PORTLAND GENERAL ELECTRIC CO /OR/ (POR)

CIK: 0000784977. SIC: 4911 Electric Services. Latest 10-K as of: 2026-02-17.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4911 Electric Services

SEC company page: https://www.sec.gov/edgar/browse/?CIK=784977. Latest filing source: 0001193125-26-052750.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-17. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000784977.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-01. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000784977.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001193125-26-197978.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-01. Report date: 2026-03-31.

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, 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:

•
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, 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, tax credits, and current or prospective wholesale and retail competition;

•
uncertainties associated with increased energy demand or significant accelerated growth in demand due to new data centers, including the concentration of data centers, and the ability to obtain regulatory approvals, environmental, and other permits to construct new facilities in a timely manner;

•
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;

•
increases to operating costs that could result from changes to trade tariffs, rising 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 tax credits;

•
risks and uncertainties related to current or future All-Source Request for Proposals (RFP) projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of trade tariffs), permitting and construction delays, available tax credits, counterparty credit risk, and legislative uncertainty;

•
demand uncertainty and changing customer preferences and choices that may reduce demand for PGE's services or alter usage patterns, including variability in demand driven by weather variations, 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;

•
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”

33

Table of Contents

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;

•
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;

•
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;

•
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;

•
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, that 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, 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;

•
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;

•
volatility in wholesale power and natural gas prices, including but not limited to volatility caused by macroeconomic and international issues, such as the war involving the United States, Iran and Israel, 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 and the war involving the United States, Iran and Israel, 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;

34

Table of Contents

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

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

•
changes in residential, commercial, or industrial customer growth, or demographic patterns, 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, impact 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;

•
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;

•
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;

•
the impact of widespread health developments, and responses to such developments (such as volunt

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-17. Report date: 2025-12-31.

ITEM 7. 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,” “may,” “plans,” “predicts,” “projects,” “will,” “continue,” “should,” “based on,” “considers,” “could,” “expected,” “forecast,” “goals,” “needs,” “promises,” “subject to,” “strategic imperatives,” “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. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, 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:

•
New or revised governmental policies, executive orders, legislative actions, and regulatory audits, investigations and actions, including those of the FERC, the OPUC, and the Internal Revenue Service 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, tax credits, and current or prospective wholesale and retail competition;

42

Table of Contents

•
uncertainties associated with increased energy demand or significant accelerated growth in demand due to new data centers, including the concentration of data centers, and the ability to obtain regulatory approvals, environmental, and other permits to construct new facilities in a timely manner;

•
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;

•
increases to operating costs that could result from changes to trade tariffs, rising 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 tax credits;

•
risks and uncertainties related to current or future All-Source Request for Proposals (RFP) projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of 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 registered 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 7. and Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;

•
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;

•
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 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;

•
impacts from legislative action 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;

•
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;

43

Table of Contents

•
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;

•
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;

•
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;

•
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, including those related to threatened and endangered species, fish, and wildlife;

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

•
changes in residential, commercial, or industrial customer growth, or demographic patterns, 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, impact 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 or legal actions;

•
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;

44

Table of Contents

•
failure to achieve the Company’s 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;

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

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

•
acts of war, terrorism, or civil disruption; and

•
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.

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 consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.

PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State. The Company participates in wholesale markets by purchasing and selling electricity, 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:

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

45

Table of Contents

•
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

•
Advance Performance—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 regulated by the Washington Utilities and Transportation Commission. 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.

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 a 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 7. See Note 21, Subsequent Events, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” for additional information on the pending acquisition.

Climate Change

State-mandated GHG emissions reduction targets—In 2021, the Oregon legislature passed HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and ESSs 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 221 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

46

Table of Contents

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 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 December 31, 2025, the Green Future Impact Program has an approved capacity of 750 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 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 submitted to the OPUC in connection with, the Company’s 2023 Integrated Resource Plan (IRP) in March 2023, the first combined IRP and CEP. That filing projected PGE’s resource and capacity needs over the next 20 years and proposed an Action Plan to meet near-term needs, subject to HB 2021 emissions reduction requirements.

On June 18, 2025, PGE submitted a CEP/IRP Update to the OPUC. The CEP/IRP Update identified a new Preferred Portfolio as a result of the refreshed analysis. PGE did not propose any changes to the Action Plan that was acknowledged within the 2023 CEP/IRP, which supports the Company's progress toward emissions targets and Preferred Portfolio resource need procurement through the 2025 All-Source RFP. This approach represents the best combination of cost, risk, community benefit, and decarbonization.

To better distinguish resource needs, the CEP/IRP Update reports the capacity from hybrid solar and battery storage resources by individual technology. The capacity need is 3,500 to 4,500 MW of renewable energy and non-emitting capacity, inclusive of 2023 RFP projects, which remain under negotiation.

The actions summarized in the CEP/IRP Update will also serve as an important tool in furthering conversations with all stakeholders, and the OPUC, on PGE’s path forward to making continued progress towards emission targets while continuing to serve customers safely, reliably, and at the lowest cost possible. PGE and parties will work through the regulatory review process for the CEP/IRP Update filing (OPUC Docket LC 80) during the coming months. PGE cannot predict the ultimate outcome of the regulatory process.

47

Table of Contents

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:

•
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.

•
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. Additional resources are anticipated to be procured through future acquisition processes, including, but not limited to, PPAs, including a bilateral all-call for PPAs, community-based renewable energy procurement, the ongoing 2025 RFP, and future RFPs.

Additional Procurement Activities

PGE has entered into the following agreements outside of the Company’s 2023 RFP and for each has requested the OPUC to grant a waiver to Oregon’s competitive bidding rules:

•
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, pending OPUC approval of the requested waiver of the competitive bidding rules.

•
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, pending OPUC approval of the requested waiver of the competitive bidding rules.

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 Update. PGE filed the draft 2025 All-Source RFP on April 17, 2025, and regulatory approval was granted on July 22, 2025. The Company issued the RFP to market on July 31, 2025, 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, PGE

48

Table of Contents

plans to submit a request for acknowledgement of the final shortlist of bidders to the OPUC. The final shortlist is made up of both renewables and non-emitting capacity projects, as shown in the table below:

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

The proposals for renewable resources provide various combinations of wind, solar and battery storage options that include storage capacity and 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.

