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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

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

For the quarterly period ended March 31, 2025
or

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________________ to ____________________
Commission File Number: 001-5532-99
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

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

121 SW Salmon Street
Portland, Oregon 97204
(503) 464-8000
(Address of principal executive offices, including zip code,
and registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

(Title of class) | (Trading Symbol) | (Name of exchange on which registered)
Common Stock, no par value | POR | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
[x] Yes x [ ] No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ☒ | Accelerated filer | ☐
Non-accelerated filer | ☐ | Smaller reporting company | ☐
|  | Emerging growth company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes [x] No
Number of shares of common stock outstanding as of April 18, 2025 is 109,514,333 shares.

1

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2025
TABLE OF CONTENTS

Definitions | 3
PART I — FINANCIAL INFORMATION
Item 1. | Financial Statements (Unaudited) | 4
| Condensed Consolidated Statements of Income and Comprehensive Income | 4
| Condensed Consolidated Balance Sheets | 5
| Condensed Consolidated Statements of Cash Flows | 7
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 63
Item 4. | Controls and Procedures | 63
PART II — OTHER INFORMATION
Item 1. | Legal Proceedings | 64
Item 1A. | Risk Factors | 64
Item 5. | Other Information | 61
Item 6. | Exhibits | 64
SIGNATURE | 66

2

Table of Contents
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
Clearwater |  | Clearwater Wind Development
Colstrip |  | Colstrip Units 3 and 4 coal-fired generating plant
EPA |  | United States Environmental Protection Agency
FERC |  | Federal Energy Regulatory Commission
FMB |  | First Mortgage Bond
GAAP |  | Accounting principles generally accepted in the United States of America
GRC |  | General Rate Case
IRP |  | Integrated Resource Plan
ITC |  | Federal investment tax credit
Moody’s |  | Moody’s Investors Service
MW |  | Megawatts
MWh |  | Megawatt hour
NVPC |  | Net Variable Power Costs
OPUC |  | Public Utility Commission of Oregon
PCAM |  | Power Cost Adjustment Mechanism
PTC |  | Production tax credit
RAC |  | Renewable Adjustment Clause
RFP |  | Request for Proposals
RPS |  | Renewable Portfolio Standard
S&P |  | S&P Global Ratings
SEC |  | United States Securities and Exchange Commission

3

Table of Contents
PART I — FINANCIAL INFORMATION

Item 1. | Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME
(Dollars in millions, except per share amounts)
(Unaudited)

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Revenues: |  |  |  |  |  |  |
Revenues, net |  |  |  |  | $ | 932 |  |  | $ | 940 |
Alternative revenue programs, net of amortization |  |  |  |  | (4) |  |  | (11) |
Total revenues |  |  |  |  | 928 |  |  | 929 |
Operating expenses: |  |  |  |  |  |  |
Purchased power and fuel |  |  |  |  | 368 |  |  | 405 |
Generation, transmission and distribution |  |  |  |  | 110 |  |  | 99 |
Administrative and other |  |  |  |  | 96 |  |  | 95 |
Depreciation and amortization |  |  |  |  | 140 |  |  | 121 |
Taxes other than income taxes |  |  |  |  | 46 |  |  | 47 |
Total operating expenses |  |  |  |  | 760 |  |  | 767 |
Income from operations |  |  |  |  | 168 |  |  | 162 |
Interest expense, net |  |  |  |  | 56 |  |  | 51 |
Other income: |  |  |  |  |  |  |
Allowance for equity funds used during construction |  |  |  |  | 5 |  |  | 5 |
Miscellaneous income, net |  |  |  |  | 5 |  |  | 6 |
Other income, net |  |  |  |  | 10 |  |  | 11 |
Income before income tax expense |  |  |  |  | 122 |  |  | 122 |
Income tax expense |  |  |  |  | 22 |  |  | 13 |
Net income |  |  |  |  | 100 |  |  | 109 |
Other comprehensive income |  |  |  |  | — |  |  | 1 |
Net income and Comprehensive income |  |  |  |  | $ | 100 |  |  | $ | 110 |
Weighted-average common shares outstanding (in thousands): |  |  |  |  |  |  |
Basic |  |  |  |  | 109,423 |  |  | 101,299 |
Diluted |  |  |  |  | 109,683 |  |  | 101,467 |
Earnings per share—basic and diluted |  |  |  |  | $ | 0.91 |  |  | $ | 1.08 |
See accompanying notes to condensed consolidated financial statements.

4

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(Unaudited)

| March 31, 2025 |  | December 31, 2024
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 11 |  |  | $ | 12 |
Accounts receivable, net | 473 |  |  | 456 |
Inventories | 111 |  |  | 114 |
Regulatory assets—current | 164 |  |  | 205 |
Other current assets | 215 |  |  | 238 |
Total current assets | 974 |  |  | 1,025 |
Electric utility plant, net | 10,534 |  |  | 10,345 |
Regulatory assets—noncurrent | 633 |  |  | 632 |
Nuclear decommissioning trust | 44 |  |  | 30 |
Non-qualified benefit plan trust | 34 |  |  | 34 |
Other noncurrent assets | 476 |  |  | 478 |
Total assets | $ | 12,695 |  |  | $ | 12,544 |
See accompanying notes to condensed consolidated financial statements.

5

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Dollars in millions)
(Unaudited)

| March 31, 2025 |  | December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 281 |  |  | $ | 365 |
Liabilities from price risk management activities—current | 109 |  |  | 147 |
Current portion of long-term debt | 68 |  |  | 170 |
Current portion of finance lease obligation | 27 |  |  | 27 |
Accrued expenses and other current liabilities | 437 |  |  | 410 |
Total current liabilities | 922 |  |  | 1,119 |
Long-term debt, net of current portion | 4,663 |  |  | 4,354 |
Regulatory liabilities—noncurrent | 1,412 |  |  | 1,440 |
Deferred income taxes | 595 |  |  | 564 |
Deferred investment tax credits | 59 |  |  | 61 |
Unfunded status of pension and postretirement plans | 137 |  |  | 140 |
Liabilities from price risk management activities—noncurrent | 67 |  |  | 72 |
Asset retirement obligations | 293 |  |  | 292 |
Non-qualified benefit plan liabilities | 73 |  |  | 74 |
Finance lease obligations, net of current portion | 273 |  |  | 276 |
Other noncurrent liabilities | 357 |  |  | 358 |
Total liabilities | 8,851 |  |  | 8,750 |
Commitments and contingencies (see notes) |  |  |
Shareholders’ Equity: |  |  |
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2025 and December 31, 2024 | — |  |  | — |
Common stock, no par value, 160,000,000 shares authorized; 109,503,325 and 109,342,251 shares issued and outstanding as of March 31, 2025 and December 31, 2024, respectively | 2,123 |  |  | 2,118 |
Accumulated other comprehensive loss | (4) |  |  | (4) |
Retained earnings | 1,725 |  |  | 1,680 |
Total shareholders’ equity | 3,844 |  |  | 3,794 |
Total liabilities and shareholders’ equity | $ | 12,695 |  |  | $ | 12,544 |
See accompanying notes to condensed consolidated financial statements.

6

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

| Three Months Ended March 31,
| 2025 |  | 2024
Cash flows from operating activities: |  |  |
Net income | $ | 100 |  |  | $ | 109 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation and amortization | 140 |  |  | 121 |
Deferred income taxes | 20 |  |  | 37 |
Pension and other postretirement benefits | 2 |  |  | 1 |
Allowance for equity funds used during construction | (5) |  |  | (5) |
Alternative revenue programs | 4 |  |  | 11 |
Regulatory assets | (5) |  |  | (120) |
Regulatory liabilities | (8) |  |  | (3) |
Tax credit sales | 3 |  |  | 1 |
Other non-cash income and expenses, net | 30 |  |  | 22 |
Changes in working capital: |  |  |
Accounts receivable, net | (25) |  |  | (5) |
Inventories | 3 |  |  | (1) |
Margin deposits | 55 |  |  | 27 |
Accounts payable and accrued liabilities | (37) |  |  | 24 |
Margin deposits from wholesale counterparties | 5 |  |  | — |
Other working capital items, net | (28) |  |  | (16) |
Other, net | (23) |  |  | (28) |
Net cash provided by operating activities | 231 |  |  | 175 |
See accompanying notes to condensed consolidated financial statements.

7

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued
(In millions)
(Unaudited)

| Three Months Ended March 31,
| 2025 |  | 2024
Cash flows from investing activities: |  |  |
Capital expenditures | $ | (359) |  |  | $ | (325) |
Purchases of Nuclear decommissioning trust securities | (2) |  |  | — |
Other, net | (15) |  |  | (6) |
Net cash used in investing activities | (376) |  |  | (331) |
Cash flows from financing activities: |  |  |
Proceeds from issuance of common stock | — |  |  | 78 |
Proceeds from issuance of long-term debt | 310 |  |  | 450 |
Payments on long-term debt | (102) |  |  | — |
Issuance (maturities) of commercial paper, net | — |  |  | (146) |
Dividends paid | (55) |  |  | (48) |
Other | (9) |  |  | (7) |
Net cash provided by financing activities | 144 |  |  | 327 |
Change in cash and cash equivalents | (1) |  |  | 171 |
Cash and cash equivalents, beginning of period | 12 |  |  | 5 |
Cash and cash equivalents, end of period | $ | 11 |  |  | $ | 176 |
Supplemental cash flow information is as follows: |  |  |
Cash paid for interest, net of amounts capitalized | $ | 43 |  |  | $ | 26 |
Cash paid (received) for income taxes, net | (1) |  |  | 2 |
See accompanying notes to condensed consolidated financial statements.

8

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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 single, vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon (State). The Company also participates in the wholesale market by purchasing and selling electricity, natural gas, and environmental credits 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. In addition, PGE performs portfolio management and wholesale market services for third parties in the region. The Company continues to develop products and service offerings for the benefit of retail and wholesale customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company owns unregulated, non-utility real estate comprised primarily of PGE’s corporate headquarters. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, State-approved service area, entirely within the State, encompasses 51 incorporated cities. As of March 31, 2025, PGE served 953,000 retail customers within a service area of 1.9 million residents.
PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters.
Condensed Consolidated Financial Statements
These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.
The financial information included herein as of and for the three months ended March 31, 2025 and 2024 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, 2024 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2024, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 14, 2025, which should be read in conjunction with the interim unaudited Financial Statements.
Comprehensive Income
No material change occurred in Other comprehensive income in the three months ended March 31, 2025 and 2024.
9

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
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.
Recent Accounting Pronouncements
In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 amends Topic 740 to address requests to improve transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2025. Early adoption is permitted. PGE does not expect the adoption to have a material impact on the consolidated financial statements and does not plan to early adopt the standard.
In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. ASU 2024-03 requires additional disclosure, in the notes to financial statements, of specified information about certain costs and expenses. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2027. Early adoption is permitted. PGE is assessing the impact of adoption on the consolidated financial statements and does not plan to early adopt the standard.
10

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
NOTE 2: REVENUE RECOGNITION
Disaggregated Revenue
The following table presents PGE’s revenue, disaggregated by customer type (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Retail: |  |  |  |  |  |  |
Residential |  |  |  |  | $ | 429 |  |  | $ | 415 |
Commercial |  |  |  |  | 242 |  |  | 227 |
Industrial |  |  |  |  | 127 |  |  | 102 |
Direct access customers |  |  |  |  | 9 |  |  | 6 |
Subtotal |  |  |  |  | 807 |  |  | 750 |
Alternative revenue programs, net of amortization |  |  |  |  | (4) |  |  | (11) |
Other accrued revenues, net |  |  |  |  | 4 |  |  | 1 |
Total retail revenues |  |  |  |  | 807 |  |  | 740 |
Wholesale revenues* |  |  |  |  | 100 |  |  | 176 |
Other operating revenues |  |  |  |  | 21 |  |  | 13 |
Total revenues |  |  |  |  | $ | 928 |  |  | $ | 929 |

* Wholesale revenues include $50 million and $88 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2025 and 2024, 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 consist of non-residential customers who 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 a less significant 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.
11

