Portland General Electric Co (POR)

PART I

ITEM 1. BUSINESS.

General

Portland General Electric Company (PGE or the Company), a vertically-integrated electric utility with corporate headquarters located in Portland, Oregon, is engaged in the generation, wholesale purchase and sale, transmission, distribution, and retail sale of electricity to customers in the state of Oregon (State). The Company operates as a cost-based, regulated electric utility with revenue requirements and customer prices determined based on the forecasted cost to serve retail customers and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). PGE meets its retail load requirement with both Company-owned generation and power purchased in the wholesale market. The Company participates in the wholesale market through the purchase and sale of electricity, natural gas, and environmental credits in an effort to obtain reasonably-priced power to serve its retail customers, manage risk, and administer its long-term wholesale contracts. PGE, incorporated in 1930, is publicly-owned, with its common stock listed on the New York Stock Exchange (NYSE). The Company operates as a single business segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE owns unregulated, non-utility property that it utilizes for its corporate headquarters.

PGE’s State-approved service area allocation of 4,000 square miles is located entirely within Oregon and includes 51 incorporated cities. During 2025, the Company added 10,000 customers, and as of December 31, 2025, served a total of approximately 960,000 retail customers.

Available Information

PGE’s periodic and current reports, and amendments to those reports, are available and may be accessed free of charge through the Investors section of the Company’s website at PortlandGeneral.com as soon as reasonably practicable after the reports are electronically filed with, or furnished to, the United States Securities and Exchange Commission (SEC). It is not intended that PGE’s website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K.

Regulation

Federal and State regulation each have a significant influence on PGE’s business operations. In addition to the agencies and activities discussed below, the Company is subject to regulation by certain environmental agencies, as described in the Environmental Matters section in this Item 1.

Regulatory Accounting

PGE prepares financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) and, as a regulated public utility, the effects of rate regulation are reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as: i) property, plant, and equipment; ii) regulatory assets and liabilities; iii) revenues; iv) certain operating expenses; v) depreciation expense; and vi) income tax expense. GAAP provides for the deferral, or recording of expenses and revenues in periods other than when an unregulated entity would. As a result, the Company may record regulatory assets, of certain actual or estimated costs that would otherwise be charged to expense, based on expected recovery from customers in future prices. Likewise, certain actual or anticipated credits that would otherwise be recognized as revenue, or reduce expense, can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

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The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future regulatory environment and related accounting guidance. For additional information, see “Regulatory Assets and Liabilities” in Note 2, Summary of Significant Accounting Policies, and Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Federal Regulation

Multiple federal agencies, including the Federal Energy Regulatory Commission (FERC), the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), and the Nuclear Regulatory Commission (NRC), may have regulatory authority over certain aspects of PGE’s operations and activities, as further described in the paragraphs that follow.

PGE is a “licensee,” a “public utility,” and a “user, owner, and operator of the bulk power system,” as those terms are defined in the Federal Power Act (FPA). As such, the Company is subject to regulation by the FERC in matters related to wholesale energy activities, transmission services, reliability and cybersecurity standards, natural gas pipelines, hydroelectric projects, accounting policies and practices, short-term debt issuances, and certain other matters.

Wholesale Energy—PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales in all markets in which it sells electricity except in its own Balancing Authority Area (BAA). The BAA is the area in which PGE is responsible for balancing customer demand with electricity supply, in real time, and the tariff exception within PGE’s BAA does not have a material impact on the Company.

Transmission—PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the FERC.

Reliability and Cybersecurity Standards—The FERC has adopted mandatory reliability standards for owners, users, and operators of the bulk power system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of these standards, and are intended to help maintain and strengthen the reliable planning and operation of the bulk power system.

Natural Gas Pipelines—The FERC has authority in matters related to the construction, operation, extension, enlargement, safety, and abandonment of jurisdictional interstate natural gas pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority as the Company has a 79.5% ownership interest in the Kelso-Beaver (KB) Pipeline, a 17-mile, 20-inch diameter, interstate pipeline that provides natural gas to the Company’s three natural gas-fired generating plants located near Clatskanie, Oregon: i) Port Westward Unit 1 (PW1); ii) Port Westward Unit 2 (PW2), and iii) Beaver. In addition, the KB Pipeline serves the North Mist storage facility, which is owned and operated by a local natural gas distribution company, and one additional delivery point for a local manufacturing concern. As the operator of record of the KB Pipeline, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety and operator qualification standards and public awareness requirements.

Hydroelectric Licensing—As required under the FPA, PGE holds FERC licenses for all Company-owned and operated hydroelectric generating plants. The FERC license process includes an extensive public review that involves the consideration of numerous natural resource issues and environmental conditions. For additional information, see the Environmental Matters section in this Item 1. and the Generating Facilities section in Item 2.—“Properties.”