PGE is proceeding to commercial negotiations with projects on the final shortlist, prioritizing those that include renewable generation and that have a viable pathway to achieve commercial operations earlier in the 2028 - 2030 eligibility period. The ultimate outcome of the RFP process 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.

PGE anticipates the OPUC to consider acknowledgement of the RFP final shortlist in May 2026. Additional details of the 2025 RFP (OPUC Docket UM 2371) are available on the OPUC website at www.oregon.gov/puc.

Legal Challenges to the RFP Process

Various regulatory and legal challenges directed at the OPUC have been initiated by NewSun Energy LLC, related to PGE’s RFP process. PGE has joined the proceedings as an intervenor, and the challenges are in various stages of litigation or regulatory review. PGE cannot predict the outcome of these proceedings or potential impact, if any.

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 program to further support its development and

49

Table of Contents

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 meet those load-service needs.

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 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:

•
Wildfire Mitigation—PGE has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan is developed and submitted to the OPUC, as required by State law, to coordinate activities across the Company and with State-wide stakeholders. On December 31, 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. During 2025, PGE invested $56 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 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, 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. As customer participation in PGE’s VPP grows, their actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.

•
Grid Enhancing Technologies (GETs)—Limited network upgrades or non-wires solutions are important strategies that offer incremental 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.

•
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

50

Table of Contents

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 demonstrating continual progress towards PGE’s clean energy goals. For further information on recovery of costs related to the DSP, see “Distribution System Plan 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 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 $14 million in capital expenditures under the 2023-2025 TE plan.

On July 25, 2025, PGE filed with the OPUC its draft 2026-2028 TE plan, which represents a continuation of the approach and strategy found within PGE’s 2023-2025 TE plan.

On December 9, 2025, the OPUC accepted PGE's 2026-2028 TE plan. In the 2026-2028 period covered by the 2026-2028 TE Plan, capital expenditures are expected 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—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. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase materials and supplies balances and elevate the cost of capital projects. Similarly, prices 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. 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, as those effects could include project delays and cost increases, and present 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—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.

51

Table of Contents

On October 2, 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 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.

PGE has been awarded five additional grants totaling approximately $252 million, either as a direct recipient or subrecipient. 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 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. See the "Income Taxes" section of Note 2, Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” for information on OPUC approval and treatment of tax credit transfers.

PGE has entered into agreements to transfer 2023 through 2025 tax credits and transferred $179 million and $112 million, net of discounts, for cash proceeds in 2025 and 2024, respectively.

The One Big Beautiful Bill Act—The OBBB significantly amends or repeals several renewable-energy tax incentives originally enacted under the IRA. Projects placed in service during 2025 that met applicable tax credit qualification requirements received PTC or ITC benefits, which are reflected in the Company’s consolidated financial statements. The transferability of tax credits, as provided under the IRA, also remains in effect. Following the July 7, 2025 executive order that added uncertainty with respect to the specific actions necessary to demonstrate a project’s start of construction, on August 15, 2025, the Treasury Department issued a notice for establishing the beginning of construction for wind and solar projects. The notice requires large projects to satisfy a physical-work test after September 2, 2025, eliminates certain inventory-procurement safe harbors, and accelerates the placed in service deadline to December 31, 2027.

These changes, together with the repeal of the permanent ten percent ITC, as outlined in the OBBB, are expected to reduce or eliminate the availability of RECs on future projects. The Company cannot yet reasonably estimate the impact on PGE’s results of operations, financial position, and cash flows or on future capital expenditures, deferred tax assets, current and future All-Source RFPs, and customer prices.

See “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview for information regarding the impact of the OBBB 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, 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 facilitates 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

52

Table of Contents

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.

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.

The Company has a 20% ownership share in Colstrip and has fully depreciated it 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 power cost related items are recovered annually under the AUT. In order to meet PGE’s regulatory, legislative, and reliability requirements, the Company continues to evaluate its ongoing ownership in Colstrip. See Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” for information regarding legal matters 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 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 RAC filings.

PGE believes it met the RPS threshold for 2025 and is on track to meet the threshold during 2026. The Company plans to submit its RPS report for 2025 by June 1, 2026. For a more comprehensive review of Environmental Matters, see “Environmental Matters” in Item 1.—Business.

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, which will require a significant amount of rulemaking to implement, 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 multiyear rate plan on a regular interval that is no less than three and no more than seven years long. The OPUC shall require each electric and natural gas company to, at least annually, 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, the first of which would be due at the end of 2026 at the earliest, 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.

53

Table of Contents

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);

•
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 sets emissions limits for filterable particulate matter for coal-based generating units. The rule reduces those limits from the standards that were originally set in 2012.

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 EPA’s MATS rule. The EPA subsequently notified companies whether their sources had been granted the exemption. Colstrip was granted an exemption until July 8, 2029. Environmental groups have filed court challenges to the MATS exemptions.

On June 11, 2025, to advance the goals of the President’s Unleashing American Energy executive order, the EPA proposed to repeal the 2024 GHG emissions standards for fossil fuel-fired power plants promulgated under Section 111 of the CAA. The EPA also proposed to repeal specific amendments to the updated MATS, that were promulgated in 2024, including the revised filterable particulate matter emissions standard. Additionally, on June 30, 2025, the EPA proposed to update the 2024 ELG Rule to extend compliance deadlines and explore flexibilities to promote reliable and affordable power generation. On February 12, 2026, the EPA revoked the 2009 endangerment finding, thus removing the EPA’s authority to regulate GHGs.

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 2024 rules could require material upgrades at Colstrip with proposed compliance dates that may not be achievable or require the use of unproven technology, resulting in significant impacts to costs related to Colstrip. If upheld, or not modified by the EPA, the 2024 MATS and GHG Rules would require compliance as early as 2027 and 2032, respectively.

In addition to the EPA’s proposed rulemakings, several 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. 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 could require 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 such matters.

Corporate structure— On July 25, 2025, the Company submitted a formal 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 currently contemplated involves placing a non-operating corporate entity over the Company’s existing structure.

54

Table of Contents

Additionally, this structure would allow for the formation of a subsidiary of the holding company that could hold existing and future transmission assets. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure, and to support construction of new transmission assets, reliability planning, and economic development.

