh MMBTU	Dec. 31, 2022 CAD ($) MMBTU MWh
Commodity contracts:
Electricity | MWh	5	6
Natural gas | MMBTU	219	211
Foreign currency | $	$ 15	$ 10

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Commodity contracts:
Electricity	$ 88	$ (14)	$ 53	$ (54)
Natural Gas	65	(27)	197	(238)
Foreign currency exchange	$ 0	$ 1	$ 0	$ 1

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Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Jun. 30, 2023 USD ($)
Electricity [Member]
Commodity contracts:
2022	$ 20
2023	12
2024	17
2025	(2)
2026	(2)
Thereafter	80
Total	125
Natural Gas [Member]
Commodity contracts:
2022	7
2023	19
2024	9
2025	(13)
2026	0
Thereafter	0
Total	34
Net Unrealized Loss/(gain)[Member]
Commodity contracts:
2022	13
2023	31
2024	26
2025	(11)
2026	(2)
Thereafter	80
Total	$ 159

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ 157	$ (15)	$ 183
Derivative, Net Liability Position, Aggregate Fair Value	244		244
Collateral Already Posted, Aggregate Fair Value	42		42
Collateral cash requirement	170		170
Purchased power and fuel	220	$ 168	524	$ 370
Deposits, Wholesale	5		5		$ 140
Letters of Credit Outstanding, Amount	92		92
Derivative, Collateral, Right to Reclaim Cash	16		16
Off-Balance-Sheet, Credit Loss, Liability	26		26
Derivative Asset, Fair Value, Amount Offset Against Collateral	16		$ 16
Credit Risk Contract
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ 9

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	97,087	89,225	94,478	89,310
Dilutive effect of potential common shares	543	146	472	139
Weighted Average Number of Shares Outstanding, Diluted	97,630	89,371	94,950	89,449

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	440	337	440	337

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Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended				6 Months Ended
	Jul. 12, 2023	Jun. 12, 2023	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023	Jun. 30, 2022
Common Stock, Shares, Outstanding beginning of period				89,283,353			89,283,353
Issuance of shares pursuant to equity-based plans			$ 1	$ 0	$ 1	$ 0
Proceeds from Issuance or Sale of Equity			92	300			$ 392
Stockholders' Equity			3,112	2,779	2,709	2,707	2,779	$ 2,707
Dividends declared			(51)	(40)	(41)	(40)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			$ 39	74	64	60	$ 113	124
Common Stock, Shares, Outstanding end of period			98,863,827				98,863,827
Stockholders' Equity			$ 3,200	$ 3,112	$ 2,738	$ 2,709	$ 3,200	2,738
Common Stock, Dividends, Per Share, Declared			$ 0.4750	$ 0.4525	$ 0.4525	$ 0.4300
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture			$ (6)	$ (1)	$ (4)
Repurchase of common stock						$ (18)	$ 0	$ (18)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent			$ 1		$ 1
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period			96,620,972	89,283,353	89,223,903	89,410,612	89,283,353	89,410,612
Issuances of shares pursuant to equity-based plans			30,245	159,603	18,769	163,291
Stock Issued During Period, Shares, New Issues			2,212,610	7,178,016
Common Stock, Shares, Outstanding end of period			98,863,827	96,620,972	89,242,672	89,223,903	98,863,827	89,242,672
Stock Repurchased and Retired During Period, Shares						(350,000)
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans			$ 1	$ 0	$ 1	$ 0
Proceeds from Issuance or Sale of Equity		$ 92	92	300				$ 0
Stockholders' Equity			1,548	1,249	1,236	1,241	$ 1,249	1,241
Dividends declared			0	0	0
Stockholders' Equity			1,647	1,548	1,241	1,236	1,647	1,241
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture			(6)	(1)	(4)
Repurchase of common stock						(5)
Common Stock Including Additional Paid in Capital [Member] | Subsequent Event [Member]
Proceeds from Issuance or Sale of Equity	$ 92
AOCI Attributable to Parent [Member]
Stockholders' Equity			(4)	(4)	(10)	(10)	(4)	(10)
Dividends declared			0	0	0
Stockholders' Equity			(3)	(4)	(9)	(10)	(3)	(9)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent			1		1
Retained Earnings [Member]
Stockholders' Equity			1,568	1,534	1,483	1,476	1,534	1,476
Dividends declared			51	40	41	40
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest			39	74	64	60
Stockholders' Equity			$ 1,556	$ 1,568	$ 1,506	1,483	$ 1,556	$ 1,506
Repurchase of common stock						$ (13)

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Contingencies (Details) $ in Millions	6 Months Ended
	Jun. 30, 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
Electricity, Generation
Loss Contingencies [Line Items]
Property, Plant and Equipment, Additions	$ 188

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%	21.00%
Federal tax credits	(11.20%)	(9.50%)	(10.00%)	(10.00%)
State and local taxes, net of federal tax benefit	8.30%	9.00%	8.80%	9.00%
Flow through depreciation and cost basis differences	(0.60%)	0.60%	0.50%	0.60%
Excess deferred tax amortization	(3.80%)	(4.10%)	(3.70%)	(4.30%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	7.10%	(0.10%)	0.90%	(0.10%)
Effective tax rate	20.80%	16.90%	17.50%	16.20%

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Income tax Income tax (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 100	$ 102
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0