Accounting Policies and Practices—PGE prepares periodic and current reports in accordance with GAAP. In addition, the Company prepares, pursuant to applicable provisions of the FPA, financial statements in accordance with the accounting requirements of the FERC, as set forth in its applicable Uniform System of Accounts and published accounting releases. Such financial statements are included in annual and quarterly reports filed with the FERC.

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Short-term Debt—Pursuant to applicable provisions of the FPA and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. For additional information on the Company’s Short-term Debt, see “Short-term Debt” in the Debt and Equity section of Liquidity and Capital Resources in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Spent Fuel Storage—The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. For additional information on spent nuclear fuel storage activities, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” and “Hazardous Material” in the Environmental Matters section of this Item 1.

State Regulation

PGE is subject to the jurisdiction of the OPUC, which reviews and approves the Company’s retail prices and reviews the Company’s generation and transmission resource acquisition plans, pursuant to a biennial integrated resource planning process. In addition, PGE is required to develop a Clean Energy Plan (CEP) to be filed in connection with the Company’s Integrated Resource Plan (IRP) that articulates the Company’s strategy to show continued progress toward emission reduction targets through an equitable transition to a decarbonized grid. The OPUC also regulates the issuance of securities, prescribes accounting policies and practices, regulates the sale of utility assets, reviews transactions with affiliated companies, and has jurisdiction over the acquisition of, or exertion of substantial influence over, public utilities.

Retail customer prices are determined through formal public proceedings that generally include testimony by participating parties, discovery, public hearings, and the issuance of a final order by the OPUC. Participants in such proceedings may include PGE, OPUC staff, and intervenors representing PGE customer groups, as well as other interested parties. The following lists the more significant regulatory mechanisms and proceedings under which customer prices are determined:

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General Rate Cases (GRCs). PGE periodically evaluates the need to update its retail electric price structure as part of a comprehensive GRC process that reflects revenue requirements based on a forecasted test year. The OPUC authorizes the Company’s rate base, debt-to-equity capital structure, return on equity, overall rate of return, and customer prices.

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Annual Power Cost Updates. The OPUC has approved an Annual Power Cost Update Tariff (AUT) by which PGE can adjust retail customer prices annually to reflect forecasted changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased in the wholesale market and fuel the Company uses to generate electricity, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s consolidated statements of income). NVPC is net of wholesale revenues as well as gains and losses on the sale of excess natural gas, included in other operating revenue, that is not used to fuel PGE’s generation facilities, both of which are classified as Revenues, net in the consolidated statements of income. The OPUC has also authorized a Power Cost Adjustment Mechanism (PCAM), under which PGE may share with customers a portion of actual cost variances associated with NVPC.

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Renewable Adjustment Clause mechanism. The State has a Renewable Portfolio Standard (RPS) that requires PGE to serve a portion of its retail load with renewable resources. In conjunction with the RPS, the State established a Renewable Adjustment Clause (RAC) mechanism that allows for the recovery in retail customer prices, outside of a GRC, of prudently incurred costs to comply with the RPS.

In 2016, the State passed Oregon Senate Bill (SB) 1547, which, among its provisions, increased the RPS percentages in certain future years and required the elimination of coal from Oregon utility customers’ energy supply. For further information on SB 1547, see “RPS standards and related laws” in the

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Financial statements

data from SEC XBRL filings. Values are as-reported; restatements supersede originals. Values reported in .

From 10-Q filed 2026-10-29 (period ending 2026-09-30).

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, risks, uncertainties and other important factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:

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new or revised governmental policies, executive orders, legislative actions, and regulatory audits, investigations, and actions, including those of the Federal Energy Regulatory Commission (FERC), the Public Utility Commission of Oregon (OPUC), and the Internal Revenue Service (IRS), 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, the formation of a holding company, energy trading activities, tax credits, and current or prospective wholesale and retail competition;

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uncertainties associated with energy demand that differs from forecasts, including significant or accelerated load growth from new data centers and the concentration of data center load, and the ability to timely serve such growth due to regulatory proceedings, legislative actions, environmental regulations, permitting requirements, contractual limitations, or cost-allocation mechanisms applicable to large-load customer and data centers;

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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;

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increases to operating costs that could result from changes to trade tariffs, rising inflation, and volatility in interest rates;

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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 tax credits;

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risks and uncertainties related to the procurement of resources through current or future All-Source Request for Proposals (RFP) projects or other regulatory mechanisms, 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, PGE's ability to obtain financing on favorable terms, and legislative uncertainty;

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demand uncertainty and changing customer preferences and choices that reduce demand for PGE's services or alter usage patterns, including variability in demand driven by weather variations, price increases, reduced consumption or load shifting resulting from energy efficiency measures or other changes in customer behavior, increased adoption of distributed and renewable generation, and an increased likelihood that customers procure electricity from alternative service providers such as registered Electricity Service Suppliers (ESSs) or through community choice aggregation programs;