The application is one of many steps required to complete the reorganization, which needs OPUC approval under Oregon law as well as any necessary FERC approvals. Later in the process, PGE's Board of Directors will decide whether to submit the proposed reorganization to PGE shareholders for approval. Following completion of these steps and the receipt of all required approvals, each outstanding share of PGE common stock would automatically convert into a share of the new holding company (HoldCo) common stock on a one-for-one basis. PGE shareholders, immediately prior to consummation of the reorganization would own the same relative percentages of HoldCo following consummation of the reorganization. After the reorganization, PGE would be a wholly owned subsidiary of HoldCo, which would be an Oregon corporation.

As of the date of this filing, the OPUC proceeding remains in the evidentiary phase. Written testimony has been submitted, and the OPUC is continuing to compile additional filings and public input. No final order has been issued, and the proceeding remains active.

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. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including, among other requirements, a review of utility prudence and application of an earnings test, in a future proceeding.

In January 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 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 December 31, 2025, PGE had deferred $48 million, including interest, as a regulatory asset for costs associated with repairing damage to transmission and distribution systems and restoring power to customers.

PGE believes that the deferral is probable of recovery and submitted a request for recovery early in the third quarter of 2025, with price changes to be effective over a two-year period beginning April 1, 2026. The OPUC has adopted a procedural schedule in Docket UE 458 for the regulatory review process that expects an order in March 2026. The OPUC has significant discretion in making the final determination of recovery based on its assessment 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 regulated return on equity, based on actual results, did not exceed the authorized rate of return as set by the OPUC, therefore, there has been no adjustment pursuant to the earnings test.

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 Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

RCE—Under the RCE mechanism, originally authorized by the OPUC to be effective through 2025, 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 PCAM. As of December 31, 2025, PGE’s deferred balance related to RCEs was $90 million, which includes $88 million related to RCEs in 2024 and $2 million in 2025. PGE filed the results of the 2024 PCAM

55

Table of Contents

with the OPUC on July 1, 2025, in Docket UE 457, which included a request for $86 million, before considering interest, in RCE costs incurred in 2024, initiating a regulatory review process. Included in the filing, the Company requested an extension of the RCE mechanism for one year, through 2026. The OPUC has adopted a procedural schedule for the regulatory review process that expects an order in March 2026. Any resulting refund or collection impacting customer prices is expected to be effective April 1, 2026. PGE believes the deferred amounts as of December 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 annual revenue requirement of $72 million from 2024 levels, which were reflected in customer prices effective January 1, 2025. The 2026 AUT contains a $39 million increase in NVPC and has been included in customer prices beginning January 1, 2026. For more information regarding the PCAM, see “Power operations” within this Overview section of Item 7.

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 General Rate Case (GRC). In 2023, the Company filed for Clearwater, which went into service in January 2024. PGE did not submit a request for recovery of any renewable resources under the RAC during 2024 or 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 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 by the OPUC in Order 25-075 issued February 21, 2025.

Order 25-075 also adopted conditions to be applied to the AUT and clarification of the applicability of those conditions were subsequently provided by the OPUC in Order 25-223, which granted certain of PGE’s requests and denied others. PGE and NewSun Energy LLC, as an intervenor, both have Petitions for Judicial Review of Order 25-075 pending at the Oregon Court of Appeals. For the period of January 1, 2025 through December 31, 2025, PGE deferred an additional net $13 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that the Company 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.

Seaside Grid BESS recovery—On May 30, 2025, PGE submitted a request to the OPUC to recover the revenue requirement associated with the Seaside Battery Energy Storage System (Seaside). The regulatory filing was pursuant to the expedited cost-recovery option introduced by the OPUC in its Order issued December 20, 2024 related to PGE's 2025 GRC (OPUC Docket UE 435).

On October 21, 2025, the OPUC issued an Order (Order 25-417) that was supported by a memorandum of understanding (MOU) entered into between PGE and key regulatory stakeholders. The MOU guided the recovery proceeding for Seaside, PGE’s largest standalone battery storage project which has been serving customers since July 2025.

The Order calls for the following:

•
a rate base increase of $220 million, net of estimated ITC benefits of $125 million;

•
a 9.34% return on equity; and

56

Table of Contents

•
an annual revenue requirement increase of $42 million, excluding impacts related to NVPC, compared to PGE’s filed request of $46 million at closing briefs.

The Order also resulted in a $6 million revenue requirement increase for the remainder of 2025, inclusive of NVPC customer benefits. Seaside’s NVPC is included in PGE’s AUT filings for 2026 (OPUC docket UE 452) and onward.

Other key items in the Order include the adoption of an earnings test for the twelve-month period ended October 31, 2026 at PGE’s authorized ROE, implemented via a deferral to track Seaside revenues and refund excess earnings, if applicable. The Company has contested the applicability of an earnings test and in addition has not accrued any refunds, as it currently does not forecast to over earn for the period covered by the test.

The Seaside revenue requirement was included in customer prices effective October 31, 2025.

Distribution System Plan recovery mechanism—On December 23, 2025, PGE and certain intervening parties submitted a stipulation to the OPUC reflecting an agreement that resolves all issues, with the exception of the application of an earnings test as proposed by intervening parties, in PGE's request for recovery in UE 459 related to the Company’s DSP Alternative Recovery Mechanism (ARM). The settlement and submitted stipulation were supported by an MOU entered into between PGE and key regulatory stakeholders. The MOU limited the scope of the ARM to specific capital investments included in the DSP docket (UM 2362) filed in December 2024, which enable network modernization, reliable customer service, and integration of clean energy and distributed energy resources.

Primary components of the stipulation include:

•
A rate base increase of $218 million;

•
9.34% ROE per the MOU reflecting PGE's latest rate case;

•
An annual revenue requirement increase of $57 million, compared to PGE's filed request of $72 million.

Of the $15 million of revenue requirement adjustments, approximately 87% are temporary in nature, allowing PGE to seek recovery of associated investments as applicable in its next GRC. These adjustments are driven primarily by non-distribution investments and are not attributable to specific assets. Per the previously noted MOU reached with stakeholders, the earliest possible rate effective date of PGE's next GRC would be May 1, 2027.