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates 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. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the condensed consolidated statements of income and comprehensive income.
Alternative Revenues programs—Revenues related to PGE’s decoupling mechanism and Renewable Adjustment Clause (RAC) are considered earned under alternative revenue programs, as these amounts represent contracts with the regulator and not with customers. Such revenues are presented separately from revenues from contracts with customers and classified as Alternative revenue programs, net of amortization on the condensed consolidated statements of income and comprehensive income. The activity within this line item is comprised of current period deferral adjustments, which can either be a collection from or a refund to customers, and is net of any related amortization. When amounts related to alternative revenue programs are ultimately included in prices and customer bills, the amounts are included within Revenues, net, with an equal and offsetting amount of amortization recorded on the Alternative revenue programs, net of amortization line item. Under the RAC, in 2024 and through February 28, 2025, the Company has deferred amounts related to the Clearwater Wind Development (Clearwater). For further information, see “Clearwater RAC” in the Regulatory Assets and Liabilities section of Note 3, Balance Sheet Components.
Wholesale Revenues
PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of, and secure reasonably-priced power for, its retail customers, manage risk, and administer its current long-term wholesale contracts. In addition, the Company performs portfolio management and wholesale market services for third parties in the region and sells environmental credits in the wholesale marketplace. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow PGE to purchase and sell electricity within the region depending upon: i) the relative price and availability of power; ii) hydro, solar and wind conditions; and iii) daily and seasonal retail demand.
PGE’s Wholesale revenues consist primarily of 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 nets 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.
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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.
NOTE 3: BALANCE SHEET COMPONENTS
Accounts Receivable, Net
Accounts receivable, net includes $135 million and $177 million of unbilled revenues as of March 31, 2025 and December 31, 2024, respectively. Accounts receivable, net includes an allowance for uncollectible accounts of $13 million and $12 million as of March 31, 2025 and December 31, 2024, respectively. The following summarizes activity during 2025 in the allowance for credit losses (in millions):

| Three Months Ended March 31, |  |
Balance as of beginning of period | $ | 12 |  |  |
Increase in provision | 3 |  |  |
Amounts written off | (4) |  |  |
Recoveries | 2 |  |  |
Balance as of end of period | $ | 13 |  |  |

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

| March 31, 2025 |  | December 31, 2024
Prepaid expenses | $ | 119 |  |  | $ | 81 |
Assets from price risk management activities | 26 |  |  | 32 |
Margin deposits | 70 |  |  | 125 |
Other current assets | $ | 215 |  |  | $ | 238 |

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(Unaudited)
Electric Utility Plant, Net
Electric utility plant, net consists of the following (in millions):

| March 31, 2025 |  | December 31, 2024
Electric utility plant in-service | $ | 15,028 |  |  | $ | 14,863 |
Construction work-in-progress | 693 |  |  | 567 |
Total cost | 15,721 |  |  | 15,430 |
Less: accumulated depreciation and amortization | (5,187) |  |  | (5,085) |
Electric utility plant, net | $ | 10,534 |  |  | $ | 10,345 |

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $630 million and $611 million as of March 31, 2025 and December 31, 2024, respectively. Amortization expense related to intangible assets was $19 million and $18 million for the three months ended March 31, 2025 and 2024, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.
Regulatory Assets and Liabilities
Regulatory assets and liabilities consist of the following (in millions):

| March 31, 2025 |  | December 31, 2024
| Current |  | Noncurrent |  | Current |  | Noncurrent
Regulatory assets: |  |  |  |  |  |  |
Price risk management | $ | 83 |  |  | $ | 60 |  |  | $ | 115 |  |  | $ | 70 |
Pension and other postretirement plans | — |  |  | 84 |  |  | — |  |  | 84 |
Trojan decommissioning activities | — |  |  | 162 |  |  | — |  |  | 161 |
February 2021 ice storm and damage | 13 |  |  | 43 |  |  | 14 |  |  | 44 |
January 2024 storm and damage | — |  |  | 46 |  |  | — |  |  | 46 |
Reliability contingency events | — |  |  | 95 |  |  | — |  |  | 90 |
2020 Labor Day wildfire | 5 |  |  | 18 |  |  | 6 |  |  | 18 |
Wildfire mitigation | 44 |  |  | — |  |  | 43 |  |  | — |
Other | 19 |  |  | 125 |  |  | 27 |  |  | 119 |
Total regulatory assets | $ | 164 |  |  | $ | 633 |  |  | $ | 205 |  |  | $ | 632 |
Regulatory liabilities: |  |  |  |  |  |  |
Asset retirement removal costs | $ | — |  |  | $ | 1,210 |  |  | $ | — |  |  | $ | 1,199 |
Deferred income taxes | — |  |  | 174 |  |  | — |  |  | 179 |
Clearwater RAC | 41 |  |  | 4 |  |  | — |  |  | 40 |
Other | 40 |  |  | 24 |  |  | 53 |  |  | 22 |
Total regulatory liabilities | $ | 81 |  | * | $ | 1,412 |  |  | $ | 53 |  | * | $ | 1,440 |

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.
January 2024 storm and damage—Beginning January 13, 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to seek recovery of incremental storm expenses through the OPUC pre-authorized emergency deferral mechanism, subject to the application of an earnings test. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC, under Docket
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UM 2190, related to the emergency restoration costs for the January storm, and through March 31, 2025 the Company had deferred $46 million, including interest, under the deferral. PGE's 2024 preliminary regulated return on equity, based on actual results, did not exceed the OPUC's authorized rate. PGE believes the full amounts deferred as of March 31, 2025 are probable of recovery under the emergency deferral mechanism. The Company anticipates submitting a request for recovery early in the third quarter of 2025. The OPUC has significant discretion in making the final determination of recovery, and their conclusion of overall prudence, including application of the earnings test, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Reliability contingency events—As approved by the OPUC in PGE’s 2024 GRC, the Reliability Contingency Event (RCE) mechanism allows PGE to defer and recover 80% of prudent costs for RCEs above amounts forecasted in the Company’s Annual Power Cost Update Tariff, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing power cost adjustment mechanism (PCAM). As of March 31, 2025, PGE’s deferred balance related to RCEs was $95 million, which includes $92 million related to RCEs deferred in 2024 and $3 million related to RCEs deferred in 2025. PGE files the results of the PCAM annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective January 1 of the following year. RCE costs incurred in 2024 and in 2025 will be included in the PCAM for 2024 and 2025, which the Company expects to file no later than July 1, 2025 and 2026, respectively. PGE believes the deferred amounts as of March 31, 2025 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Wildfire Mitigation represents incremental costs and investments made by PGE related to efforts on its system to mitigate the risk of wildfire and improve resiliency to wildfire damage under Oregon Senate Bill 762, enacted in 2021. These efforts include enhanced tree and brush clearing, hardening and undergrounding equipment, and making emergency plans in close partnership with various land and emergency management agencies to further expand the use of a public safety power shutoff, when the risk warrants. In December 2024, PGE submitted its 2025 risk-based Wildfire Mitigation Plan, which is expected to be reviewed by the OPUC on June 26, 2025.
As of March 31, 2025 and December 31, 2024, PGE’s deferred balance related to incremental wildfire mitigation operating expenses was $44 million and $43 million, respectively. The 2025 balance is comprised of:
•Pre-AAC—Prior to establishing the collections noted below, PGE had deferred incremental costs related to wildfire mitigation and as of March 31, 2025 this balance was $5 million, which will fully amortize by September 30, 2025.
•2023 Base rates—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, through December 31, 2023. As of March 31, 2025, there was $1 million in the balancing account. In February 2025, the OPUC approved an advice filing that allows for the recovery of these costs over a twelve-month period, which began March 1, 2025.
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•2024 AAC—Beginning January 1, 2024, and in conjunction with the Company’s 2024 GRC proceeding, PGE removed the $24 million of wildfire mitigation operations and maintenance (O&M) expense recovery from base rates, with the intent of recovering the current year forecasted O&M expense within the automatic adjustment clause in a separate tariff. On February 16, 2024, PGE submitted an advice filing to the OPUC to update the tariff to reflect prospective wildfire mitigation costs for 2024, which included $45 million of O&M expense and $4 million for the revenue requirement of capital placed in service. On July 23, 2024, the OPUC reached a decision that allowed PGE to begin collecting $24 million of O&M expense and $4 million for the revenue requirement of capital placed in service. Collection is occurring over a nine-month period, which began August 1, 2024. Although the approved amount of collections in 2024 was less than actual costs, PGE does not believe it is precluded from deferring such costs and believes they are prudently incurred and probable of recovery. Any differences between actual expense and customer collections will be recorded as regulatory assets or liabilities within the automatic adjustment clause balancing account, which will be subject to a prudence review, but will not be subject to an earnings test. As of March 31, 2025, there was $28 million deferred as a regulatory asset in the balancing account. PGE anticipates submitting an additional filing to seek recovery of the remaining O&M expense in the third quarter of 2025. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
•2025 AAC—In conjunction with PGE’s filed 2025 Wildfire Mitigation Plan, PGE submitted a series of advice filings in 2025 with the intent of recovering the $56 million related to O&M and $12 million related to the capital revenue requirement in a two-phased approach. The first phase, which includes $24 million of O&M to be collected over a twelve-month period, was approved by the OPUC in February 2025, with a tariff effective date of March 1, 2025. The second phase, which was requested with a tariff effective date of May 14, 2025 and includes the remaining $32 million O&M and the entire $12 million related to capital revenue requirement, is still pending OPUC approval. Although the OPUC has only approved a portion of PGE’s 2025 wildfire mitigation O&M, PGE does not believe it is precluded from deferring such costs. Any differences between actual expense and customer collections will be recorded as regulatory assets or liabilities within the automatic adjustment clause balancing account, which will be subject to a prudence review, but will not be subject to an earnings test. As of March 31, 2025, there was $10 million deferred as a regulatory asset in the balancing account. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Clearwater RAC—The Clearwater RAC represents all costs and benefits associated with the Clearwater wind facility. Under the RAC, during 2023, the Company submitted a filing for Clearwater proposing to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the year ended December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits resulting in a net regulatory liability of $40 million, which began amortizing as a refund to customers on March 1, 2025 over a twelve month period, as approved in Order 25-075 issued February 21, 2025. For the period of January 1, 2025 through February 28, 2025, PGE deferred an additional net $7 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that PGE believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC for that period. The OPUC has significant discretion on overall prudence and in making the final determination of recovery or refund. Any cost disallowance or increased refunds would be recognized as a charge to earnings.
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(Unaudited)
Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consist of the following (in millions):

| March 31, 2025 |  | December 31, 2024
Accrued employee compensation and benefits | $ | 56 |  |  | $ | 80 |
Accrued taxes payable | 32 |  |  | 36 |
Accrued interest payable | 54 |  |  | 49 |
Accrued dividends payable | 57 |  |  | 57 |
Regulatory liabilities—current | 81 |  |  | 53 |
Margin deposits from wholesale counterparties | 11 |  |  | 5 |
Other | 146 |  |  | 130 |
Total accrued expenses and other current liabilities | $ | 437 |  |  | $ | 410 |

Credit Facilities
On September 10, 2024, PGE entered into an amendment of its existing revolving credit facility that extended the scheduled expiration into September 2029. As of March 31, 2025, PGE had a $750 million revolving credit facility that provides t he Company the ability to expand to $850 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on the Company’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2025, PGE was in compliance with this covenant with a 55.2% 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 $750 million.
The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. The Company has elected to limit its borrowings under the revolving credit facility in order to allow for coverage of any potential need to repay commercial paper that may be outstanding at the time. As of March 31, 2025, PGE had no commercial paper outstanding.
PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.
In addition, PGE has four letter of credit facilities that provide a total capacity of $320 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 $133 million were outstanding as of March 31, 2025. 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, 2026.
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Long-term Debt
On March 25, 2025, PGE entered into a Bond Purchase Agreement related to the sale of $310 million in First Mortgage Bonds (FMBs). The Bonds were issued and funded in full on March 25, 2025 and consist of:
•a series, due in 2035, in the amount of $60 million that will bear interest from its issuance date at an annual rate of 5.36%;
•a series, due in 2045, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 5.72%; and
•a series, due in 2055, in the amount of $200 million that will bear interest from its issuance date at an annual rate of 5.84%.
On November 14, 2024, PGE drew a $220 million loan under a 366-day term loan agreement. On December 31, 2024, PGE repaid $50 million of the term loan and, on March 31, 2025, the Company repaid another $102 million, leaving an outstanding balance of $68 million.
Defined Benefit Retirement Plan Costs
Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Service cost |  |  |  |  | $ | 2 |  |  | $ | 3 |
Interest cost* |  |  |  |  | 8 |  |  | 8 |
Expected return on plan assets* |  |  |  |  | (9) |  |  | (10) |
Net periodic benefit cost |  |  |  |  | $ | 1 |  |  | $ | 1 |