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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;

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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;

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severe weather and other natural phenomena, such as the greater prevalence of wildfires in Oregon, 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;

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ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (PSPS) or 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;

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impacts from legislation limiting wildfire-related liability or providing a wildfire relief fund, such as negative effects on PGE’s credit rating, which could limit PGE’s ability to access capital on terms similar to past transactions or at all and could impact PGE’s liquidity, cash flows, and capital expenditure plans;

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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;

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

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

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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, such as the escalation of US operations in the Middle East, that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;

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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 and the escalation of US operations in the Middle East, on the Company’s power costs;

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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;

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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

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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;

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

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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;

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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;

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

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cybersecurity attacks, data security breaches, physical attacks and security breaches, the use or misuse of artificial intelligence technologies, including AI-enabled cyberattacks, fraud, misinformation, unauthorized disclosure of sensitive information, operational errors, or other malicious acts, internally or to third parties, that cause damage to the Company’s generation, transmission, or distribution facilities, impact information technology or operational 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;

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reputational damage from negative publicity, protests, fines, penalties and other negative consequences resulting in regulatory and/or legal actions;

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employee workforce factors, including labor strikes, work stoppages, collective bargaining negotiations that result in increased labor costs or other less favorable terms, the inability to obtain contracted workers at reasonable rates during a labor disruption, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover resulting from macroeconomic conditions such as elevated levels of voluntary resignations, any of which could increase costs and adversely affect operations and financial results;

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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 litigation, regulatory action or adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation;

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

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

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acts of war, terrorism, or civil disruption, including the escalation of US operations in the Middle East, which could amplify the effects of any of the above risk factors and contribute to volatility in capital market conditions, interest rates and inflation; and

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uncertainties associated with the proposed Acquisition, including but not limited to, the expected closing of the proposed transaction and the timing thereof, the financing of the proposed transaction, strategies and plans, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow.

Additional disclosures regarding risks, uncertainties and important factors that could cause PGE’s results or performance to differ from the statements made in this report are discussed in Part I, Item 1A. “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 17, 2026, and in Part II, Item 1A. “Risk Factors” of this Quarterly Report on Form 10-Q.

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

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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

PGE's corporate strategy places customers at the center of everything the Company does. PGE supports energizing lives, strengthening communities, and driving advancement in energy to promote social, economic, and environmental progress. With a focus on affordability, the Company continuously innovates, streamlines, and manages costs to deliver exceptional experiences for its customers. The Company is committed to delivering steady growth and returns to shareholders. The Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region.

PGE is focused on the following strategic imperatives:

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Decarbonize Power—make progress toward customer-driven clean energy goals by continuing to add new renewable and non-emitting resources and products to the Company's energy mix;

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Electrify the Economy—power the lives of approximately two million residents in its service territory by supporting the region’s economic growth industries and capturing the benefits of new technologies while serving approximately two-thirds of Oregon’s commercial and industrial activity; and

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Advance Performance—continue to build a safer and more reliable grid by accelerating cost-effective grid investments and modernizing transmission.

Pending Acquisition

On February 15, 2026, PGE, through a newly formed, wholly-owned subsidiary, entered into an agreement (the “Agreement”) with PacifiCorp, an indirect subsidiary of Berkshire Hathaway Energy Company, to acquire select Washington state generation, transmission, and electric utility operations for $1.9 billion. The Acquisition would enable PGE to extend its service to approximately 140,000 Washington customers.

Under the Agreement, if the Acquisition is completed, PGE will acquire three generation facilities: the Chehalis thermal plant (477 MW), the Goodnoe Hills wind facility (94 MW), and the Marengo I and II wind facilities (234 MW). The Acquisition would also include 4,500 miles of transmission and distribution lines, and local utility operations across approximately 2,700 square miles.

PGE intends to manage the Washington operations as a separate company through a newly created subsidiary to be regulated by the Washington Utilities and Transportation Commission (WUTC). PGE intends to retain current Washington employees and honor existing labor agreements. PGE corporate functions are expected to provide shared support for both Washington and Oregon companies.

The Acquisition is designed with the goal that Washington and Oregon customers would not be impacted by costs associated with executing the acquisition and transaction financing. PGE expects the Acquisition and state and federal regulatory reviews to close in approximately twelve months following the submission of regulatory applications. Regulatory applications were submitted to the WUTC and the OPUC on March 30, 2026 and April 2, 2026, respectively. On July 15, 2026, the Company, jointly with other parties, submitted an application to the FERC seeking approval of the transaction, requesting a decision by December 15, 2026.

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Central to this Acquisition is PGE’s plan to enter into a joint venture with Manulife Infrastructure Fund III, L.P. and its affiliates, including John Hancock Life Insurance Company (U.S.A.), which will collectively be a minority owner of the Washington utility business. PGE would remain majority owner and sole operator.