The terms of the stipulation remain subject to OPUC approval. The OPUC has adopted a procedural schedule for the regulatory review process in Docket UE 459 that anticipates an order in March 2026, with customer prices effective April 1, 2026. PGE cannot predict the ultimate outcome of the regulatory process.

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 December 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

57

Table of Contents

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 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. PGE received settlement proceeds related to Portland Harbor Superfund insurance coverage settlement agreements during 2025, which were deferred into the PHERA mechanism. PGE is continuing insurance recovery activity with additional insurers. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

New Large Load—In December 2023, the OPUC established Docket UE 430 to investigate new load connection costs. Following a lengthy regulatory process, in December 2024, PGE filed Advice No. 24-38 with the OPUC. This filing introduced 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 continue to be evaluated in a new Commission docket, UM 2377. This initial approval allowed 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. Applicable 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.

In June 2025, the Oregon Legislature passed HB 3546 relating to service to large data centers. HB 3546, which became effective in June 2025, directs the OPUC to provide a classification for retail customers deemed large energy use data center facilities. Any tariffs for the class must allocate costs to the class in a manner that is equal or proportional to the costs of serving the class, or directly assign the costs to large energy use data center facilities and avoid unwarranted shifting of costs to other classes. HB 3546 also directs the OPUC to require that electric companies serving data centers must enter into a contract for services with such customer under terms and conditions specified by the law. The OPUC has included HB 3546 alignment and establishment of a data center classification for retail customers within the scope of UM 2377 as well as other topics that may apply to all large load customers. The OPUC is expected to issue an Order in UM 2377 in the second quarter of 2026.

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 bundled with electricity in the wholesale marketplace.

PGE participates in the western EIM, which enables, among other benefits, greater integration of renewable energy onto the grid by better balancing the variable output of renewable resources.

The Company signed an implementation agreement and filed tariff changes with the FERC to join the EDAM, which is expected to build on the success of the western EIM and help provide PGE and its customers additional

58

Table of Contents

access to affordable, reliable, and clean energy. In August 2025, the FERC approved PGE’s revisions to its Open Access Transmission Tariff for EDAM participation. In September 2025, the California Legislature approved Assembly Bill 825 (the Pathways Bill), authorizing the CAISO to transition market governance, including the EDAM, to an independent regional organization.

The EDAM, anticipated to begin operation in 2026, will allow market participants to submit bids for their forecasted energy demand and available generation resources a day ahead of expected use. The EDAM will then optimize transmission and resource use across all market participants, enabling access to the lowest cost resources to meet regional needs. The EDAM is expected to leverage PGE's existing technology and systems and utilize 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 unified market platform.

As part of its ongoing commitment to reliably serving both retail and wholesale customers, PGE is evaluating alternatives to participation as a financially binding entity in the Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP). While PGE continues to support the regional planning and analytical framework established by the WRAP, the Company provided notice of withdrawal in October 2025. PGE is in collaboration with utilities committed to the EDAM and Oregon regulated load serving entities to develop and adopt a resource adequacy framework that enhances reliability, is aligned more closely with the EDAM design, and reflects the operational realities of a rapidly evolving electric grid across the western United States, with a target operational date of 2028.

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 megawatt 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. For further information regarding seasonal fluctuations, see “Seasonality” in the Customers and Revenues section in Item 1.—“Business.”

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 help 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.

59

Table of Contents

Customers and demand—The following tables present total energy deliveries and the average number of retail customers by type for 2025 and 2024.

Energy deliveries (MWh in thousands)

2025

2024

% Change

% Change (Weather-Adjusted)

Retail:

Residential

7,596

7,732

(1.8

)%

0.4

%

Commercial

6,467

6,509

(0.6

)

(0.2

)

Industrial

5,905

5,032

17.3

17.4

Subtotal

19,968

19,273

3.6

4.6

Direct access:

Commercial

548

515

6.4

6.4

Industrial

2,014

1,909

5.5

5.5

Subtotal

2,562

2,424

5.7

5.7

Total retail energy deliveries

22,530

21,697

3.8

4.7

Wholesale energy deliveries

9,392

9,722

(3.4

)

Total energy deliveries

31,922

31,419

1.6

Average number of retail customers

2025

2024

% Increase/

(Decrease)

Residential

840,457

88

%

829,721

88

%

1.3

%

Commercial

114,277

12

113,518

12

0.7

Industrial

218

—

208

—

4.8

Direct access

703

—

497

—

41.4

Total

955,655

100

%

943,944

100

%

1.2

In 2025, retail energy deliveries increased 3.8% from 2024, with increases in demand from industrial customers outweighing the decreases seen in the residential and commercial classes. The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Compared to the prior year, weather served to reduce deliveries, as temperatures were overall mild. Temperatures in the fourth quarter were mild, with December experiencing the warmest average temperature on record at the Portland International Airport.

Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 1.8% lower in 2025 than 2024, due to a 3% decrease in average usage per customer, which resulted largely from mild temperatures, and was partially offset by a 1.3% increase in the average number of customers. PGE has seen the number of rooftop solar installations increase in its service territory over the past few years, which continues to reduce the average usage per customer.

Commercial energy deliveries decreased 0.1% from the prior year driven by mild temperatures in 2025, impacts of programmatic energy efficiency and uncertainty in economic conditions that tempered commercial growth in 2024 and have continued into 2025.

Industrial energy deliveries increased 14.1% in 2025 due to continued strength in the digital service sector. Several large customers experienced continued growth in 2025 and new data center facilities came online.

60

Table of Contents

Total heating degree-days, an indication of electricity use for heating, declined 3% in 2025 from 2024 in total, and were 11% below the 15-year moving average. In 2025, heating degree-days were lower in each quarter of the year, except for the first quarter, which was only slightly higher. The fourth quarter, which is normally a high heating demand period, in 2025, was even milder than 2024, which was among the warmest ever recorded to that point. Correspondingly, cooling degree-days, a similar indication of the extent to which customers were likely to have used electricity for cooling, exceeded the 15-year average by 9%, although were 8% below the 2024 total, which was 18% above average, illustrating that the two most recent summer seasons have continued to see warm temperatures when compared to historical averages.

The following table presents the number of heating and cooling degree-days in 2025 and 2024, along with the current 15-year averages, reflecting the influence that weather had on comparative energy deliveries.