* 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 March 31, 2025 and December 31, 2024, 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, 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.
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(Unaudited)
Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.
The Company’s financial assets and liabilities whose values were recognized at fair value in the Company’s condensed consolidated balance sheets are as follows by level within the fair value hierarchy (in millions):

| As of March 31, 2025
| Level 1 |  | Level 2 |  | Level 3 |  | Other (2) |  | Total
Assets: |  |  |  |  |  |  |  |  |
Cash equivalents | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Nuclear decommissioning trust: (1) |  |  |  |  |  |  |  |  |
Debt securities: |  |  |  |  |  |  |  |  |
Domestic government | 15 |  |  | 12 |  |  | — |  |  | — |  |  | 27 |
Corporate credit | — |  |  | 9 |  |  | — |  |  | — |  |  | 9 |
Money market funds | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |
Non-qualified benefit plan trust: (3) |  |  |  |  |  |  |  |  |
Debt securities—domestic government | 2 |  |  | — |  |  | — |  |  | — |  |  | 2 |
Paid Leave Oregon Trust |  |  |  |  |  |  |  |  |
Money market funds | — |  |  | — |  |  | — |  |  | 5 |  |  | 5 |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | — |  |  | 21 |  |  | 4 |  |  | — |  |  | 25 |
Natural gas | — |  |  | 8 |  |  | — |  |  | — |  |  | 8 |
| $ | 17 |  |  | $ | 50 |  |  | $ | 4 |  |  | $ | 13 |  |  | $ | 84 |
Liabilities: |  |  |  |  |  |  |  |  |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 19 |  |  | $ | 39 |  |  | $ | — |  |  | $ | 58 |
Natural gas | — |  |  | 114 |  |  | 4 |  |  | — |  |  | 118 |
| $ | — |  |  | $ | 133 |  |  | $ | 43 |  |  | $ | — |  |  | $ | 176 |

(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 $32 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.
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| As of December 31, 2024
| Level 1 |  | Level 2 |  | Level 3 |  | Other (2) |  | Total
Assets: |  |  |  |  |  |  |  |  |
Cash equivalents | $ | 12 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 12 |
Nuclear decommissioning trust: (1) |  |  |  |  |  |  |  |  |
Debt securities: |  |  |  |  |  |  |  |  |
Domestic government | 10 |  |  | 6 |  |  | — |  |  | — |  |  | 16 |
Corporate credit | — |  |  | 7 |  |  | — |  |  | — |  |  | 7 |
Money market funds | — |  |  | — |  |  | — |  |  | 7 |  |  | 7 |
Non-qualified benefit plan trust: (3) |  |  |  |  |  |  |  |  |
Debt securities—domestic government | 2 |  |  | — |  |  | — |  |  | — |  |  | 2 |
Paid Leave Oregon Trust: |  |  |  |  |  |  |  |  |
Money market funds | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | — |  |  | 18 |  |  | 1 |  |  | — |  |  | 19 |
Natural gas | — |  |  | 15 |  |  | — |  |  | — |  |  | 15 |
| $ | 24 |  |  | $ | 46 |  |  | $ | 1 |  |  | $ | 11 |  |  | $ | 82 |
Liabilities: |  |  |  |  |  |  |  |  |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 25 |  |  | $ | 31 |  |  | $ | — |  |  | $ | 56 |
Natural gas | — |  |  | 159 |  |  | 4 |  |  | — |  |  | 163 |
| $ | — |  |  | $ | 184 |  |  | $ | 35 |  |  | $ | — |  |  | $ | 219 |

(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 $32 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 NAV 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 NAV. 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), NQBP trust, and Paid Leave Oregon trust are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:
Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.
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Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.
Money market funds—PGE invests in money market funds that seek to maintain a stable NAV. 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 NAV. Redemption is permitted daily without written notice.
The NQBP trust is invested in exchange-traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as Nasdaq and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.
Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates and reduce volatility in NVPC for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.
For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.
Assets and liabilities from price risk management activities classified as Level 3 consist of longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument.
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Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:

|  | Fair Value |  | Valuation Technique |  | Significant Unobservable Input |  | Price per Unit
Commodity Contracts |  | Assets |  | Liabilities |  |  |  | Low |  | High |  | Weighted Average
|  | (in millions) |  |  |  |  |  |  |  |  |  |
As of March 31, 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity physical forwards |  | $ | — |  |  | $ | 37 |  |  | Discounted cash flow |  | Electricity forward price (per megawatt hour (MWh)) |  | $ | 17.00 |  |  | $ | 92.81 |  |  | $ | 55.63 |
Natural gas financial swaps |  |  |  | 4 |  |  | Discounted cash flow |  | Natural gas forward price (per Decatherm) |  | 1.84 |  |  | 2.90 |  |  | 2.30 |
Electricity financial futures |  | 4 |  |  | 2 |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | 23.00 |  |  | 100.00 |  |  | 59.54 |
|  | $ | 4 |  |  | $ | 43 |  |  |  |  |  |  |  |  |  |  |
As of December 31, 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity physical forwards |  | $ | — |  |  | $ | 28 |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | $ | 14.00 |  |  | $ | 99.68 |  |  | $ | 59.43 |
Natural gas financial swaps |  | — |  |  | 4 |  |  | Discounted cash flow |  | Natural gas forward price (per Decatherm) |  | 1.86 |  |  | 6.53 |  |  | 2.68 |
Electricity financial futures |  | 1 |  |  | 3 |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | 27.00 |  |  | 110.00 |  |  | 70.55 |
|  | $ | 1 |  |  | $ | 35 |  |  |  |  |  |  |  |  |  |  |

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

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Balance as of the beginning of the period |  |  |  |  | $ | 34 |  |  | $ | 45 |
Net realized and unrealized losses/(gains)* |  |  |  |  | 9 |  |  | (2) |
Transfers from Level 3 to Level 2 |  |  |  |  | (4) |  |  | — |
Balance as of the end of the period |  |  |  |  | $ | 39 |  |  | $ | 43 |

* 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 $1 million net realized gains for the three months ended March 31, 2025 and $1 million net realized losses for the three months ended March 31, 2024.
Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter.
Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.
As of March 31, 2025, the carrying amount of PGE’s long-term debt was $4,731 million, net of $16 million of unamortized debt expense, and its estimated aggregate fair value was $4,217 million. As of December 31, 2024, the carrying amount of PGE’s long-term debt was $4,524 million, net of $15 million of unamortized debt expense, and its estimated aggregate fair value was $3,963 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 services for third parties in the region and purchases and sells environmental credits in the wholesale marketplace. 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. 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 ins truments as economic hedges. PGE does not intend to engage in trading activities for non-retail purposes.
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PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):

| March 31, 2025 |  | December 31, 2024
Current assets: |  |  |
Commodity contracts: |  |  |
Electricity | $ | 21 |  |  | $ | 18 |
Natural gas | 5 |  |  | 14 |
Total current derivative assets (1) | 26 |  |  | 32 |
Noncurrent assets: |  |  |
Commodity contracts: |  |  |
Electricity | 4 |  |  | 1 |
Natural gas | 3 |  |  | 1 |
Total noncurrent derivative assets (1) | 7 |  |  | 2 |
Total derivative assets (2) | $ | 33 |  |  | $ | 34 |
Current liabilities: |  |  |
Commodity contracts: |  |  |
Electricity | $ | 23 |  |  | $ | 32 |
Natural gas | 86 |  |  | 115 |
Total current derivative liabilities | 109 |  |  | 147 |
Noncurrent liabilities: |  |  |
Commodity contracts: |  |  |
Electricity | 35 |  |  | 24 |
Natural gas | 32 |  |  | 48 |
Total noncurrent derivative liabilities | 67 |  |  | 72 |
Total derivative liabilities (2) | $ | 176 |  |  | $ | 219 |

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.
(2) As of March 31, 2025 and December 31, 2024, no commodity derivative assets or liabilities were designated as hedging instruments.
PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions):

| March 31, 2025 |  | December 31, 2024
Commodity contracts: |  |  |  |  |
Electricity | 2 |  | MWhs |  | 2 |  | MWhs
Natural gas | 198 |  | Decatherms |  | 199 |  | Decatherms
Foreign currency | $ | 35 |  | Canadian |  | $ | 34 |  | Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of March 31, 2025, gross amounts included as Price risk management liabilities subject to master netting agreements were $33 million, entirely for natural gas, for which PGE has posted $10 million
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(Unaudited)
collateral. As of December 31, 2024, gross amounts included as Price risk management liabilities subject to master netting agreements were $41 million, all of which was for natural gas, for which PGE had posted $16 million collateral.
Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Commodity contracts: |  |  |  |  |  |  |
Electricity |  |  |  |  | $ | 9 |  |  | $ | (19) |
Natural Gas |  |  |  |  | 14 |  |  | 14 |

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended March 31, 2025 and 2024, ne t gains o f $46 million and net gains of $49 million, respectively, have been offset.
Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of March 31, 2025 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

| 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | Thereafter |  | Total
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity | $ | (2) |  |  | $ | 5 |  |  | $ | 4 |  |  | $ | 3 |  |  | $ | 3 |  |  | $ | 20 |  |  | $ | 33 |
Natural gas | 62 |  |  | 42 |  |  | 5 |  |  | 1 |  |  | — |  |  | — |  |  | 110 |
Net unrealized loss/(gain) | $ | 60 |  |  | $ | 47 |  |  | $ | 9 |  |  | $ | 4 |  |  | $ | 3 |  |  | $ | 20 |  |  | $ | 143 |

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.
The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2025 was $161 million, for which PGE has posted $55 million in collateral, consisting of $18 million of letters of credit and $37 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2025, the cash requirement to either post as collateral or settle the instruments immediately would have been $118 million. As of March 31, 2025, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheets.
As of March 31, 2025, PGE held from counterparties $10 million in collateral, consisting of $5 million of letters of credit and $5 million of cash. 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.
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(Unaudited)
PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. Credit risk may be concentrated to the extent 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 at-the-market offering program. See Note 7, Shareholders’ Equity, for additional information on the 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. Anti-dilutive stock awards are excluded from the calculation of diluted earnings per common share.
For the three months ended March 31, 2025, unvested performance-based restricted stock units and related dividend equivalent rights of 617 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 507 thousand shares excluded for the three months ended March 31, 2024.
Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Weighted-average common shares outstanding—basic |  |  |  |  | 109,423 |  |  | 101,299 |
Dilutive effect of potential common shares |  |  |  |  | 260 |  |  | 168 |
Weighted-average common shares outstanding—diluted |  |  |  |  | 109,683 |  |  | 101,467 |

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(Unaudited)
NOTE 7: SHAREHOLDERS’ EQUITY
The activity in equity during the three and three-month periods ended March 31, 2025 and 2024 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, 2024 | 109,342,251 |  |  | $ | 2,118 |  |  | $ | (4) |  |  | $ | 1,680 |  |  | $ | 3,794 |  |  |  |
Issuances of shares pursuant to equity-based plans | 161,074 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Stock-based compensation | — |  |  | 5 |  |  | — |  |  | — |  |  | 5 |  |  |  |
Dividends declared ($0.5000 per share) | — |  |  | — |  |  | — |  |  | (55) |  |  | (55) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 100 |  |  | 100 |  |  |  |
Balances as of March 31, 2025 | 109,503,325 |  |  | $ | 2,123 |  |  | $ | (4) |  |  | $ | 1,725 |  |  | $ | 3,844 |  |  |  |
Balances as of December 31, 2023 | 101,159,609 |  |  | $ | 1,750 |  |  | $ | (5) |  |  | $ | 1,574 |  |  | $ | 3,319 |  |  |  |
Issuances of shares pursuant to equity-based plans | 148,926 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Stock-based compensation | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Issuances of shares pursuant to equity agreements | 1,714,972 |  |  | 78 |  |  | — |  |  | — |  |  | 78 |  |  |  |
Other comprehensive income | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |  |  |  |
Dividends declared ($0.4750 per share) | — |  |  | — |  |  | — |  |  | (48) |  |  | (48) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 109 |  |  | 109 |  |  |  |
Balances as of March 31, 2024 | 103,023,507 |  |  | $ | 1,828 |  |  | $ | (4) |  |  | $ | 1,635 |  |  | $ | 3,459 |  |  |  |