For more information regarding PGE’s plans to fund its future capital requirements, including this proposed Acquisition, see “Liquidity” in the Liquidity and Capital Resources section of this Item 2. See "Pending Acquisition" in Note 1, Basis of Presentation, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” for additional information on the pending acquisition.

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 211 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 September 30, 2026, the Green Future Impact Program has an approved capacity of 750 megawatts (MW) nameplate, of which 482 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. In December 2025, Portland, Oregon experienced the warmest December on record, averaging six degrees above normal temperatures for the region. In January 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 six percent. 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 preliminary and ongoing engagement with customers, stakeholders, regulators, and other interested parties to help inform the Company’s assessment of future energy needs and resource options. Through its Integrated Resource Plan (IRP) and Clean Energy Plan (CEP) processes, PGE evaluates multiple planning scenarios using forecasts, modeling, stakeholder input, surveys, and other available data.

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With the passage of HB 2021, PGE began preparing a CEP concurrent with its IRP to evaluate pathways for achieving Oregon's greenhouse gas emission reduction targets while maintaining an affordable and reliable electric system. PGE submitted its first combined CEP and IRP to the OPUC in 2023 and subsequently submitted a CEP/IRP Update in 2025 that refreshed forecasts, planning assumptions, and resource needs.

On October 15, 2026, PGE submitted its 2026 CEP/IRP to the OPUC (OPUC Docket LC 88). The filing updates the Company's assessment of future energy and capacity needs and evaluates portfolio pathways intended to support continued progress toward Oregon's clean energy requirements while maintaining affordability and reliability. The filing contemplates potential resource additions, emissions-reduction outcomes, and transmission expansion needs under two pathways. One pathway identifies a need of approximately 3,400 MW needed by 2030, and over 5,000 MW by 2032, in order to continue to serve customers reliably while making significant progress towards HB 2021 emissions reduction targets. The other pathway, which achieves Oregon's HB 2021 emissions requirements currently in effect and maintains system reliability, identifies a 2030 resource need of approximately 6,700 MW, and over 9,000 MW needed by 2032. The 2026 CEP/IRP is subject to review through the OPUC's regulatory process, which PGE currently expects to continue into 2027. The expected additions from PGE's ongoing 2025 RFP, or any other additional resource procurement activities executed subsequent to the third quarter of 2026, will satisfy a portion of the incremental resource needs under either pathway. PGE will continue to engage with customers, stakeholders, and regulators throughout that review process and cannot predict its ultimate outcome.

2023 All-Source RFP

After a robust and competitive bidding, repricing, and negotiating process as part of the 2023 RFP, PGE has entered into agreements to construct two solar and battery hybrid projects for a total of 615 MW:

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Biglow Optimization—PGE entered into an agreement to construct a 125 MW solar facility and a 125 MW BESS in Sherman County, Oregon. PGE will own the resource with an investment of approximately $540 million, excluding AFUDC. The project has an estimated commercial operation date at the end of 2027.

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Wheatridge Expansion—PGE and NextEra Energy, Inc. entered into agreements to construct a 240 MW solar facility and a 125 MW BESS facility, located in Morrow County, Oregon. PGE will own 110 MW of solar and 65 MW of BESS production capacity with an investment of approximately $490 million, excluding AFUDC. NextEra Energy, Inc. will operate the facility, own the remaining 130 MW of solar and 60 MW of BESS production capacity and sell their portion of the output to PGE under a 30-year PPA. The project has an estimated commercial operation date at the end of 2027.

These agreements represent the final procurement from the 2023 All-Source RFP. The 2023 RFP is a component of PGE’s multi-pronged procurement approach focused on customer affordability, system reliability, and decarbonization. Both the 2023 RFP reprice and the 2025 RFP disclosed below were designed to capture expiring tax credits to support customer affordability.

2025 All-Source RFP

Consistent with its 2023 IRP Action Plan and CEP Update, PGE initiated the 2025 All-Source RFP to address forecasted capacity needs beginning in 2029 and advance the Company's decarbonization obligations under HB 2021.

Following OPUC approval on July 22, 2025, PGE issued the RFP on July 31, 2025, seeking renewable generation and non-emitting dispatchable capacity resources. The procurement was conducted under Oregon's competitive bidding rules with oversight from an OPUC-selected independent evaluator.