Heating Degree-Days

Cooling Degree-Days

2025

2024

15-Year

Average

2025

2024

15-Year

Average

1st quarter

1,772

1,755

1,819

4

—

—

2nd quarter

464

547

606

102

108

109

3rd quarter

19

36

60

588

643

521

4th quarter

1,294

1,324

1,502

—

—

6

Total

3,549

3,662

3,987

694

751

636

Increase (decrease) from the 15-year average

(11

)%

(8

)%

9

%

18

%

Customers are measured and reported in terms of individual service points, with certain companies, which are classified among the commercial, industrial, or Direct Access categories, having multiple service points. ESSs supplied Direct Access customers with energy representing 11% of PGE’s total retail energy deliveries during both 2025 and 2024. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 12% of the Company’s total retail energy deliveries for 2025. With the adoption of the New Large Load Direct Access program in 2020, as much as 16% of the Company’s 2025 energy deliveries could have been supplied by ESSs. The OPUC, under docket UM 2024, has undertaken an investigation of long-term 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 and energy storage resources and wholesale market transactions to meet the energy needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. 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.

61

Table of Contents

The following table provides information regarding the performance of the Company’s generation portfolio.

Plant

availability (1)

Actual energy provided

compared to projected levels (2)

Actual energy provided as a

percentage of total retail load

2025

2024

2025

2024

2025

2024

Thermal:

Natural gas

87

%

82

%

102

%

98

%

37

%

36

%

Coal (3)

79

78

97

93

6

6

Wind (4)

89

92

96

101

9

10

Hydro

85

93

99

96

4

4

(1)
Plant availability represents the percentage of the year 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 in 2025 compared to 2024 increased by 4%. This increase is primarily driven by economic dispatch decisions. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from all hydroelectric sources, both PGE-owned generation and purchased, increased 8% in 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 10% while energy generated by the Company-owned facilities decreased 5% in 2025. Energy expected to be received from hydroelectric resources in 2025 was projected in the AUT based on a modified hydro study, which utilizes 10 years of historical stream flow data. For further detail on regional hydro results, see “Purchased power and fuel” in the Results of Operations section in this Item 7.

Energy received from PGE-owned wind resources and under contracts decreased 9% in 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, PGE 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, which is reset annually by means of the AUT filings) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2025 and 2024:

•
For 2025, actual NVPC was below baseline NVPC by $6 million, which was within the established deadband range. Accordingly, there is no estimated refund to customers under the PCAM for 2025. A

62

Table of Contents

final determination regarding the 2025 PCAM results will be made by the OPUC through a public filing and review in 2026.

•
For 2024, actual NVPC was below baseline NVPC by $78 million, 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.

As approved by the OPUC in PGE’s 2024 GRC, the 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 RCE, see Note 7, Regulatory Assets and Liabilities in the Notes to Condensed Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Business transformation and optimization expenses—In 2025, PGE incurred $42 million incremental business transformation and optimization expenses, which include strategic advisory and workforce realignment expenses, focused on a multi-year cost management initiative to realize long-term benefits. For more information on the impact of these costs on annual results, see “Generation, transmission and distribution,” “Administrative and other,” “Depreciation and amortization,” and “Other income, net” in the Results of Operations section of this Overview. The Company expects to incur business transformation and optimization expenses related to these initiatives throughout 2026.

Additionally, PGE has incurred incremental accounting, legal, and consulting costs related to its submission of a regulatory application for approval of a holding company reorganization. For more on the corporate structure see “Corporate Structure” in the Regulatory Matters section of this Overview.

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 years presented (dollars in millions):

Years Ended December 31,

%

2025

2024

Increase

Amount

Amount

(Decrease)

Total revenues

$

3,576

$

3,440

4

%

Operating expenses:

Purchased power and fuel

1,411

1,418

—

Generation, transmission and distribution

450

436

3

Administrative and other

392

403

(3

)

Depreciation and amortization

578

496

17

Taxes other than income taxes

190

175

9

Total operating expenses

3,021

2,928

3

Income from operations

555

512

8

Interest expense, net *

232

211

10

Other income:

Allowance for equity funds used during construction

18

23

(22

)

Miscellaneous income, net

18

26

(31

)

Other income, net

36

49

(27

)

Income before income taxes

359

350

3

Income tax expense

53

37

43

Net income

$

306

$

313

(2

)%

* Includes an allowance for borrowed funds used during construction of $11 million in 2025 and $15 million in 2024.

63

Table of Contents

2025 Compared to 2024

Net income for 2025 decreased $7 million from 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 decline in the average price of wholesale deliveries, although lower sales volumes also contributed to the decline. Purchased power and fuel expense declined slightly, reflecting stable market conditions and lower commodity prices. Generation, transmission and distribution expenses were up slightly, while total Administrative and other expenses were reduced 3% from 2024. 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 primarily to lower PTC benefits.

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

2025

2024

%

Increase

(Decrease)

Retail:

Residential

$

1,486

$

1,457

2

%

Commercial

969

914

6

Industrial

536

435

23

Subtotal

2,991

2,806

7

Direct Access:

Commercial

16

10

60

Industrial

25

23

9

Subtotal

41

33

24

Subtotal Retail

3,032

2,839

7

Alternative revenue programs, net of amortization

21

(40

)

(153

)

Other accrued (deferred) revenues, net

17

16

6

Total retail revenues

3,070

2,815

9

Wholesale revenues

418

558

(25

)

Other operating revenues

88

67

31

Total revenues

$

3,576

$

3,440

4

%

Total retail revenues—The following items contributed to the increase in Total retail revenues for the year ended December 31, 2025 compared to the year ended December 31, 2024 (dollars in millions):

Year ended December 31, 2024

$

2,815

Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)

72

Retail energy deliveries driven by changes in customer demand

66

Change in average price of energy deliveries due primarily to changes in overall customer prices beyond the AUT, as approved by the OPUC

60

Clearwater RAC deferral (largely offset in Purchased power, Depreciation and amortization, and Income tax expense)

37

Wildfire mitigation, offset in operating expenses and amortization

23

Colstrip annual tariff update

16

Combination of various supplemental tariffs and adjustments

(19

)

Year ended December 31, 2025

3,070

Change in Total retail revenues

$

255

64

Table of Contents

Wholesale revenues result primarily from sales of electricity and environmental credits to utilities and power marketers made in the Company’s efforts to meet the needs of, and secure reasonably priced power for, its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.