At-the-Market Offering Program—In July 2024, PGE entered into an equity distribution agreement under which it could sell up to $400 million of its common stock through at-the-market offering programs. In the fourth quarter of 2024 the Company entered into forward sale agreements for 1,420,049 shares. In December 2024, the Company issued 1,066,549 shares pursuant to the forward sale agreements and received net proceeds of $50 million. In the first quarter of 2025 the Company entered into forward sale agreements for 1,996,890 shares. The Company could have physically settled the remaining amount by delivering 2,350,390 shares in exchange for cash of $104 million as of March 31, 2025. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.
Prior to settlement, the potentially issuable shares pursuant to the agreements 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 agreements 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 months ended March 31, 2025, no shares were included in the calculation of diluted EPS related to the securities under the agreements. For additional information concerning the Company’s diluted earnings per share, see Note 6, Earnings Per Share.
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NOTE 8: CONTINGENCIES
PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.
Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made.
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event.
PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
EPA Investigation of Portland Harbor
An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs), as it historically owned or operated property near the river.
A Portland Harbor site remedial investigation was completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.
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The EPA finalized a feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor 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 the 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 have 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 continues 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.
On November 18, 2024, the EPA issued a Special Notice Letter to 60 entities, including PGE, with requirements and deadlines that may ultimately lead to litigation, in relation to Portland Harbor. The EPA has recommended that recipients coordinate their response, which are now due May 30, 2025. Formal negotiations are anticipated to take approximately two years, concluding in fall 2026 and no later than May 2027.
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
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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.
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). 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, 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. The parties have agreed to stay the arbitration proceedings indefinitely as settlement discussions are underway. PGE cannot predict the ultimate outcome of this matter.
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 alleged they suffered adverse effects from the defendants’ coal dust. In 2021, the claim was amended to add PGE as a defendant. Plaintiffs were seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court. The trial date had been rescheduled for June 2, 2025, however, in March 2025, parties reached tentative agreement that will not have a material impact on the Company’s financial position, results of operations, or cash flows.
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
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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
management currently believes that resolution of such known matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.
NOTE 9: GUARANTEES
PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2025, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.
NOTE 10: INCOME TAXES
Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Federal statutory tax rate |  |  |  |  | 21.0 | % |  | 21.0 | %
Federal tax credits* |  |  |  |  | (9.5) |  |  | (16.2) |
State and local taxes, net of federal tax benefit |  |  |  |  | 8.6 |  |  | 9.1 |
Flow-through depreciation and cost basis differences |  |  |  |  | (0.5) |  |  | 0.2 |
Reversal of excess deferred income tax |  |  |  |  | (2.0) |  |  | (3.3) |
Executive Compensation |  |  |  |  | 0.8 |  |  | 0.5 |
Other |  |  |  |  | (0.4) |  |  | (0.6) |
Effective tax rate |  |  |  |  | 18.0 | % |  | 10.7 | %

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities as well as amortization of investment tax credits (ITCs). 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. The generation of production tax credits from Tucannon River Wind Farm ended in 2024. ITCs are deferred and amortized as a reduction of income tax expense over the estimated useful lives of the related properties.
Carryforwards
Federal tax credit carryforwards as of March 31, 2025 and December 31, 2024 were $76 million and $69 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2045. PGE included anticipated proceeds from the sale of tax credits in determining the need for a valuation allowance. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2025 will be realized, however a valuation allowance has been recorded for the expected discount on the sale of tax credits. The valuation allowance as of March 31, 2025 was $1 million and was deferred as a regulatory asset. As of December 31, 2024,
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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
no material valuation allowance was recorded. As of March 31, 2025, and December 31, 2024, PGE had no material unrecognized tax benefits.
NOTE 11: SEGMENT INFORMATION
PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity. 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 the State of Oregon.
The Company has identified one operating and reportable segment and defines its segment on the basis of the way in which internally reported financial information is regularly reviewed by the chief operating decision maker (CODM) to analyze financial performance, make decisions, and allocate resources. The Company’s CODM is the President and Chief Executive Officer.
The Company’s CODM assesses the segment’s performance by using Consolidated Net Income. The CODM uses Consolidated Net Income predominantly as a key input to earnings per share and return on equity, which is an important metric for investors, regulators and is also tied to employee compensation.
The table below provides information about the Company’s single business segment, including significant segment expenses, and includes reconciliation to Consolidated Net Income (dollars in millions):

| Three Months Ended March 31,
| 2025 |  | 2024
Total revenues | $ | 928 |  |  | $ | 929 |
Operating expenses: |  |  |
Purchased power and fuel | 368 |  |  | 405 |
Operating and maintenance expense: |  |  |
Generation, transmission and distribution | 110 |  |  | 99 |
Administrative and other | 96 |  |  | 95 |
Total operating and maintenance expense | 206 |  |  | 194 |
Depreciation and amortization | 140 |  |  | 121 |
Taxes other than income taxes | 46 |  |  | 47 |
Total operating expenses | 760 |  |  | 767 |
Income from operations | 168 |  |  | 162 |
Interest expense, net: |  |  |
Interest expense | 60 |  |  | 55 |
Allowance for borrowed funds used during construction | (4) |  |  | (4) |
Total interest expense, net | 56 |  |  | 51 |
Other income, net: | 10 |  |  | 11 |
Income before income taxes | 122 |  |  | 122 |
Income tax expense | 22 |  |  | 13 |
Net income | $ | 100 |  |  | $ | 109 |

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Certain additional financial information relating to the Company’s single business segment was as follows (dollars in millions):

| Three Months Ended March 31,
| 2025 |  | 2024
Total assets | $ | 12,695 |  |  | $ | 11,588 |
Capital expenditures | 359 |  |  | 325 |

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,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” “based on,” “conditioned upon,” “considers,” “could,” “expected,” “forecast,” “goals,” “needs,” “promises,” “subject to,” “targets,” 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. Portland General Electric Company’s (PGE, or the Company) 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, executive orders, legislative action, and regulatory audits, investigations, and actions, including those of the Federal Energy Regulatory 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, 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;
•trade tariffs, inflation, and volatility in interest rates;
•the impacts of changes in the tax code, including tax rates, minimum tax rates, adjustments made to deferred tax assets and liabilities, and changes impacting the availability of and ability to transfer renewable tax credits;
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•risks and uncertainties related to current or future All-Source RFP projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of trade tariffs), permitting and construction delays, available tax credits, counterparty credit risk, and legislative uncertainty;
•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 prices 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 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, along with “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components 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 financial health and 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 such costs;
•ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (PSPS) and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems were involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through prices or insurance, resulting in impact to the financial condition or reputation of the Company;
•operational factors affecting PGE’s power generating and battery storage facilities, including forced outages, fires, unscheduled delays, environmental impacts, 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, repair costs, or abandoned costs;
•delays in the supply chain and increased supply costs, failure to complete capital projects on schedule or within budget, failure to obtain permits, 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;
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•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, including the potential impact of trade tariffs, 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, compliance with, and general uncertainty around environmental laws and policies;
•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, including changes in load resulting in future transmission constraints, 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, internally or to third parties, 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;
•reputational damage from negative publicity, protests, fines, penalties and other negative consequences resulting in regulatory and/or legal actions;
•physical attacks upon Company employees;
•employee workforce factors, including potential strikes, work stoppages, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries during 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 (GHG) emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively respond to legislative requirements concerning GHG 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
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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; and
•acts of war, terrorism, or civil disruption.
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 of Oregon (State). The Company participates in wholesale markets by purchasing and selling electricity, natural gas, and environmental credits 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. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory in the State.
Company Strategy
The Company exists to power the advancement of society. PGE energizes lives, strengthens communities, and fosters energy solutions that promote social, economic, and environmental progress. The Company is committed to being a clean energy leader and delivering steady growth and returns to shareholders. PGE is focused on working with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing GHG 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 imperatives:
•Decarbonize Power—Reduce 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.
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Climate Change
State-mandated GHG emissions reduction targets—In 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 227 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% clean and renewable electricity by 2035 and 100% 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 municipal 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 either from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.
As of March 31, 2025, the Green Future Impact Program has an approved capacity of 750 megawatts (MW) nameplate, of which 482 megawatts (MW) have been subscribed. Through this voluntary program, the Company seeks to support customers’ clean energy acceleration.
Severe weather—In recent years, PGE’s service territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. Beginning January 13, 2024, the Company’s service territory encountered a severe winter weather event, including snow, ice, and high winds that caused catastrophic damage to physical assets and resulted in widespread customer power outages. For more information regarding the January 2024 severe winter weather event, see “Declared States of Emergency” within this Overview section. In August 2023 the region experienced a record-breaking heat wave with temperatures reaching all-time recorded highs for the month. This resulted in a peak load demand of 4,498 MW, exceeding the Company’s previous all-time peak load demand, and surpassing the prior summer peak load by nearly 6%. The increase and severity of 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 created a Clean Energy Plan (CEP), which articulates the Company’s strategy to make continued progress towards 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 Integrated Resource Plan (IRP). PGE filed its first combined IRP and CEP with the OPUC in March 2023. That filing projected PGE’s
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resource and capacity needs over the next 20 years and proposed an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements.
Throughout the remainder of 2023, PGE refreshed its forecasts, first in an Addendum filed in July 2023 then several times in subsequent comments in the CEP and IRP docket with the OPUC (LC 80). PGE estimates a total resource need of approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to make continual progress towards meeting the Company’s clean energy targets. Through the 2021 All-Source Request for Proposals (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.
On January 25, 2024, the OPUC acknowledged PGE’s IRP, subject to certain conditions, providing regulatory support for the Company to pursue the near-term resource additions articulated in the Action Plan. However, the OPUC declined to acknowledge the CEP, directing the Company to provide additional forecast of its emission reductions based on new analysis in the CEP/IRP Update to be filed in June 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP.
2021 and 2023 All-Source RFPs
Pursuant to the 2021 All-Source RFP process, which sought approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, PGE entered into agreements to acquire resources as follows:
•Clearwater Wind Development (Clearwater)—The 311 MW wind energy facility is part of the larger Clearwater Wind Development in Eastern Montana. PGE owns 208 MW of production capacity of the facility. Subsidiaries of NextEra Energy Resources, LLC, which operates the facility, owns the remaining 103 MW of production capacity and sells their portion of the output to PGE under a 30-year PPA.
•Seaside Grid—The 200 MW Battery Energy Storage System (BESS) facility, located in Portland, Oregon has an estimated commercial operation date of June 30, 2025 and will be owned by PGE. As of March 31, 2025, the Company has recorded $334 million, including AFUDC, in construction work-in-progress (CWIP) for the Seaside Grid.
•Constable BESS (formerly Evergreen)—The 75 MW BESS facility, located in Hillsboro, Oregon was placed in service on December 20, 2024 and is owned by PGE. As of March 31, 2025, the Company has recorded $157 million in Electric Utility Plant, net, including AFUDC.
•Sundial BESS (formerly Troutdale Grid)—The 200 MW BESS facility, located in Troutdale, Oregon reached commercial operations on December 20, 2024. NextEra Energy Resources, LLC owns the resource and sells the capacity to PGE under a 20-year agreement.
The agreements related to the Clearwater Wind Development and all BESS agreements represent the final procurement 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 directly interconnected to PGE’s transmission and distribution system. In the event emissions are associated with energy obtained to charge the BESS, they are accounted for when they are emitted from the generating facility. As such, BESS projects do not add incremental emissions to the grid, and therefore, are considered non-emitting dispatchable capacity resources. The BESS facilities qualify for the federal investment tax credits (ITCs). The agreements related to the Clearwater Wind Development qualify for production tax credits (PTCs) and are eligible under Oregon’s Renewable Portfolio Standard (RPS). The agreements will be subject to prudency review by the OPUC.
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PGE filed notice with the OPUC in January 2023 that an RFP was needed to procure resources to meet forecasted capacity shortfalls and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan. PGE filed the draft 2023 All-Source RFP with the OPUC in May 2023 and regulatory approval was granted in January 2024. The Company issued the 2023 All-Source RFP to market in February 2024, seeking bids for resources that can provide non-emitting dispatchable capacity and renewable generation.
After a robust and competitive bidding process performed in accordance with Oregon's competitive bidding rules, and with the active participation of, and oversight by, an OPUC-selected third-party independent evaluator, on September 17, 2024, PGE submitted a request for acknowledgement of the final shortlist of bidders to the OPUC. On October 7, 2024, the Company filed notification that one project on the final shortlist was no longer available.
PGE constructed the final short list to provide optionality and address the Company’s future capacity need. The Company ranked the final shortlist in two groups, prioritized based on performance in the RFP price scoring evaluation, representing the optimal intersection of value to customers at the least-cost and the least-risk. These two groups together represented the final shortlist of projects recommended for regulatory acknowledgement. On November 19, 2024, the OPUC acknowledged, with conditions, PGE’s final shortlist of resources as follows:
•Group A, as shown below, consisted of three bids that are top performing and PGE expected to enter commercial negotiation for all of these projects. Group A included 375 megawatts (MW) nameplate of renewable resources and 400 MW nameplate of battery storage; and
•Group B, as shown below, consisted of five bids, all of which represent capacity options via BESS facilities. These projects are also high performing and PGE may enter commercial negotiations with some or all of these projects, allowing flexibility to address any remaining capacity need. Group B includes 885 MW nameplate of battery storage.
The proposals for renewable resources provide various combinations of solar and battery storage options that include PPAs along with Company-owned resources via Build Transfer Agreements (BTA). The proposals for non-emitting dispatchable capacity resources provide battery storage options that include PPAs along with Company-owned resources via BTAs.