PGE submitted its final shortlist for acknowledgment on February 17, 2026, and received OPUC acknowledgment on May 26, 2026. The final shortlist included 12 projects offering combinations of wind, solar, and battery storage resources through PPAs, storage capacity agreements, and utility ownership structures, including build-transfer agreements (BTAs), as shown in the table below:

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2025 RFP Final Shortlist
Project	Technology	Structure	MW	Company-owned MW
1	Battery	PPA	185
2	Battery	PPA	200
3	Wind	PPA	560
4	Solar	PPA	100
5	Wind	PPA	103
6	Solar, Battery	Hybrid	800	400
7	Wind, Battery, Solar	Hybrid	800	375
8	Solar, Battery	BTA	450	450
9	Solar, Battery	BTA	400	400
10	Battery	BTA	100	100
11	Battery	BTA	200	200
12	Solar, Battery	PPA	900

Following a competitive bidding and negotiation process, PGE has executed an agreement for one project on the final shortlist:

•

Biglow Optimization Phase 2— In October 2026, PGE entered into a build transfer agreement to acquire a 200 MW solar facility and a 250 MW BESS in Sherman County, Oregon. PGE expects to own the resource, representing an investment of approximately $900 million, excluding AFUDC. The project has an estimated commercial operation date at the end of 2029 and is expected to qualify for ITCs.

PGE continues to evaluate and negotiate with projects on the final shortlist, prioritizing those that include renewable generation and that have a viable pathway to achieve commercial operations within the 2028–2030 eligibility period. However, interconnection, transmission, permitting, and other development constraints have materially reduced the number of viable projects, with several facing potential delays into the 2030s.

Consequently, PGE expects the 2025 RFP to deliver fewer resources than originally anticipated and is pursuing complementary procurement pathways to address the resulting resource gap. PGE believes these resource acquisition opportunities are capable of providing renewable energy and dependable capacity within the identified need period, subject to applicable regulatory approvals.

Together, these procurement activities reflect PGE's diversified approach to meeting growing customer demand, maintaining system reliability, advancing decarbonization objectives, and managing customer costs. The ultimate outcome of the RFP process, or any other additional resource procurement activities outside of the RFP, may involve the selection of multiple projects for both renewable and non-emitting dispatchable capacity resources, which PGE expects will be approximately 2,500 MWs in total.

Additional information regarding the 2025 All-Source RFP is available in OPUC Docket UM 2371 on the OPUC website at www.oregon.gov/puc.

Additional Procurement Activities

In parallel with its competitive RFP processes, PGE is advancing additional resource acquisitions through bilateral agreements and other regulatory pathways to address identified capacity and renewable energy needs.

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Meadowlark BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project will be owned by Copenhagen Infrastructure Partners, LLC and has an estimated commercial operation date at the end of 2027.

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Nottingham BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project has an estimated commercial operation date in 2028. OPUC approved PGE’s requested waiver of the competitive bidding rules on August 18, 2026.

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•

Salmonfly Solar & BESS—PGE has entered into a build transfer agreement to acquire a proposed 199 MW solar facility and a 199 MW BESS in Jefferson County, Oregon, located on the Confederated Tribes of Warm Springs (CTWS) Reservation, representing an investment of approximately $853 million, excluding AFUDC. The project has an estimated commercial operation date at the end of 2029 and is expected to qualify for ITCs. Salmonfly builds on PGE's longstanding partnership with CTWS through the jointly owned Pelton Round Butte Hydroelectric Project. Salmonfly provides a near-term opportunity to secure renewable energy capacity within the identified need period that was not available through the 2025 RFP. This project remains subject to OPUC process as detailed in PGE's request for a waiver to the competitive bidding rules.

Transmission Upgrades

In alignment with local and regional transmission plans, the 2023 IRP Action Plan, and CEP Update, 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.

In May 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 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. In August 2024, the project was awarded a $700 million grant from the U.S. DOE’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 also allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in the Laws and Regulations section of 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 and enhanced wholesale markets, and ease congestion on the existing western transmission system. PGE continues to explore the North Plains Connector as a resource to help 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 (Warm Springs Power Pathway) 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 the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants.

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:

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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. In December 2025, PGE filed its 2026-2028 Wildfire Mitigation Plan, which forecasts $47 to $50 million annually in operations and maintenance costs and an additional $70 to $84 million annually in capital investments, for the 2026-2028 period, 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 nine months ended September 30, 2026, PGE invested $59 million in capital projects related to wildfire mitigation and resiliency and utility asset management.

•

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

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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. When coordinated through the Company’s Distributed Energy Resources Management Systems, these resources can be forecasted, dispatched, and measured to support grid reliability and decarbonization goals, 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. As PGE integrates technologies to increase orchestration of these resources, they continue to contribute to reliability and help reduce customer exposure to scarcity pricing in energy markets, benefiting participating and non-participating customers.

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Grid Enhancing Technologies (GETs)—Network upgrades or non-wires solutions are important strategies that offer improvements and can unlock capacity on existing transmission paths in the region. GETs include advanced conductors and coatings, topological optimization, and dynamic line ratings. PGE is actively incorporating GETs across its system to further increase the performance of new and existing transmission assets. These efforts, when deployed across a number of areas and assets, have the potential to add incremental capacity to the grid at lower costs.