In 2025, a $140 million, or 25%, decrease from 2024 in wholesale revenues occurred as a $90 million decrease resulted from lower average prices received when the Company sold power into the wholesale market. The decline in average sales prices resulted in large part to market volatility around specific regional weather events in January 2024 and milder overall weather in 2025. In addition, sales volumes decreased 3%, which resulted in a $19 million decrease, and the Company sold $32 million fewer environmental credits in 2025 than in the prior year.

Other operating revenues increased $21 million, or 31%, in 2025 from 2024, with the largest contributors being an increase from imbalance transactions with ESS providers, which is offset in Purchased power and fuel expense, and additional joint pole revenues.

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 year ended December 31, 2025 compared to the year ended December 31, 2024 (dollars in millions):

Year ended December 31, 2024

$

1,418

Average variable power cost per MWh

(109

)

Total system load

27

2021 PCAM deferral amortization

(15

)

RCE deferral activity, net

90

Year ended December 31, 2025

1,411

Change in Purchased power and fuel

$

(7

)

Average variable power cost per MWh (in dollars):

Year ended December 31, 2024

$

49.08

Year ended December 31, 2025

$

45.63

Total system load (MWh in thousands):

Year ended December 31, 2024

30,348

Year ended December 31, 2025

30,848

For the year ended December 31, 2025, the $109 million decrease related to the change in average variable power cost per MWh was primarily driven by an 11% decrease in the average cost for purchased power, offset by a 3% increase in the average cost for the Company’s own generation. The $27 million increase related to total system load was comprised of a 2% increase in energy obtained from purchased power, and a 1% increase in energy obtained from PGE’s own generation.

65

Table of Contents

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

Years Ended December 31,

2025

2024

Sources of energy (MWh in thousands):

Generation:

Thermal:

Natural gas

11,424

37

%

10,939

36

%

Coal

1,936

6

1,910

6

Total thermal

13,360

43

12,849

42

Hydro

1,205

4

1,267

4

Wind

2,711

9

2,922

10

Total generation

17,276

56

17,038

56

Purchased power:

Hydro

7,431

24

6,752

22

Wind

1,195

4

1,386

5

Solar

1,415

5

1,119

4

Natural Gas

885

3

94

—

Waste, Wood and Landfill Gas

107

—

170

1

Source not specified

2,539

8

3,789

12

Total purchased power

13,572

44

13,310

44

Total system load

30,848

100

%

30,348

100

%

Less: wholesale sales

(9,383

)

(9,722

)

Retail load requirement

21,465

20,626

Purchased power in the table above includes power received from QFs as follows:

Years Ended December 31,

2025

2024

Sources of energy (MWhs in thousands):

PURPA purchased power:

Hydro

29

31

Wind

29

29

Solar

605

580

Waste, Wood, Landfill Gas, and Other

107

117

Total

770

757

The following table presents the forecasted April-to-September 2026 and actual April-to-September 2025 and 2024 runoff at particular points of major rivers relevant to PGE’s hydro resources:

Runoff as a Percent of Normal*

Location

2026

Forecast

2025

Actual

2024

Actual

Columbia River at The Dalles, Oregon

94

%

77

%

74

%

Mid-Columbia River at Grand Coulee, Washington

101

78

74

Clackamas River at Estacada, Oregon

76

69

91

Deschutes River at Moody, Oregon

90

93

93

* 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.

66

Table of Contents

Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $133 million in 2025 compared with 2024. The increase attributable to changes in Purchased power and fuel expense was the result of a 7% decrease in the average variable power cost per MWh and a 2% increase in total system load. This was partially offset by an decrease in wholesale revenues driven by a 22% decrease in the volume of wholesale energy deliveries and a 3% lower average price per MWh sold.

The following items contributed to the increase in actual NVPC for the year ended December 31, 2025 compared to the year ended December 31, 2024 (in millions):

Year ended December 31, 2024

$

860

Purchased power and fuel expense

(82

)

Wholesale revenues

140

2021 PCAM deferral amortization

(15

)

RCE deferral activity, net

90

Year ended December 31, 2025

993

Change in NVPC

$

133

For further information regarding NVPC in relation to the PCAM, see “Power operations” in the Overview section of this Item 7.

Generation, transmission and distribution expense increased $14 million or 3% for the year ended December 31, 2025 compared to the year ended December 31, 2024, with the change attributed largely to the following items (in millions):

Year ended December 31, 2024

$

436

Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses

5

Generation facility maintenance expenses driven by major maintenance activities and decreased run hours

(15

)

Service restoration and storm response costs

9

Business transformation and optimization expenses

5

Energy storage

4

Miscellaneous expenses

6

Year ended December 31, 2025

450

Change in Generation, transmission and distribution

$

14

In the table above, $(2) million related to vegetation management, $13 million related to wildfire mitigation, $9 million related to storm response costs and $5 million related to major maintenance have been offset through customer prices or specific regulatory mechanisms.

Administrative and other expense decreased $11 million, or 3%, for the year ended December 31, 2025 compared to the year ended December 31, 2024 due largely to the following items (in millions):

Year ended December 31, 2024

$

403

Employee compensation and benefits expenses

(4

)

Regulatory and professional service costs

2

Customer related costs

(18

)

Business transformation and optimization expenses

32

Amortization of COVID-19 bad debt expense deferral

(13

)

Miscellaneous expenses

(10

)

Year ended December 31, 2025

392

Change in Administrative and other

$

(11

)

67

Table of Contents

In the table above, $7 million of the decrease in customer related costs is due to regulatory programs that have been offset through customer prices or specific regulatory mechanisms.

Depreciation and amortization expense increased $82 million or 17% for the year ended December 31, 2025 compared to year ended December 31, 2024, with the change largely resulting from the following items (in millions):

Year ended December 31, 2024

$

496

Capital additions

69

Business transformation and optimization expenses

1

Activity related to regulatory programs (offset elsewhere on the income statement)

1

Right of use asset amortization expenses

11

Year ended December 31, 2025

578

Change in Depreciation and amortization

$

82

Taxes other than income taxes expense increased $15 million, or 9%, in 2025 compared with 2024, primarily due to higher franchise fees and property tax expenses slightly offset by lower payroll taxes.