2023 RFP Final Shortlist
| Project |  | Technology |  | Structure |  | MW |  | Company-owned MW
Group A | 1 |  | Solar, Battery |  | PPA |  | 250 (1) |  | —
2 |  | Battery |  | BTA |  | 400 |  | 400
3 |  | Solar, Battery |  | BTA |  | 125 (1) |  | 125
Group B | 4 |  | Battery |  | PPA |  | 185 |  | —
5 |  | Battery |  | PPA |  | 200 |  | —
6 |  | Battery |  | Hybrid (2) |  | 200 |  | 100
7 |  | Battery |  | Hybrid (2) |  | 200 |  | 100
8 |  | Battery |  | BTA |  | 100 |  | 100

(1) MW values do not include nameplate capacity of paired energy storage of 250 MW for project 1 and 125 MW for project 3.
(2) Hybrid commercial structure includes a PPA portion and a Company-owned portion of project resources.
On December 12, 2024, Project 1 in Group A notified PGE that it was withdrawing from commercial negotiations. PGE continues to negotiate with the remaining Group A projects and aims to finalize contracts over the second half of 2025.
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RFP final shortlist projects were evaluated and selected based on conditions as of the final shortlist date and are subject to risks and uncertainties, including, but not limited to, regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including the application of trade tariffs), and legislative uncertainty.
Additional details of the 2023 RFP (OPUC Docket UM 2274) are available on the OPUC website at www.oregon.gov/puc.
Both the 2021 and 2023 RFPs were the subject of regulatory and legal challenges initiated by NewSun Energy LLC, focused on the scoring methodology of the RFPs and OPUC acknowledgement of the final shortlists. Two of NewSun’s challenges to the 2021 RFP were dismissed as moot in recent court decisions, although NewSun has indicated it will file further appeals. PGE has joined the proceedings as an intervenor, and the remaining challenges are in various stages of litigation or regulatory review. PGE cannot predict the outcome of these proceedings or potential impact, if any, on its 2021 and 2023 All-Source RFP process.
NewSun was an intervenor in the Clearwater RAC proceeding in Docket UE 427, in which the OPUC rejected NewSun’s proposals to change the RFP oversight process but adopted conditions proposed by OPUC staff on how PGE should recognize Clearwater’s capacity factor and transmission assumptions in its AUT and PCAM beginning in 2025. While PGE is seeking review of the OPUC’s February 21, 2025 order adopting the conditions, PGE cannot predict the outcome or potential impact, if any, on future RFP, AUT, or PCAM proceedings.
2025 All-Source RFP
PGE filed notice with the OPUC in November 2024 that an RFP in 2025 was needed to procure resources to meet a forecasted 2029 capacity shortfall and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan and CEP. PGE filed the draft 2025 All-Source RFP on April 17, 2025.
Transmission Upgrades
In alignment with local and regional transmission plans, the 2023 IRP Action Plan, and CEP, PGE is evaluating and implementing upgrades to existing transmission resources and expansions of current transmission networks. Transmission resource actions are intended to alleviate congestion, improve regional adequacy and reliability, enable decarbonization goals, and address growing customer demand.
On May 28, 2024, PGE signed a non-binding memorandum of understanding in the development of the North Plains Connector, an approximately 415-mile, high-voltage direct-current (HVDC) transmission line to be constructed with endpoints near Bismarck, North Dakota and Colstrip, Montana. The parties have entered negotiations with the United States Department of Energy (U.S. DOE) to finalize the project objectives, terms, and conditions, including the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. On August 6, 2024, the project was awarded a $700 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to further support its development and would reduce the overall total investment of the project. A portion of the GRIP funding is allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in this Overview for further discussion over the impacts of Federal grants and effect of Presidential executive orders.
The North Plains Connector would be the nation’s first HVDC transmission connection among three regional U.S. electric energy markets, providing additional flexibility and the sharing of resources across multiple time zones. PGE's resource planning process indicates the need for transmission to provide additional transfer capacity, access to diverse energy resources, access to enhanced wholesale markets, and ease congestion on the existing western
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transmission system. PGE continues to explore the North Plains Connector as a resource to meet those load-service needs.
The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS) with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project will accelerate the development of transmission capacity, enabling new generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS communities by increasing resources available to the CTWS to support economic growth opportunities. See “Federal Grants” in this Overview for further discussion over the impacts of Federal grants and the potential effect of Presidential executive orders.
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 has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC, as required by State law, to coordinate activities across the Company and with State-wide stakeholders. The 2025 WMP Update forecasts $53 to $57 million in operations and maintenance costs and an additional $57 to $78 million in capital investments, for the year ending 2025, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating 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. In the three months ended March 31, 2025, PGE invested $8.5 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2025 WMP.
•Virtual Power Plant (VPP)—PGE’s VPP is comprised of Distributed Energy Resources and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) charging solutions support grid reliability and increase portfolio flexibility and resource diversity. These Distributed Energy Resources and flexible loads are the foundation of PGE’s VPP that increasingly provides a growing suite of grid and system services over time. When coordinated through the Company’s Distributed Energy Resources Management Systems, Distributed Energy Resource and flexible loads support cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. Customer participation in the VPP helps avoid customer service interruptions and reduces exposure to scarcity pricing in energy markets. On July 8, 2024, customer actions, orchestrated through the VPP, reduced load by more than 100 MW. As their participation in PGE’s VPP grows, customer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.
•Distribution System Plan (DSP)—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. The OPUC Staff finalized their review of modifications to the current DSP guidelines in the fourth quarter of 2024 and PGE filed its next DSP in December 2024, fully compliant with the updated requirement. The DSP outlines distribution system assets, describes how the Company plans for new load, including distributed resources such as EVs and rooftop solar installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in meeting PGE’s clean energy goals.
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Electrify the economy—To help Oregon reach its decarbonization goals, PGE is committed to increasing electrification of buildings and supporting vehicle electrification for customers, as well as its own vehicle fleet.
Transportation electrification (TE) is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to manage EV charging load, develop infrastructure projects aimed at improving accessibility to EV charging stations, build electric fleet partnerships, and offer programs to support customers’ transitions to TE.
In October 2023, the OPUC accepted PGE’s second TE plan, which covers the 2023 to 2025 time period and considers current and planned activities, along with forecasted EV loads. To date, PGE has incurred $10 million in capital expenditures under the current TE plan. PGE is planning to submit its draft 2026-2028 TE plan in July 2025.
PGE continues to pursue advanced technologies to enhance the grid, pursue 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
Trade Tariffs—Recently, trade tariffs were imposed through presidential executive orders. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect. Trade tariffs may increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. For example, the cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase materials and supplies balances that are ultimately issued out to capital projects. Similarly, prices may rise for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. While PGE’s Canadian natural gas imports are not expected to be impacted by the current state of trade tariffs due to the imports being U.S.-Mexico-Canada Agreement compliant, the future of trade tariff impacts on such imports is uncertain. The Company is unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, which could include project delays, cost increases, and obstacles to PGE’s strategic plan execution. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.
Federal Grants—In November 2021, the $1.2 trillion IIJA, which includes approximately $550 billion of new federal spending, was signed into law. PGE continues to pursue multiple areas under the IIJA, and other state and federal programs, for potential grant funding of projects. These projects target improvements in electrical system reliability and resiliency, wildfire situational awareness and mitigation, greater communications capabilities, advancements in customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, and regional transmission capacity constraints.
As of March 31, 2025, PGE has been associated with the submission of 42 grant applications as the recipient or Sub-recipient and has been awarded 16 grants totaling $319 million, including the following:
•U.S. DOE Bethel-Round Butte Transmission Line Upgrade—The U.S. DOE selected the CTWS, with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission Line to 500 kV. The U.S DOE and the CTWS, as the prime recipient, entered into a Cooperative Agreement on August 13, 2024. Subsequently the CTWS entered into a subrecipient agreement with PGE on December 1, 2024. These agreements memorialize the funding and scope for the multiyear transmission line upgrade. See “Transmission Upgrades” in this Overview for further discussion.
•U.S. DOE Grid Edge Devices—The U.S. DOE selected and subsequently entered into an agreement on October 1, 2024 with PGE leading a consortium for a $50 million grant for the Grid Edge Devices project.
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The project will enable real-time information at each meter to improve the visibility of the electrical system to grid operators, providing detection of potential operational problems and shorten outage times, ultimately helping to anticipate and mitigate the impacts of extreme weather on grid resiliency.
As of March 31, 2025, PGE has incurred an immaterial amount of costs associated with its Federal grants and continues to assess the impacts of these federal grants on the Company’s financial position and results of operations. A series of Presidential executive orders were recently issued related to energy and environmental policies. These orders could lead to delays, reviews, and potential terminations or modifications of grants. PGE is analyzing these executive orders to understand their potential impact on grant funding, and associated work that was originally required as a part of certain Community Benefits Plans. As of March 31, 2025, the grants disclosed above continue to be executed. Although PGE continues to apply for additional grants, the Company cannot predict the ultimate timing and success of securing funding from federal programs, or predict the outcome of existing grants.
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.
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. In December 2023, PGE received approval from the OPUC to transfer 2023 PTCs and record any difference in the full value and the discounted value in a property balancing account. Consistent with options available under the IRA, the Company transferred 2023 credits with the final transfer occurring in the first quarter of 2024. On April 17, 2024, PGE received approval from the OPUC to transfer 2024 and 2025 PTCs and record any difference between the full value and the discounted value in a property balancing account. On December 11, 2024, PGE received approval from the OPUC to transfer 2024 ITCs and return the net proceeds from the sale to PGE customers. PGE has entered into agreements to transfer 2023 to 2025 tax credits and transferred $112 million, net of discounts, for cash proceeds in 2024. The Company expects to generate and transfer approximately $158 million in tax credits in 2025.
The Company believes the tax incentives in the IRA provide additional investment opportunities for PGE and provide benefits to customers. Increased capital expenditures in such investment opportunities would likely result in additional financing needs through debt and equity instruments. PGE continues to monitor for potential impacts to its business due to executive orders that may change tax incentives under IRA programs. Potential modifications to or repeal of the IRA tax credits, normalization rules, and transferability of credits, may substantially influence renewable energy development and ongoing generation and battery storage investments. Such changes could have a material impact on PGE’s results of operations, financial position, and cash flows.
HB 2021—Among other things, HB 2021 requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers to certain targets: 80% reduction by 2030; 90% by 2035; and 100% by 2040, compared to a baseline emission level. The baseline emission level is calculated for each provider by using average annual emissions associated with power generated and purchased for retail load for the years 2010 through 2012, which provide a representative sample of various hydroelectric production years.
HB 2021 requires utilities to develop a CEP for meeting the reduction targets, concurrent with each IRP. In reviewing a CEP, the OPUC must ensure that utilities create a plan that is in the public interest, demonstrate continual progress toward meeting the targets, and take actions as soon as practicable that facilitate rapid reduction of GHG emissions. Further, the CEP must result in an affordable, reliable, and clean electric system. The law does not require particular GHG percentage reductions be attained until 2030. The law contains a cost cap and reliability related provisions that can slow or pause compliance with the GHG targets, if implicated. The OPUC has a current open docket, UM 2273, in which provisions regarding the cost cap are being investigated.
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A separate law adopted in 2009 requires retail electricity providers to report annually to the Oregon Department of Environmental Quality (ODEQ) the GHG emissions associated with electricity used to serve retail customers. The OPUC must use the data reported to the ODEQ to determine whether the GHG targets have been met.
RPS standards and related laws—In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable sources by dates certain and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers no later than 2030.
The Company has a 20% ownership share in Colstrip and, in response to SB 1547, has accelerated depreciation of Colstrip to December 31, 2025. In order to meet PGE’s regulatory, legislative, and reliability requirements, the Company continues to evaluate the continuation of its 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:
•establish RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040, for the percentage of electricity that must come from renewable sources;
•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.
PGE expects to meet the 2025 RPS threshold.
EPA Regulations for Electric Generating Facilities—In April 2024, the United States Environmental Protection Agency (EPA) released final regulations pertaining to electric generation facilities. The regulations included:
•GHG regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA). The rule finaliz ed: i) gui delines for GHG emissions from existing fossil fuel-fired steam generating electric units; and ii) revisions to existing performance standards for new, reconstructed, or heavily modified fossil fuel-fired stationary combustion turbine electric generating units.
•Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the ELG Rule), which applied to wastewater discharges from coal-based generating units and established pollution control requirements, building upon the 2015 and 2020 ELG Rules. The rule included a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034.
•Updated Mercury and Air Toxics Standards (MATS), pursuant to section 112 of the CAA, which set emissions limits for filterable particulate matter for coal-based generating units. The rule reduced those limits from the standards that were originally set in 2012.
PGE continues to evaluate each of these rules to assess the impact it may have on the Company’s continuing investment in Colstrip, which could be material. Compliance with the rules would require material upgrades at
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Colstrip with proposed compliance dates that may not be achievable or require the use of unproven technology, resulting in significant impacts to costs of Colstrip. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively, however a substantial number of legal challenges have been filed regarding these rules. In challenges to all three rules, at the EPA’s request, the courts have granted stays to allow new EPA leadership to reevaluate the rule. In a March 2025 press release, the EPA announced that these rules were among several that the EPA will target for reconsideration. On April 8, 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to the CAA Section 112(i)(4) for the Agency’s final rule. The EPA subsequently notified companies whether their sources had been granted the exemption. Colstrip was granted an exemption until July 8, 2029. These challenges, or attempts by the federal government to withdraw or modify the regulations, if successful, could affect the applicability to PGE and Colstrip specifically.
Given the uncertainty surrounding applicability of these laws and regulations, PGE cannot reasonably estimate the impact to its results of operations, financial position, and cash flows, however, if the MATS Rule and GHG Rule are ultimately enforced, it would likely result in additional material compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.
In addition, the regulations include Disposal of Coal Combustion Residuals (CCR) from Electric Utilities – Legacy CCR Surface Impoundments. This rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants, and CCR management units at active and inactive power plants. PGE has assessed the potential impact of the CCR regulation changes and believes it will not hav e a material im pact on the Company’s current Asset Retirement Obligations.
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.
Declared states of emergency—The OPUC has approved a pre-authorized deferral of costs associated with qualifying declared states of emergency, which would include federal or state declared emergencies with impacts on PGE’s service territory. Under this mechanism, PGE could provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency, subject to an earnings test. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including a review of utility prudence in a future proceeding, among other requirements.
Beginning January 13, 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. Along with over a dozen mutual assistance crews, PGE repaired damage and restored power to over 500,000 customers throughout the storm and the days that followed. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to seek recovery of incremental storm expenses through the previously filed emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC under Docket UM 2190 for emergency restoration costs related to the January storm. As of March 31, 2025, PGE had deferred $46 million, including interest, as a regulatory asset for costs associated with repairing damage to transmission and distribution systems and restoring power to customers.
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PGE believes that the full amount of the deferral is probable of recovery and anticipates submitting a request for recovery early in the third quarter of 2025, with price changes to be effective during 2026. The OPUC has significant discretion in making the final determination of recovery based on its determination of prudency and interpretation of the earnings test application, either of which could result in all, or a portion of, the deferral being disallowed. As of December 31, 2024, PGE's preliminary return on equity, based on actual results, did not exceed the OPUC's authorized rate of return. Any disallowance would be a charge to earnings, which could be material to the Company’s financial condition, results of operations, or cash flows. For further information, see “January 2024 storm and damage” in the Regulatory Assets and Liabilities section of Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”
Reliability Contingency Event (RCE)—Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing power cost adjustment mechanism (PCAM). As of March 31, 2025, PGE’s deferred balance related to RCEs was $95 million, which includes $92 million related to RCEs deferred in 2024 and $3 million related to RCEs deferred in 2025. This includes costs from multiple qualified RCEs during 2024, the most significant of which was related to the January storm event, and costs incurred during the first quarter of 2025. PGE files the results of the PCAM annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective January 1 of the following year. RCE costs incurred in 2024 will be included in the PCAM for 2024, which the Company expects to file no later than July 1, 2025. PGE believes the deferred amounts as of March 31, 2025 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
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 2025 AUT included a final increase in power costs for 2025, and a corresponding increase in NVPC, of $72 million from 2024 levels, which were reflected in customer prices effective January 1, 2025.
Portland Harbor Environmental Remediation Account (PHERA) mechanism—The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of March 31, 2025, 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 recovery mechanism allows the Company to defer and recover estimated liabilities and incurred legal and technical analysis 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
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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.”
Renewable recovery framework—As previously authorized by the OPUC, the RAC is a primary method available to recover costs associated with renewable resources and the inclusion of prudent costs of energy storage projects associated with renewables, under certain conditions. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a GRC. In 2023, the Company filed for Clearwater, which went into service January 5, 2024. During 2024, PGE did not submit a request for recovery of any renewable resources under the RAC and has not requested recovery of any renewable resources under the RAC during 2025.
Under the RAC, during 2023, the Company submitted a filing in OPUC Docket UE 427 for Clearwater proposing to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the twelve month period ending December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits resulting in a net regulatory liability of $40 million, which began amortizing as a refund to customers on March 1, 2025 over a twelve month period, as approved in Order 25-075 issued February 21, 2025. The OPUC’s order also adopted conditions to be applied to the AUT and PGE plans to seek clarification of the applicability of those conditions. For the period of January 1, 2025 through February 28, 2025, PGE deferred an additional net $7 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that PGE believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC for that period. The OPUC has significant discretion on overall prudence and in making the final determination of recovery or refund. Any cost disallowance or increased refunds would be recognized as a charge to earnings.
New Large Load—In October 2023, in Docket UE 416, the OPUC directed a docket be opened to investigate new load connection costs and in December 2023, the OPUC established Docket UE 430 for that purpose. Following a lengthy regulatory process, in December 2024, PGE filed Advice No. 24-38 with the OPUC. This filing introduces several proposed changes to PGE policies and tariffs that, if approved, would: i) reasonably protect other customers from the cost to connect new large load customers; ii) improve transmission system planning and capacity; iii) provide fair recovery of distribution investment costs from large load users; and iv) implement contractual requirements designed to appropriately allocate and recover distribution and transmission costs and mitigate the risk of stranded assets, while providing flexibility to meet large customer needs.
On April 15, 2025, the OPUC approved PGE's filing, as revised, with an effective date of April 16, 2025, on condition that the issues raised in the filing would be addressed in a new Commission docket, UM 2377. This allows PGE to begin working with large load customers to form a load interconnection queue, conduct studies to assess and allocate connection costs, and offer study and service agreements. Any agreements with new large load customers may be revised and updated based on the outcome in the separate OPUC proceeding, UM 2377, that was opened to address PGE’s proposed tariff changes and related issues.
Operating Activities
In addition to providing electricity from PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, manage risk, and administer its long-term wholesale contracts, the Company purchases and sells electricity in the wholesale market. To fuel its generation portfolio, the Company purchases natural gas in the United States and Canada and sells excess gas back into the wholesale market. PGE also performs portfolio management and wholesale market sales services for third parties in the region and purchases and sells environmental credits in the wholesale marketplace.
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The Company participates in the California Independent System Operator's (CAISO) western Energy Imbalance Market (EIM), which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. PGE recently signed the implementation agreement and filed tariff changes with the FERC to join the CAISO’s Extended Day-Ahead Market (EDAM). EDAM is expected to build on the success of the western EIM and help provide the Company and its customers access to more affordable, reliable, and clean energy. Utilities that participate in the EDAM, expected to begin operating in 2026, will bid their anticipated energy demand and generating resources into the market a day ahead of expected usage. The EDAM will then optimize generation resources and the energy needed for all market participants, allowing them to receive the least costly and cleanest energy to meet their energy needs. The EDAM is expected to build upon existing technology and systems PGE has deployed and leverages the Company’s transmission system to connect regional resources, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert southwest, across a common market.
In its ongoing effort to benefit retail and wholesale customers, PGE has supported the Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP), since 2023. The WRAP represents a regional framework to more effectively address resource adequacy, enhance reliability, integrate clean energy, and manage costs through resource diversification and capacity sharing across a wide geographic footprint and broad pool of participants across the west.
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. Summer peak deliveries have continued to exceed those of the winter months for nearly ten years, generally resulting from growing air conditioning demand and the trend toward a warmer overall climate. In August 2023, demand reached a new all-time high, surpassing the previous mark, which was set in summer 2021. Historically, PGE had experienced its highest average megawatts (MWa) deliveries and retail energy sales during the winter heating season and recorded its current winter peak load in December 2022. Summer peak deliveries in each year since 2021 have exceeded that winter peak.
Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to enhance the availability of supply chain-constrained items that are needed to serve new and existing customers, such as securing inventory of critical materials to improve reliability, reserving manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. The Company’s materials and supplies forecasting process is designed to secure materials availability as well as mitigate cost increases through long-term agreements, supplier engagement, and expanding the supply base. PGE is monitoring the fluid situation around tariffs and trade policies and continues to evaluate any potential impact to its operations and the need to implement applicable mitigation strategies.
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Customers and Demand—The following tables present total energy deliveries, in thousands of Megawatt hours (MWh), and the average number of retail customers by customer type for the periods indicated:

|  |  |  | Three Months Ended March 31, |
|  |  |  |  |  |  |  | 2025 |  | 2024 | % Change | % Change (Weather- Adjusted) |
Energy deliveries: |  |  |  |  |  |  |  |  |  |  |
Retail: |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  |  |  |  |  |  | 2,226 |  |  | 2,243 |  | (1) | % | (1) | % |
Commercial |  |  |  |  |  |  |  | 1,632 |  |  | 1,628 |  | — |  | — |  |
Industrial |  |  |  |  |  |  |  | 1,398 |  |  | 1,186 |  | 18 |  | 18 |  |
Subtotal |  |  |  |  |  |  |  | 5,256 |  |  | 5,057 |  | 4 |  | 4 |  |
Direct access: |  |  |  |  |  |  |  |  |  |  |  |  |
Commercial |  |  |  |  |  |  |  | 129 |  |  | 120 |  | 8 |  | 8 |  |
Industrial |  |  |  |  |  |  |  | 443 |  |  | 396 |  | 12 |  | 12 |  |
Subtotal |  |  |  |  |  |  |  | 572 |  |  | 516 |  | 11 |  | 11 |  |
Total retail |  |  |  |  |  |  |  | 5,828 |  |  | 5,573 |  | 5 |  | 4 | % |
Wholesale |  |  |  |  |  |  |  | 1,979 |  |  | 2,179 |  | (9) |  |  |
Total |  |  |  |  |  |  |  | 7,807 |  |  | 7,752 |  | 1 | % |  |

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Average number of retail customers: |  |  |  |  |  |  |  |  |
Residential |  |  |  |  |  |  | 837,109 |  | 88 | % |  | 824,239 | 88 | %
Commercial |  |  |  |  |  |  | 114,191 |  | 12 |  |  | 112,869 | 12 |
Industrial |  |  |  |  |  |  | 216 |  | — |  |  | 204 | — |
Direct access |  |  |  |  |  |  | 589 |  | — |  |  | 514 | — |
Total |  |  |  |  |  |  | 952,105 |  | 100 | % |  | 937,826 |  | 100 | %

Total retail energy deliveries for the three months ended March 31, 2025 increased 4.6% compared with the three months ended March 31, 2024, driven by an increase in industrial deliveries. The first quarter of 2025 contained one fewer delivery day due to leap year in 2024.
Residential weather-adjusted deliveries saw average usage per customer 2.5% lower during the first three months of 2025 compared with 2024, while the average number of residential customers was 1.6% greater. PGE has seen the number of rooftop solar installations increase in its service territory over the past few years, and continued funding of energy efficiency programs, both of which weigh on average usage per customer.
The industrial class continues to show growth in energy deliveries, up 16.4% in the three months ended March 31, 2025 compared to the same period in 2024, reflecting strength in the high-tech manufacturing and digital services sectors.
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The following table indicates the number of heating degree-days for the three months ended March 31, 2025 and 2024, 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 |  |
| 2025 |  | 2024 |  | Avg. |  |  |  |  |  |
January | 725 |  |  | 759 |  |  | 703 |  |  |  |  |  |  |
February | 613 |  |  | 539 |  |  | 597 |  |  |  |  |  |  |
March | 434 |  |  | 457 |  |  | 519 |  |  |  |  |  |  |
Year-to-date | 1,772 |  |  | 1,755 |  |  | 1,819 |  |  |  |  |  |  |
(Decrease) from the 15-year average | (3) | % |  | (4) | % |  |  |  |  |  |  |  |