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Distribution System Plan (DSP)—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in 2022 and 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. 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 demonstrating continual progress towards PGE’s clean energy goals. For further information on recovery of costs related to the DSP, see “DSP recovery mechanism” in the Regulatory Matters section of this Overview.

Electrify the economy—To help Oregon reach its decarbonization goals, PGE is committed to increasing electrification of buildings and supporting vehicle electrification for customers.

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 December 2025, the OPUC accepted PGE's 2026-2028 TE Plan. The plan considers current and planned activities, along with forecasted EV loads for the 2026-2028 period, with expected capital expenditures to be approximately $11 million.

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—U.S. trade policy and tariff measures continue to evolve through a combination of existing and newly implemented tariff programs, ongoing litigation, and potential future trade actions. These evolving measures may increase the cost of raw materials and equipment, disrupt global supply chains, and contribute to volatility in commodity, capital, and credit markets. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase, which could affect materials and supplies balances and increase capital projects costs. Similarly, procurement costs may rise and lead times may lengthen 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. Although PGE does not expect a material impact on its Canadian natural gas imports from existing Canada-related policies and tariffs, future trade actions involving Canada could affect commodity markets, supply chains, or procurement costs. Evolving tariff policies affecting particular countries and product categories, as well as the possibility of additional trade measures, have increased uncertainty regarding future equipment costs and supply availability. The Company is unable to reasonably estimate the effects of the rapidly changing trade tariff landscape, as those effects could include project delays and cost increases, and present obstacles to PGE’s strategic plan execution, capital investments, and resource development initiatives. PGE is closely

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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—PGE continues to evaluate opportunities on behalf of customers to leverage state, federal, and private foundation funding programs to offset the cost 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, and regional transmission capacity constraints.

In October 2025, PGE received notice from the U.S. DOE of the termination of four federal grants that originally planned to provide $61 million in federal reimbursement over the life of the grants. PGE has incurred an immaterial amount of costs for projects associated with the terminated grants and does not expect the termination process to result in a material impact on the Company’s financial position and results of operations. The U.S. DOE has subsequently communicated the potential to reinstate financial assistance related to PGE’s Grid Edge Devices grant, which would provide approximately $45 million in total funding. PGE is evaluating the terms and considerations associated with reinstatement of the grant.

PGE has been awarded, either as a direct recipient or subrecipient, five additional grants totaling approximately $252 million. These grants remain in various stages of execution, with the largest being the Warm Springs Power Pathway. PGE continues to monitor these grants for potential modification or termination but has not received any formal notice of termination. To date, PGE has incurred only immaterial costs related to these grants. See “Transmission Upgrades” in the Investing in a Clean Energy Future section of this Overview for further discussion on the Warm Springs Power Pathway grant. 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 (IRA)—The IRA was signed into law in 2022. The United States Treasury and the IRS 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 2024, PGE received approval from the OPUC to transfer PTCs generated in 2024 and 2025 and to record any difference between the full value and the discounted value in a property balancing account. On April 15, 2026, PGE received approval from the OPUC to transfer PTCs generated in 2026 and 2027 and to record any difference between the full value and the discounted value in a property balancing account.

PGE has entered into agreements to transfer tax credits and transferred $23 million and $153 million, net of discounts, for cash proceeds in the first nine months of 2026 and 2025, respectively. PGE transferred tax credits, net of discounts, of $179 million in 2025. For the remainder of 2026, the Company expects to generate and transfer approximately $15 million of additional tax credits, net of discounts.

The One Big Beautiful Bill Act (OBBBA)—The OBBBA significantly amended or repealed several renewable-energy tax incentives originally enacted under the IRA. Projects previously placed in service that met applicable tax credit qualification requirements received PTC or ITC benefits, which are reflected in the Company’s condensed consolidated financial statements. The transferability of tax credits, as provided under the IRA, also remains in effect. In August 2025, the U.S. Treasury issued a notice for establishing the beginning of construction for wind and solar projects. The notice required large projects to satisfy a physical-work test after September 2, 2025, eliminated certain inventory-procurement safe harbors, and accelerated the placed in service deadline to December 31, 2027. A subsequent court ruling invalidated the August 2025 notice, although debate continues as to the repercussions. Since the effect of the court ruling on the Company remains unclear, PGE has not changed its method of determining qualifying projects, treating them as if the notice remains in effect.

These changes, together with the repeal of the permanent ten percent ITC, as outlined in the OBBBA, are expected to reduce or eliminate the availability of renewable energy tax incentives on future projects.

See “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview for information regarding the impact of the OBBBA on the RFP process.

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,

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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.

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 take actions as soon as practicable that facilitate rapid reduction of GHG emissions, demonstrate continual progress toward meeting the targets, and create a plan that is in the public interest. 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 affordability 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. In addition, a rulemaking docket, AR 685, seeks to develop a framework around the components and calculation of the cost cap, including costs already incurred in compliance.