Interest expense increased $21 million, or 10%, in 2025 compared with 2024 driven by higher average balances of outstanding debt.

Other income, net decreased $13 million, or 27%, in 2025 compared to 2024. The decrease was primarily attributable to lower AFUDC equity income driven by lower construction work-in progress balances and $4 million in business transformation and optimization expenses related to pension settlements.

Income tax expense increased $16 million, or 43%, in 2025 compared to 2024 primarily driven by decreased PTC benefits resulting from expiration of the 10-year PTC generation window at Tucannon near the end of 2024 and higher pre-tax income as compared to the prior year.

2024 Compared to 2023

For a comparison of the Company’s results of operations for the fiscal year ended December 31, 2024 to the year ended December 31, 2023, see Item 7.—” Management’s Discussion and Analysis of Financial Condition and Results of Operations” in 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

Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan.” in Item 1A.—“Risk Factors,” for further information.

68

Table of Contents

Capital Requirements

The following table presents actual capital expenditures and debt maturities for 2025 and projected capital expenditures and future debt maturities for 2026 through 2030 (in millions, excluding AFUDC):

Years Ended December 31,

2025

2026

2027

2028

2029

2030

Ongoing capital expenditures (1)

$

642

$

865

$

895

$

925

$

925

$

925

Transmission

174

215

390

420

515

525

Clearwater

7

—

—

—

—

—

BESS projects

320

—

—

—

—

—

Hybrid projects

—

575

455

—

—

—

Total capital expenditures (2)

$

1,143

$

1,655

$

1,740

$

1,345

$

1,440

$

1,450

Long-term debt maturities

$

170

$

—

$

160

$

100

$

200

$

325

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

(2)
Amounts subsequent to 2025 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.

During 2025, PGE funded its capital expenditures through a combination of cash from operations in the amount of $1.1 billion, proceeds from the issuance of FMBs in the total amount of $310 million, and net proceeds from the issuance of shares pursuant to the at-the-market offering program of $250 million. Capital expenditures in 2026 are expected to be approximately $1.7 billion. PGE plans to fund the 2026 capital expenditures with cash from operations during 2026, which is expected to range from $1 billion to $1.2 billion, the issuance of debt securities of up to $350 million, the issuance of equity securities of up to $300 million, and the issuance of 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. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

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 generation, transmission, distribution, and energy storage facilities to support both new and existing customers, along with information technology systems and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

The pending Acquisition to acquire PacifiCorp’s Washington state regulated utility business will require financing of $1.9 billion. The acquisition is supported by a fully committed bridge facility with Barclays Bank PLC and JPMorgan Chase Bank, N.A. for $1.9 billion. The Company expects to permanently finance the transaction through a balanced mix of debt, equity, and its minority investment partner, Manulife Infrastructure Fund III L.P. (“Manulife”) and its affiliates including John Hancock Life Insurance Company (USA). In connection with the financing plan, PGE expects equity commitments from Manulife to finance up to $600 million of the purchase. Assuming the closing of the transactions contemplated by the Agreement and the consummation of the financing transactions, Manulife will be the Company's joint venture partner in the business. PGE would remain majority owner and sole operator.

69

Table of Contents

The Company believes its cash flow from operating activities, access to credit markets, and its credit facilities provide sufficient liquidity to support estimated future cash requirements, including the cash consideration necessary to close on the proposed Acquisition. For additional information on the proposed acquisition, see “Pending Acquisition” in the Overview section in this Item 7., and Note 21, Subsequent Events, in Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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

Years Ended December 31,

2025

2024

Cash and cash equivalents, beginning of year

$

12

$

5

Net cash provided by (used in):

Operating activities

1,118

778

Investing activities

(1,196

)

(1,297

)

Financing activities

142

526

Net change in cash and cash equivalents

64

7

Cash and cash equivalents, end of year

$

76

$

12

2025 Compared to 2024

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 2025 compared to 2024 (dollars in millions):

Increase/

(Decrease)

Net income

$

(7

)

Accounts receivable and unbilled revenue

50

Margin deposit activity

58

Accounts payable

(3

)

Regulatory deferral activity

149

Depreciation and amortization

82

Deferred income taxes

14

Tax credit sales

67

Alternative revenue programs

(61

)

Other miscellaneous changes

(9

)

Net change in cash flow from operations

$

340

For additional information regarding changes in Net income, see the Results of Operations section in this Item 7.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that total depreciation and amortization in 2026 will range from $560 million to $580 million. Combined with all other sources, cash provided by operations in 2026 is estimated to range from $1 billion to $1.2 billion.

Cash provided by operations includes the recovery in customer prices of cash charges related to various long-term contractual obligations such as interest on long-term debt and purchased power and fuel contracts. PGE’s anticipated employer contributions for its defined benefit pension plan and other postretirement plans is $26 million in 2026, $23 million in 2027, $20 million in 2028, $18 million in 2029, and $17 million in 2030. Contributions are expected to be covered by cash provided by operations. For additional information regarding

70

Table of Contents

contractual obligations, see Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation, transmission, distribution, and energy storage facilities. The $101 million decrease in net cash used in investing activities in 2025 compared with 2024 is primarily due to capital expenditures related to BESS projects and other new construction and improvements to PGE’s distribution, transmission, and generation facilities.

The Company plans for $1.7 billion of capital expenditures in 2026 related to upgrades to and replacement of generation, transmission, and distribution infrastructure as well as costs related to hybrid projects. PGE plans to fund the 2026 capital expenditures with cash from operations during 2026, as discussed above, as well as with the issuance of debt, issuances of shares pursuant to the at-the-market offering program, and short-term debt as necessary. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2025, cash provided by financing activities was primarily the result of the funding of $310 million in FMBs and $250 million in proceeds from the issuance of common stock pursuant to at-the-market offering programs. This was partially offset by payments of dividends in the amount of $225 million and $170 million of long-term debt.

2024 Compared to 2023

For a comparison of liquidity and capital resources and the Company’s cash flow activities for the fiscal year ended December 31, 2024 and 2023, see Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on February 14, 2025.