During the three months ended March 31, 2025 compared to the same three months of 2024, weather had a modest positive impact on Total Retail deliveries. While temperatures were slightly above average during the first quarters of both 2025 and 2024, the number of heating degree-days recorded in 2025 were 3% below average compared to 4% below in the same period of 2024.
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, 11% of PGE’s total retail energy deliveries for the first three months of 2025 would have been to these customers.
PGE offers service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 16% of the Company’s energy deliveries could have been supplied by ESSs to Direct Access customers. Actual deliveries to Direct Access customers of energy supplied by ESSs represented 10% of PGE’s total retail energy deliveries for the first three months of 2025 and 2024. The OPUC, under docket UM 2024, has undertaken an investigation of long-term of Direct Access with program caps being one of the issues under consideration. This regulatory proceeding is expected to conclude in early 2026.
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, natural gas, and environmental credits 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 three months ended March 31, 2025 and 2024:

| Plant availability (1) |  | Actual energy provided compared to projected levels (2) |  | Actual energy provided as a percentage of total system load |  |  |  |  |
| 2025 | 2024 |  |  | 2025 | 2024 |  | 2025 | 2024 |  |  |  |  |
Generation: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Thermal: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | 92 | % | 89 | % |  |  | 105 | % | 110 | % |  | 41 | % | 40 | % |  |  |  |  |
Coal (3) | 92 |  | 85 |  |  |  | 94 |  | 93 |  |  | 7 |  | 7 |  |  |  |  |  |
Wind (4) | 92 |  | 92 |  |  |  | 88 |  | 84 |  |  | 8 |  | 8 |  |  |  |  |  |
Hydro | 99 |  | 96 |  |  |  | 114 |  | 97 |  |  | 6 |  | 5 |  |  |  |  |  |

(1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability reflects Colstrip, which PGE does not operate.
(4)Plant availability includes Wheatridge Renewable Energy Facility and Clearwater, which PGE does not operate.
Energy received from PGE-owned and jointly-owned thermal plants during the three months ended March 31, 2025 compared to 2024 increased 3%. This increase was primarily driven by fewer outages in 2025 as compared to 2024. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.
Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 12% during the three months ended March 31, 2025 compared to 2024 primarily due to more favorable hydro conditions in the current period. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 12% while energy generated by the Company-owned facilities increased 12% during the three months ended March 31, 2025. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 10 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 and under contract wind resources decreased 1% during the three months ended March 31, 2025 compared to 2024. 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 the 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 PCAM as calculated for regulatory purposes for the three months ended March 31, 2025 and 2024, respectively:
•For the three months ended March 31, 2025, actual NVPC was $6 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2025 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 10.34%, there is no estimated refund to customers expected under the PCAM for 2025.
•For the three months ended March 31, 2024, actual NVPC was $19 million below baseline NVPC. For the year ended December 31, 2024, actual NVPC was $78 million below baseline NVPC, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE was below 10.5%, there was no estimated refund to customers under the PCAM for 2024. A final determination regarding the 2024 PCAM results will be made by the OPUC through a public filing and review in 2025.
As approved by the OPUC in PGE’s 2024 GRC, the Reliability Contingency Event (RCE) mechanism allows PGE to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. For more on the 2024 RCE, see “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”
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Results of Operations
The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations.
The results of operations are as follows for the periods presented (dollars in millions):

|  |  |  |  |  |  | Three Months Ended March 31, |  | % Increase (Decrease) |  |
|  |  |  |  |  |  |  |  |  | 2025 |  | 2024 |  |  |
Total revenues |  |  |  |  |  |  |  |  |  |  | $ | 928 |  |  |  |  | $ | 929 |  |  | — | % |  |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased power and fuel |  |  |  |  |  |  |  |  |  |  | 368 |  |  |  |  | 405 |  |  | (9) |  |  |
Generation, transmission and distribution |  |  |  |  |  |  |  |  |  |  | 110 |  |  |  |  | 99 |  |  | 11 |  |  |
Administrative and other |  |  |  |  |  |  |  |  |  |  | 96 |  |  |  |  | 95 |  |  | 1 |  |  |
Depreciation and amortization |  |  |  |  |  |  |  |  |  |  | 140 |  |  |  |  | 121 |  |  | 16 |  |  |
Taxes other than income taxes |  |  |  |  |  |  |  |  |  |  | 46 |  |  |  |  | 47 |  |  | (2) |  |  |
Total operating expenses |  |  |  |  |  |  |  |  |  |  | 760 |  |  |  |  | 767 |  |  | (1) |  |  |
Income from operations |  |  |  |  |  |  |  |  |  |  | 168 |  |  |  |  | 162 |  |  | 4 |  |  |
Interest expense, net* |  |  |  |  |  |  |  |  |  |  | 56 |  |  |  |  | 51 |  |  | 10 |  |  |
Other income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Allowance for equity funds used during construction |  |  |  |  |  |  |  |  |  |  | 5 |  |  |  |  | 5 |  |  | — |  |  |
Miscellaneous income, net |  |  |  |  |  |  |  |  |  |  | 5 |  |  |  |  | 6 |  |  | (17) |  |  |
Other income, net |  |  |  |  |  |  |  |  |  |  | 10 |  |  |  |  | 11 |  |  | (9) |  |  |
Income before income tax expense |  |  |  |  |  |  |  |  |  |  | 122 |  |  |  |  | 122 |  |  | — |  |  |
Income tax expense |  |  |  |  |  |  |  |  |  |  | 22 |  |  |  |  | 13 |  |  | 69 |  |  |
Net income |  |  |  |  |  |  |  |  |  |  | 100 |  |  |  |  | 109 |  |  | (8) |  |  |
Other comprehensive income |  |  |  |  |  |  |  |  |  |  | — |  |  |  |  | 1 |  |  | (100) |  |  |
Net income and Comprehensive income |  |  |  |  |  |  |  |  |  |  | $ | 100 |  |  |  |  | $ | 110 |  |  | (9) | % |  |

* Includes an allowance for borrowed funds used during construction of $4 million for both the three months ended March 31, 2025 and 2024.
Net income for the three months ended March 31, 2025 decreased $9 million, or 8%, compared to the same period of 2024. Retail revenues increased primarily due to price changes to cover anticipated higher NVPC and general cost increases, as authorized by the OPUC. Wholesale revenues have decreased, driven by a 50% decline in the average price of wholesale deliveries. The reduction in Purchased power and fuel reflects reduced cost of purchased power, partially offset by the reduced costs in 2024 due to the deferral of costs under the RCE mechanism that did not recur. Generation, transmission and distribution expenses were up primarily due to vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses. Increases in Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, were largely anticipated and somewhat offset in net income by increased revenues. Income tax expense was up due to lower PTC benefits.
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Total revenues consist of the following for the periods presented (dollars in millions):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Retail: |  |  |  |  |  |  |  |  |  |  |
Residential |  |  |  |  |  |  | $ | 429 |  | 46 | % |  | $ | 415 |  | 45 | %
Commercial |  |  |  |  |  |  | 242 |  | 26 |  |  | 227 |  | 24 |
Industrial |  |  |  |  |  |  | 127 |  | 14 |  |  | 102 |  | 11 |
Subtotal |  |  |  |  |  |  | 798 |  | 86 |  |  | 744 |  | 80 |
Direct access: |  |  |  |  |  |  |  |  |  |  |
Commercial |  |  |  |  |  |  | 4 |  | — |  |  | 2 |  | — |
Industrial |  |  |  |  |  |  | 5 |  | 1 |  |  | 4 |  | 1 |
Subtotal |  |  |  |  |  |  | 9 |  | 1 |  |  | 6 |  | 1 |
Subtotal Retail |  |  |  |  |  |  | 807 |  | 87 |  |  | 750 |  | 81 |
Alternative revenue programs, net of amortization |  |  |  |  |  |  | (4) |  | — |  |  | (11) |  | (1) |
Other accrued revenues, net |  |  |  |  |  |  | 4 |  | — |  |  | 1 |  | — |
Total retail revenues |  |  |  |  |  |  | 807 |  | 87 |  |  | 740 |  | 80 |
Wholesale revenues |  |  |  |  |  |  | 100 |  | 11 |  |  | 176 |  | 19 |
Other operating revenues |  |  |  |  |  |  | 21 |  | 2 |  |  | 13 |  | 1 |
Total revenues |  |  |  |  |  |  | $ | 928 |  | 100 | % |  | $ | 929 |  | 100 | %

Total retail revenues—The following items contributed to the increase in Total retail revenues for the three months ended March 31, 2025 compared to the same period in 2024 (in millions):

|  |  | Three Months Ended |
March 31, 2024 |  |  | $ | 740 |  |
Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel) |  |  | 50 |  |
Retail energy deliveries driven by changes in customer load |  |  | 21 |  |
Clearwater RAC deferral |  |  | 5 |  |
Average price of energy deliveries due primarily to changes in delivery mix, partially offset by overall customer price increases beyond the AUT |  |  | (19) |  |
Combination of various supplemental schedules and adjustments |  |  | 10 |  |
March 31, 2025 |  |  | 807 |  |
Change in Total retail revenues |  |  | $ | 67 |  |

Wholesale revenues result from sales of electricity and environmental credits to utilities and power marketers made in the Company’s efforts to meet the needs of, and obtain 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.
For the three months ended March 31, 2025, Wholesale revenues decreased $76 million, or 43%, from the three months ended March 31, 2024 as the Company experienced a 50% decline in average sales prices resulting from market volatility around specific regional weather events in January 2024 and milder overall weather in 2025 combined with a 9% reduction in sales volumes due largely to milder weather and lower natural gas prices, along with a $5 million reduction in sales of environmental credits.
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Other operating re venues for the three months ended March 31, 2025 were up $8 million from the comparable period in 2024, primarily the result of an increase in revenues resulting from imbalance transactions with ESS providers.
Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts.
The following items contributed to the change in Purchased power and fuel for the three months ended March 31, 2025 compared to the same period in 2024 (dollars in millions, except for average variable power cost per Megawatt hour (MWh):

|  |  | Three Months Ended
March 31, 2024 |  |  | $ | 405 |
Average variable power cost per MWh |  |  | (85) |
Total system load |  |  | (20) |
2021 PCAM deferral amortization |  |  | (4) |
RCE deferral |  |  | 72 |
March 31, 2025 |  |  | 368 |
Change in Purchased power and fuel |  |  | $ | (37) |
Average variable power cost per MWh: |  |  |
March 31, 2024 |  |  | $ | 62.58 |
March 31, 2025 |  |  | $ | 49.23 |
Total system load (MWhs in thousands): |  |  |
March 31, 2024 |  |  | 7,610
March 31, 2025 |  |  | 7,543

For the three months ended March 31, 2025, the $85 million decrease related to the change in average variable power cost per MWh was driven by a 26% decrease in the average cost of purchased power and a less than 1% decrease in the average cost for the Company’s own generation. The $20 million decrease related to total system load was comprised of an 7% decrease of energy obtained from purchased power, offset by a 3% increase in the Company’s own generation.
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PGE’s sources of energy, total system load, and retail load requirement are as follows for the periods presented (MWhs in thousands):

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Generation: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Thermal: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  |  |  |  |  |  |  |  | 3,117 |  |  | 41 | % |  | 3,028 |  |  | 40 | %
Coal |  |  |  |  |  |  |  |  | 533 |  |  | 7 |  |  | 526 |  |  | 7 |
Total thermal |  |  |  |  |  |  |  |  | 3,650 |  |  | 48 |  |  | 3,554 |  |  | 47 |
Hydro |  |  |  |  |  |  |  |  | 442 |  |  | 6 |  |  | 393 |  |  | 5 |
Wind |  |  |  |  |  |  |  |  | 599 |  |  | 8 |  |  | 590 |  |  | 8 |
Total generation |  |  |  |  |  |  |  |  | 4,691 |  |  | 62 |  |  | 4,537 |  |  | 60 |
Purchased power: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hydro |  |  |  |  |  |  |  |  | 1,748 |  |  | 23 |  |  | 1,564 |  |  | 21 |
Wind |  |  |  |  |  |  |  |  | 289 |  |  | 4 |  |  | 306 |  |  | 4 |
Solar |  |  |  |  |  |  |  |  | 174 |  |  | 2 |  |  | 147 |  |  | 1 |
Natural Gas |  |  |  |  |  |  |  |  | — |  |  | — |  |  | 94 |  |  | 1 |
Waste, Wood, and Landfill Gas |  |  |  |  |  |  |  |  | 25 |  |  | — |  |  | 39 |  |  | 1 |
Source not specified |  |  |  |  |  |  |  |  | 616 |  |  | 9 |  |  | 923 |  |  | 12 |
Total purchased power |  |  |  |  |  |  |  |  | 2,852 |  |  | 38 |  |  | 3,073 |  |  | 40 |
Total system load |  |  |  |  |  |  |  |  | 7,543 |  |  | 100 | % |  | 7,610 |  |  | 100 | %
Less: wholesale sales |  |  |  |  |  |  |  |  | (1,979) |  |  |  |  | (2,179) |  |  |
Retail load requirement |  |  |  |  |  |  |  |  | 5,564 |  |  |  |  | 5,431 |  |  |

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

|  |  | Three Months Ended March 31,
|  |  |  |  | 2025 |  | 2024
Sources of energy (MWhs in thousands): |  |  |  |  |  |  |
PURPA purchased power: |  |  |  |  |  |  |
Hydro |  |  |  |  | 10 |  |  | 11 |
Wind |  |  |  |  | 4 |  |  | 5 |
Solar |  |  |  |  | 96 |  |  | 91 |
Waste, Wood, and Landfill Gas |  |  |  |  | 25 |  |  | 28 |
Total |  |  |  |  | 135 |  |  | 135 |