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 on or before January 1, 2030, although an exception in the law may extend this date five years for the output of Colstrip Units 3 and 4 coal-fired generating plant (Colstrip).

The Company has a 20% ownership share in Colstrip and has fully depreciated the facility as of December 31, 2025. Any capital spending after 2025 is expected to be fully depreciated within the year of spending. The forecasted annual revenue requirement for Colstrip, including depreciation, is updated annually in a separate, supplemental tariff and recovery of power cost related items is sought annually under the AUT. In order to meet PGE’s regulatory, legislative, and reliability requirements, the Company continues to evaluate its ongoing ownership interest in 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 the Investing in a Clean Energy Future section of this Overview for information regarding development in eastern Montana.

Other provisions of SB 1547:

•

established 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;

•

limited 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

•

provided opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s RAC filings.

During the second quarter of 2026, the Company submitted its RPS report for 2025, which indicated that the Company met the threshold for 2025. The OPUC found the Company in compliance for 2025 on September 15, 2026, through Order 26-345. PGE believes it is on track to meet the RPS threshold for 2026.

HB 3179—In response to increasing utility bills and concerns about affordability, the Oregon Legislature in 2025 passed HB 3179. Under the provisions of the legislation, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multi-year rate plan (MRP) on a regular interval that is no less than three and no more than seven years long. The OPUC issued Order 26-191 on May 26, 2026, that began formal rulemaking in docket AR 677. In the proposed rules identified in Order 26-191, the OPUC is seeking to establish an initial filing schedule for MRPs, which calls for PGE to file its first MRP no earlier than

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May 1, 2029 and no later than July 31, 2029. The OPUC has also opened a docket, AR 676, as a multi-phased rulemaking to establish the MRP framework with a target to complete the framework in early 2027.

Under rules made effective March 19, 2026, each electric and natural gas company is required to, at least annually by December 31, file with the OPUC, and make publicly available, a report on any price adjustments that the electric or natural gas company expects within the next twelve months. Such report, must identify all price adjustment requests that an electric or natural gas company has filed or reasonably knows or anticipates to file. Any increase in residential prices may not take effect from November 1 to March 31.

United States Environmental Protection Agency (EPA) Regulations for Electric Generating Facilities—In 2024, the EPA released final regulations pertaining to electric generation facilities. The regulations included:

•

GHG regulations under section 111 of the Clean Air Act (CAA) for new, modified, and reconstructed fossil fuel-fired combustion turbines and for existing fossil fuel-fired steam generating units, including coal-based units;

•

Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the ELG Rule), which applies to wastewater discharges from coal-based generating units and establishes pollution control requirements, building upon the 2015 and 2020 ELG Rules; and

•

Updated Mercury and Air Toxics Standards (MATS), pursuant to section 112 of the CAA, which established revised emission standards for filterable particulate matter at existing coal fired generating units.

In April 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to CAA section 112(i)(4) from specified requirements of the 2024 MATS amendments. Colstrip subsequently received an exemption from the otherwise applicable July 8, 2027 compliance date through July 8, 2029, and environmental groups filed court challenges to the exemptions. In February 2026, the EPA finalized repeal of the relevant 2024 MATS amendments effective April 27, 2026. That repeal has subsequently been challenged in litigation. The practical significance of the Colstrip exemption and the related challenges depends on the outcome of both the litigation concerning the exemption and the litigation challenging EPA’s repeal of the 2024 MATS amendments.

In June 2025, to advance the goals of the President’s Unleashing American Energy executive order, the EPA proposed to repeal the 2024 GHG emission standards for fossil fuel-fired power plants promulgated under section 111 of the CAA, and proposed to repeal specified 2024 MATS amendments. In December 2025, the EPA finalized revisions extending several compliance deadlines under the 2024 ELG Rule. The EPA corrected certain dates in January 2026 and proposed additional revisions in May 2026. On February 12, 2026, the EPA finalized rescission of the 2009 endangerment finding supporting regulation of new motor vehicles and engines under CAA section 202(a) and repealed the associated vehicle GHG standards, effective April 20, 2026. That action did not, by itself, eliminate all potential EPA authority to regulate GHG emissions under other CAA provisions. On September 14, 2026, the EPA finalized a partial repeal of the 2024 power-plant GHG rule, including the emission guidelines for existing fossil fuel-fired steam generating units and specified carbon capture and storage-based standards for modified coal-fired units and new baseload combustion turbines, effective November 16, 2026. The EPA concurrently issued a supplemental proposal to repeal the remaining power-sector GHG standards. On September 17, 2026, environmental and public-health organizations filed a petition for review of the partial repeal in the D.C. Circuit.