Credit Ratings and Debt Covenants

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

Moody’s

S&P

Issuer credit rating

A3

BBB+

Senior secured debt

A1

A

Commercial paper

P-2

A-2

Outlook

Stable

Stable

In December 2025, Moody’s revised the Company’s outlook from Negative back to Stable as a result of the Company's improved metrics, which are expected to remain above the downgrade threshold.

In the event Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to higher fees on its revolving credit facility. The Company could also 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, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE’s consolidated balance sheets, while any letters of credit issued are not reflected in the Company’s consolidated balance sheets.

As of December 31, 2025, PGE had posted $239 million of collateral with these counterparties, consisting of $116 million in cash and $123 million in bank letters of credit. Based on the Company’s energy portfolio,

71

Table of Contents

estimates of energy market prices, and the level of collateral outstanding as of December 31, 2025, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $70 million and decreases to $54 million by December 31, 2026 and $3 million by December 31, 2027. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade as of December 31, 2025 is $168 million and decreases to $150 million by December 31, 2026 and $66 million by December 31, 2027.

On December 24, 2025, PGE executed an amendment to an existing enabling agreement with a counterparty that was holding $158 million of PGE collateral, consisting of $48 million in cash and $110 million in bank letters of credit. The amendment provided a cap of the amount required based on credit ratings. This resulted in the recall of $128 million of the posted collateral in January 2026, consisting of $48 million in cash and $80 million in bank letters of credit.

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 securing the bonds. PGE estimates that on December 31, 2025, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $785 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 of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facilities contain 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 December 31, 2025, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 53.0%.

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.

Short-term Debt—Pursuant to an order issued by the FERC on January 12, 2026, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2028. The following table shows available liquidity as of December 31, 2025 (in millions):

72

Table of Contents

December 31, 2025

Capacity

Outstanding

Available

Revolving credit facility (1)

$

750

$

—

$

750

Letters of credit (2)

320

192

128

Total credit

$

1,070

$

192

878

Cash and cash equivalents

76

Total liquidity

$

954

(1)
Scheduled to expire in September 2030, PGE has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay outstanding commercial paper. As of December 31, 2025, PGE had no commercial paper outstanding, therefore, the elected available credit capacity is $750 million.

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

As of December 31, 2025, PGE had a $750 million unsecured revolving credit facility scheduled to expire in September 2030. 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 then remaining term of the applicable credit facility.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 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 in the consolidated balance sheets.

Under the revolving credit facility, as of December 31, 2025, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2025, the aggregate unused available credit capacity under the revolving credit facility was $750 million.

In addition, PGE has four letter of credit facilities under which the Company has total capacity of $320 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, which are considered off-balance sheet arrangements, letters of credit for a total of $192 million were outstanding as of December 31, 2025. PGE works to optimize its use of its letter of credit facility to manage energy trading margin.

Long-term Debt—During 2025, PGE issued and funded a total of $310 million of Long-term Debt and repaid a total of $170 million.

On March 25, 2025, PGE entered into a Bond Purchase Agreement related to the sale of $310 million in 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%.

73

Table of Contents

On November 14, 2024, PGE obtained a 366-day term loan from lenders in the aggregate principal of $300 million under a 366-Day Bridge Credit Agreement. Pursuant to the Agreement, on November 14, 2024, PGE drew a loan from the Lenders in the aggregate principal of $220 million. The term loan bore interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 80.0 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On December 31, 2024, PGE repaid $50 million of the term loan, leaving an outstanding balance of $170 million. On March 31, 2025, the Company repaid another $102 million, and on October 27, 2025 repaid the remaining balance of $68 million, repaying the loan in full.

As of December 31, 2025, total long-term debt outstanding, net of $17 million of unamortized debt expense, was $4,662 million, none of which is scheduled to mature in 2026.

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. The Company entered into forward sale agreements for 5,756,432 shares and 1,420,049 shares in 2025 and 2024, respectively. In 2024, the Company issued 1,066,549 shares pursuant to the forward sale agreements and received net proceeds of $50 million. During 2025, the Company issued 5,919,618 shares pursuant to the forward sale agreements and received net proceeds of $250 million. The Company could have physically settled the remaining amount by delivering 190,314 shares in exchange for cash of $8 million as of December 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.

PGE anticipates entering into a new at-the-market offering program in the first quarter of 2026. 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 program, see Note 13, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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 debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 47.0% and 45.6% as of December 31, 2025 and 2024, respectively.

Critical Accounting Policies and Estimates

The preparation of consolidated financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain.

Regulatory Accounting

As a rate-regulated enterprise, PGE applies regulatory accounting, which includes the recognition of regulatory assets and liabilities on the Company’s consolidated balance sheets. Regulatory assets represent probable future revenue associated with certain incurred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited or refunded to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established or subject to approval by independent third-party regulators, prices are designed to recover the specific enterprise’s cost-of-service, and, in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Amortization of regulatory assets and liabilities is reflected in the statement of income over the period in which they are included in customer prices.

74

Table of Contents

If future recovery of regulatory assets is not probable, PGE would expense such items in the period such determination is made. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting. Discontinued application of regulatory accounting would have a material impact on the Company’s results of operations and financial position.

For additional information on PGE’s regulatory assets and liabilities, see “Regulatory Matters” in the Overview section in this Item 7., and Note 7, Regulatory Assets and Liabilities in Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Asset Retirement Obligations

PGE recognizes AROs for legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Estimates for ARO liabilities are generally based on site-specific studies and are periodically subject to updates and changes that may arise over time.

Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions to ARO liabilities in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Accretion of the ARO liability is classified as Depreciation and amortization expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets.

As a co-owner of Colstrip, PGE has provided surety bonds, which are considered off-balance sheet arrangements, of $18 million as of December 31, 2025 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC.

For additional information on AROs, see Note 8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Contingencies

PGE has various unresolved legal and regulatory matters about which there is inherent uncertainty, with the ultimate outcome contingent upon several factors. Such contingencies are evaluated using the best information available. A loss contingency is accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency and the reasons to the effect that it cannot be reasonably estimated are disclosed. A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate

75

Table of Contents

or range of potential loss is material. Established accruals reflect management’s assessment of inherent risks, credit worthiness, and complexities involved in the process. There can be no assurance as to the ultimate outcome of any particular contingency.

For additional information on contingencies, see Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”