The following table presents the forecast April-to-September 2025 and actual 2024 runoff at particular points of major rivers relevant to PGE’s hydro resources:

| Runoff as a Percent of Normal*
Location | 2025 Forecast |  | 2024 Actual
Columbia River at The Dalles, Oregon | 90 | % |  | 74 | %
Mid-Columbia River at Grand Coulee, Washington | 91 |  |  | 74 |
Clackamas River at Estacada, Oregon | 90 |  |  | 91 |
Deschutes River at Moody, Oregon | 103 |  |  | 93 |

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* 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 months ended March 31, 2025 increased compared to the same period in 2024 as follows (in millions):

|  |  | Three Months Ended
March 31, 2024 |  |  | $ | 229 |
Purchased power and fuel expense |  |  | (105) |
Wholesale revenues |  |  | 76 |
2021 PCAM deferral amortization |  |  | (4) |
RCE deferral |  |  | 72 |
March 31, 2025 |  |  | $ | 268 |
Change in NVPC |  |  | $ | 39 |

For further information regarding NVPC in relation to the PCAM, see “Purchased power and fuel expense” and “Revenues” within this “Results of Operations” for more details.
For the three months ended March 31, 2025 and 2024, actual NVPC was $6 million and $19 million below baseline NVPC, respectively.
Based on forecast data, NVPC for the year ending December 31, 2025 is currently estimated to be below the baseline and outside the deadband. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE is estimated to be below 10.34%, there is no estimated refund to customers expected under the PCAM for 2025.
Generation, transmission, distribution increased as follows for the three months ended March 31, 2025 compared to the same period in 2024 (in millions):

|  |  | Three Months Ended
March 31, 2024 |  |  | $ | 99 |
Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses |  |  | 7 |
Service restoration and storm response costs |  |  | 4 |
March 31, 2025 |  |  | $ | 110 |
Change in Generation, transmission and distribution |  |  | $ | 11 |

In the table above, $3 million related to vegetation management, $4 million related to wildfire mitigation, and $4 million related to storm response costs have been offset through customer prices or specific regulatory mechanisms.
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Administrative and other increased as follows for the three months ended March 31, 2025 compared to the same period in 2024 (in millions):

|  |  | Three Months Ended
March 31, 2024 |  |  | $ | 95 |
Regulatory and Professional services costs |  |  | 5 |
Employee compensation and benefits |  |  | 8 |
Customer related costs |  |  | (6) |
Miscellaneous expenses |  |  | (6) |
March 31, 2025 |  |  | $ | 96 |
Change in Administrative and other |  |  | $ | 1 |

In the table above, $5 million of the decrease in customer related costs is due to regulatory programs that have been offset through customer pricing or specific regulatory mechanisms.
Depreciation and amortization expense increased $19 million in the three months ended March 31, 2025, compared to the same period in 2024. The increase was primarily due to higher utility plant balances.
Taxes other than income taxes decreased $1 million in the three months ended March 31, 2025, compared to the same period in 2024. The decrease was driven by lower payroll taxes partially offset by higher franchise fees.
Interest expense, net increased $5 million in the three months ended March 31, 2025 compared to the same period in 2024, primarily due to higher long-term debt balances.
Other income, net decreased $1 million for the three months ended March 31, 2025, compared to the same period in 2024. The decrease was primarily driven by lower non-qualified plan asset investment performance slightly offset by higher AFUDC from higher CWIP balances.
Income tax expense increased $9 million in the three months ended March 31, 2025, compared to the same period in 2024, primarily driven by lower PTC benefits resulting from the expiration of the 10-year PTC generation window at Tucannon near the end of 2024.
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, 2024, filed with the SEC on February 14, 2025.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.
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The following summarizes PGE’s cash flows for the periods presented (in millions):

| Three Months Ended March 31,
| 2025 |  | 2024
Cash and cash equivalents, beginning of period | $ | 12 |  |  | $ | 5 |
Net cash provided by (used in): |  |  |
Operating activities | 231 |  |  | 175 |
Investing activities | (376) |  |  | (331) |
Financing activities | 144 |  |  | 327 |
Increase (decrease) in cash and cash equivalents | (1) |  |  | 171 |
Cash and cash equivalents, end of period | $ | 11 |  |  | $ | 176 |

Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the three months ended March 31, 2025 compared with the three months ended March 31, 2024 (in millions):

| Increase/ (Decrease)
Net income | $ | (9) |
Accounts receivable and Unbilled revenue | (20) |
Margin deposits activity | 33 |
Accounts payable | (61) |
Regulatory deferral activity | 110 |
Depreciation and amortization | 19 |
Deferred income taxes | (17) |
Tax credit sales | 2 |
Alternative revenue programs | (7) |
Other miscellaneous changes | 6 |
Net change in cash flow from operations | $ | 56 |

PGE estimates that non-cash charges for depreciation and amortization in 2025 will range from $550 million to $575 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $900 million to $1 billion.
Cash Flows from Investing Activities—Net cash used in investing activities for the three months ended March 31, 2025 increased $45 million when compared with the three months ended March 31, 2024. Cash flows used in investing activities consist primarily of capital expenditures related to BESS projects and other new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $34 million.
Excluding AFUDC, the Company plans to make capital expenditures of $1.3 billion in 2025, which it expects to fund with cash to be generated from operations during 2025, as discussed above, the issuance of short- and long-term debt, and issuances of shares pursuant to the at-the-market offering program. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.
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Cash Flows from Financing Activities—During the three months ended March 31, 2025, net cash provided by financing activities was primarily the result of the funding of $310 million in First Mortgage Bonds (FMBs). This was partially offset by payment of $55 million of dividends and $102 million of long-term debt.
Capital Requirements
The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2025 through 2029, excluding AFUDC (in millions):

| 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029
Ongoing capital expenditures (1) | $ | 860 |  |  | $ | 895 |  |  | $ | 890 |  |  | $ | 920 |  |  | $ | 920 |
Transmission | 240 |  |  | 255 |  |  | 390 |  |  | 420 |  |  | 515 |
BESS projects | 165 |  |  | — |  |  | — |  |  | — |  |  | — |
Total capital expenditures (2) | $ | 1,265 |  |  | $ | 1,150 |  |  | $ | 1,280 |  |  | $ | 1,340 |  |  | $ | 1,435 |
Long-term debt maturities | $ | 68 |  |  | $ | — |  |  | $ | 160 |  |  | $ | 100 |  |  | $ | 200 |

(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 2025, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $900 million to $1 billion, and issuances of long-term debt of up to $450 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.
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Short-term Debt. Pursuant to an order issued by the FERC in January 2024, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2026. The following table shows available liquidity as of March 31, 2025 (in millions):

| As of March 31, 2025
| Capacity |  | Outstanding |  | Available
Revolving credit facility (1) | $ | 750 |  |  | $ | — |  |  | $ | 750 |
Letters of credit (2) | 320 |  |  | 133 |  |  | 187 |
Total credit | $ | 1,070 |  |  | $ | 133 |  |  | $ | 937 |
Cash and cash equivalents |  |  |  |  | 11 |
Total liquidity |  |  |  |  | $ | 948 |

(1)Scheduled to expire September 2029.
(2)P GE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.
On September 10, 2024, PGE entered into an amendment of its existing revolving credit facility. As of March 31, 2025, PGE had a $750 million unsecured revolving credit facility scheduled to expire in September 2029. The Company has the ability to expand the revolving credit facility to $850 million, if needed, subject to the requirements of the agreement. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may borrow for one, 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 March 31, 2025, 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 March 31, 2025, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $750 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.
Long-term Debt. As of March 31, 2025, PGE’s total long-term debt outstanding, net of $16 million of unamortized debt expense, was $4,731 million.
On March 25, 2025, PGE entered into a Bond Purchase Agreement related to the sale of $310 million in First Mortgage Bonds (FMBs). The Bonds were issued and funded in full on March 25, 2025 and consist of:
•a series, due in 2035, in the amount of $60 million that will bear interest from its issuance date at an annual rate of 5.36%;
•a series, due in 2045, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 5.72%; and
•a series, due in 2055, in the amount of $200 million that will bear interest from its issuance date at an annual rate of 5.84%.
On November 14, 2024, PGE drew a $220 million loan under a 366-day term loan agreement. On December 31, 2024, PGE repaid $50 million of the term loan and, on March 31, 2025, the Company repaid another $102 million, leaving an outstanding balance of $68 million.
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Equity—In July 2024, PGE entered into an equity distribution agreement under which it could sell up to $400 million of its common stock through at-the-market offering programs. In the fourth quarter of 2024 the Company entered into forward sale agreements for 1,420,049 shares. In December 2024, the Company issued 1,066,549 shares pursuant to the forward sale agreements and received net proceeds of $50 million. In the first quarter of 2025 the Company entered into forward sale agreements for 1,996,890 shares. The Company could have physically settled the remaining amount by delivering 2,350,390 shares in exchange for cash of $104 million as of March 31, 2025. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.
For additional information on the at-the-market offering programs, 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 44.8% and 45.6% as of March 31, 2025 and December 31, 2024 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 | Negative |  | Stable

In June 2024, Moody’s revised the Company’s outlook from Stable to Negative. This change is not expected to have a material impact on the Company’s liquidity or collateral obligations.
In the event Moody’s or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits in PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.
As of March 31, 2025, PGE had posted $136 million of collateral with these counterparties, consisting of $70 million in cash and $66 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2025, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $98 million, and decreases to $40 million by December 31, 2025 and to $1 million by December 31, 2026. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $193 million and decreases to $102 million by December 31, 2025 and to $58 million by December 31, 2026.
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PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facilities would increase.
The indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2025, under the most restrictive issuance test in the Indenture, the Company could have issued up to $551 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.
PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of March 31, 2025, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 55.2%.

Item 3. | Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations, or cash flows. There have been no material changes to market risks, or credit risk, affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 14, 2025.

Item 4. | Controls and Procedures.

Disclosure Controls and Procedures
PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2025, these disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting
There were no changes in PGE’s internal control over financial reporting that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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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.

Other than the item noted below, 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, 2024, filed with the SEC on February 14, 2025.
Trade tariffs and related market volatility and supply chain disruptions could increase PGE’s operating costs, impair PGE’s ability to complete capital projects, and impede access to capital markets.
Recently imposed trade tariffs could negatively impact PGE’s financial condition, results of operations, and cash flows. While the impact of these trade tariffs is difficult to predict at this time, economic volatility, supply chain disruption, or cost increases triggered by these trade tariffs could negatively affect PGE’s ability to execute its strategic plan. Adverse capital and credit market conditions caused by the new trade tariffs could negatively affect the Company’s access to capital, cost of capital, and ability to complete capital projects.

Item 5. | Other Information.

Rule 10b5-1 Trading Arrangements
During the three months ended March 31, 2025, the following director (as defined in Rule 16a-1(f) of the Exchange Act) adopted a “Rule 10b5-1 trading agreement,” as the term is defined in Item 408(c) of Regulation S-K:

Name (Title) |  | Action Taken (Date of Action) |  | Type of Trading Arrangement |  | Duration of Trading Arrangement |  | Aggregate Number of Securities to be Purchased or Sold*
Michael Lewis (Board Director) |  | Adoption (February 20, 2025) |  | Rule 10b5-1 trading arrangement |  | Until March 19, 2026, or such earlier date upon which all transactions are completed or expire without execution |  | Up to 1,564 shares of common stock

* Estimated. Board members receive stock grants annually in July that vest immediately. Mr. Lewis plans to sell 50% of the shares awarded to him in July 2025. For reference, 50% of his 2024 grant would have been 1,564 shares.
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Item 6. | Exhibits.

Exhibit Number | Description
3.1 | Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2 | Twelfth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q filed October 27, 2023).
31.1 | Certification of Chief Executive Officer.
31.2 | Certification of Chief Financial Officer.
32 | Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS | XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH | XBRL Taxonomy Extension Schema Document.
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB | XBRL Taxonomy Extension Label Linkbase Document.
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document.
104 | Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed April 25, 2025, formatted in iXBRL (Inline Extensible Business Reporting Language).

Certain instruments defining the rights of holders of other long-term debt of the Company are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  |  | PORTLAND GENERAL ELECTRIC COMPANY
|  |  | (Registrant)
Date: | April 24, 2025 |  | By: | /s/ Joseph R. Trpik
|  |  |  | Joseph R. Trpik
|  |  |  | Senior Vice President, Finance and Chief Financial Officer
|  |  |  | (duly authorized officer and principal financial officer)

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