PGE continues to evaluate the 2024 MATS amendments, the Colstrip compliance exemption, EPA's repeal of the relevant MATS requirements, and the related litigation to assess the potential impact, which could be material, on the Company’s continuing investment in Colstrip. If EPA's repeal is vacated or otherwise reversed and the 2024 MATS amendments are reinstated, the applicability and timing of those requirements would depend in part on the outcome of the litigation concerning the Colstrip exemption. Reinstatement of the 2024 requirements could require material upgrades at Colstrip on a schedule that may not be achievable or could require the use of technology not yet demonstrated at Colstrip, resulting in significant costs related to the facility.

Legal challenges have been filed concerning the 2024 rules, the subsequent repeal actions, the MATS exemptions, and the rescission of the endangerment finding. Courts previously denied requests to stay the 2024 GHG and MATS rules. Any later orders holding merits proceedings in abeyance while the EPA reconsidered those rules should not be characterized as stays of the rules themselves. The rescission of the endangerment finding took effect April 20, 2026, and the partial repeal of the 2024 power-plant GHG rule is scheduled to take effect November 16, 2026, while related legal challenges are

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pending. These challenges, and further federal action to withdraw, modify, or reinstate requirements, could affect the applicability to PGE and Colstrip. Given the uncertainty surrounding these laws and regulations, PGE cannot reasonably estimate the impact on its results of operations, financial position, and cash flows. If prior requirements are reinstated, remaining GHG standards apply, or other requirements impose comparable obligations, PGE could incur material additional 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.

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 a number of such matters.

Corporate structure—In July 2025, the Company submitted an application to the OPUC seeking approval of a holding company reorganization. PGE believes it to be in the best interests of its customers and shareholders to update its corporate structure into a holding company structure. The structure contemplated involves placing a non-operating corporate entity over the Company’s existing structure. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure and to support reliability planning and economic development.

On July 23, 2026, FERC issued an order authorizing the reorganization into a holding company structure. On August 12, 2026, PGE and OPUC Staff entered into a stipulation in OPUC Docket UM 2385 that recommended the OPUC approve PGE’s application for a corporate reorganization to create a holding company structure. The stipulation included a monetary commitment of approximately $45 million to fund a rate credit and other customer benefits. The stipulation also included a comprehensive set of enforceable commitments, such as:

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A commitment to refrain from seeking rate recovery of acquisition premiums, goodwill, transaction costs and other related costs;

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A commitment to not provide funding or transfer assets over $1 million to any subsidiaries, excluding those to be funded or transferred to PGE and subsidiaries formed for purposes of the acquisition of assets in Washington, without OPUC approval under defined statutory standards;

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A commitment to maintain service, safety, and reliability for customers and to provide regular reports on related metrics;

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A commitment for PGE and the holding company to maintain separate credit ratings;

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An agreement for the holding company to maintain its subsidiary PGE’s common equity at a level of 45% or higher, with the provision that the dividend may be suspended in certain circumstances including for significant decreases in credit ratings, without an OPUC-approved remediation plan;

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A commitment to maintain adequate interest coverage and a pool of qualified assets to maintain the ability to issue First Mortgage Bonds;

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A commitment to hold customers harmless from certain costs associated with the formation of the holding company, as well as from costs that may be incurred if the cost of debt becomes more costly as a result of the formation of the holding company;

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The establishment of a share of PGE preferred stock held by an independent third party (Golden Share) that will override all other outstanding shares in the event of bankruptcy of the holding company;

•

Access to PGE and holding company books and records; and

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holders ( registered funds via N-PORT, institutional investors via 13F). Showing top by dollar value.

Holder	Type	ETF	MF	Position ($)	% of holder	Δ % of holder	Holder AUM

Next expected filings

~2027-02-16 10-K expected by 2027-03-01 (in 110 days)
~2027-04-30 10-Q expected by 2027-05-13 (in 183 days)
~2027-07-30 10-Q expected by 2027-08-12 (in 274 days)
~2027-10-28 10-Q expected by 2027-11-10 (in 364 days)

Predicted from historical filing cadence; not an SEC commitment.

Recent SEC filings

2026-10-29 10-Q Quarterly Report
2026-10-16 8-K Other Events
2026-09-28 8-K Other Events
2026-07-31 10-Q Quarterly Report
2026-07-31 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits
2026-05-01 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits
2026-05-01 10-Q Quarterly Report
2026-03-24 8-K Material Agreement Entered; Material Financial Obligation; Regulation FD Disclosure; Financial Statements and Exhibits
2026-02-19 8-K Other Events; Financial Statements and Exhibits
2026-02-17 10-K Annual Report
2026-02-17 8-K Other Events; Financial Statements and Exhibits
2026-02-17 8-K Material Agreement Entered; Earnings Release; Material Financial Obligation; Regulation FD Disclosure; Financial Statements and Exhibits
2025-12-29 8-K Other Events
2025-10-31 10-Q Quarterly Report
2025-10-31 8-K Earnings Release; Regulation FD Disclosure; Financial Statements and Exhibits

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