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 (IRS), with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs and capital investments, energy trading activities, tax credits, and current or prospective wholesale and retail competition;
•uncertainties associated with energy demand that differs from forecasts, including significant or accelerated load growth from new data centers and the concentration of data center load, and the ability to timely serve such growth due to regulatory, environmental, and other permitting requirements;
•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 the procurement of resources through current or future All-Source Request for Proposals (RFP) projects or other regulatory mechanisms, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of trade tariffs), permitting and construction delays, available tax credits, counterparty credit risk, 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, price increases, reduced consumption or load shifting resulting from energy efficiency measures or other changes in customer behavior, increased adoption of distributed and renewable generation, and an increased likelihood that customers procure electricity from alternative service providers such as registered Electricity Service Suppliers (ESSs) or through community choice aggregation programs;
•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”
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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 escalation of US operations in the Middle East, that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;
•changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes, including the potential impact of trade tariffs and the escalation of US operations in the Middle East, on the Company’s power costs;
•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;
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•changes in, compliance with, and general uncertainty around environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
•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, the use or misuse of artificial intelligence technologies, including AI-enabled cyberattacks, fraud, misinformation, unauthorized disclosure of sensitive information, operational errors, or other malicious acts, internally or to third parties, that cause damage to the Company’s generation, transmission, or distribution facilities, impact information technology or operational technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, vendor, employee, or Company information;
•reputational damage from negative publicity, protests, fines, penalties and other negative consequences resulting in regulatory and/or legal actions;
•employee workforce factors, including labor strikes, work stoppages, collective bargaining negotiations that result in increased labor costs or other less favorable terms, the inability to obtain contracted workers at reasonable rates during a labor disruption, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover resulting from macroeconomic conditions such as elevated levels of voluntary resignations, any of which could increase costs and adversely affect operations and financial results;
•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 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, including the escalation of US operations in the Middle East, which could amplify the effects of any of the above risk factors and contribute to volatility in capital market conditions, interest rates and inflation; and
•uncertainties associated with the proposed Acquisition, including but not limited to, the expected closing of the proposed transaction and the timing thereof, the financing of the proposed transaction, strategies and plans, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow.
Additional disclosures regarding risks, uncertainties and important factors that could cause PGE’s results or performance to differ from the statements made in this report are discussed in Part I, Item 1A. “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 17, 2026, and in Part II, Item 1A. “Risk Factors” of this Quarterly Report on Form 10-Q.
Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
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OVERVIEW
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.
PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State of Oregon (State). The Company participates in wholesale markets by purchasing and selling electricity, natural gas, and environmental credits in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory in the State.
Company Strategy
PGE's corporate strategy places customers at the center of everything the Company does. PGE supports energizing lives, strengthening communities, and driving advancement in energy to promote social, economic, and environmental progress. With a focus on affordability, the Company continuously innovates, streamlines, and manages costs to deliver exceptional experiences for its customers. The Company is committed to delivering steady growth and returns to shareholders. The Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region.
PGE is focused on the following strategic imperatives:
•Decarbonize Power—make progress toward customer-driven clean energy goals by continuing to add new renewable and non-emitting resources and products to the Company's energy mix;
•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—continue to build a safer and more reliable grid by accelerating cost-effective grid investments and modernizing transmission.
Pending Acquisition
On February 15, 2026, PGE, through a newly formed, wholly-owned subsidiary, entered into an agreement (the “Agreement”) with PacifiCorp, an indirect subsidiary of Berkshire Hathaway Energy Company, to acquire select Washington state generation, transmission, and electric utility operations for $1.9 billion. The Acquisition would enable PGE to extend its service to approximately 140,000 Washington customers.
Under the Agreement, if the Acquisition is completed, PGE will acquire three generation facilities: the Chehalis thermal plant (477 MW), the Goodnoe Hills wind facility (94 MW), and the Marengo I and II wind facilities (234 MW). The Acquisition would also include 4,500 miles of transmission and distribution lines, and local utility operations across approximately 2,700 square miles.
PGE intends to manage the Washington operations as a separate company through a newly created subsidiary to be regulated by the Washington Utilities and Transportation Commission (WUTC). PGE intends to retain current Washington employees and honor existing labor agreements. PGE corporate functions are expected to provide shared support for both Washington and Oregon companies.
The Acquisition is designed with the goal that Washington and Oregon customers would not be impacted by costs associated with executing the acquisition and transaction financing. PGE expects the Acquisition and state and federal regulatory reviews to close in approximately twelve months following the submission of regulatory applications. Regulatory applications were submitted to the WUTC and the OPUC on March 30, 2026 and April 2, 2026, respectively. On July 15, 2026, the Company, jointly with other parties, submitted an application to the FERC seeking approval of the transaction, requesting a decision by December 15, 2026.
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Central to this Acquisition is PGE’s plan to enter into a joint venture with Manulife Infrastructure Fund III, L.P. and its affiliates, including John Hancock Life Insurance Company (U.S.A.), which will collectively be a minority owner of the Washington utility business. PGE would remain majority owner and sole operator.
For more information regarding PGE’s plans to fund its future capital requirements, including this proposed Acquisition, see “Liquidity” in the Liquidity and Capital Resources section of this Item 2. See "Pending Acquisition" in Note 1, Basis of Presentation, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” for additional information on the pending acquisition.
Climate Change
State-mandated GHG emissions reduction targets—In 2021, the Oregon legislature passed House Bill (HB) 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the State. A number of provisions in the bill align with PGE’s strategic direction and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG emissions reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the “Laws and Regulations” section of this Overview.
Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 213 thousand residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100% clean and renewable electricity by 2035 and 100% economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have similar goals and continue to consider similar goals for the future.
The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows large business and municipal customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy either from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.
As of June 30, 2026, the Green Future Impact Program has an approved capacity of 750 megawatts (MW) nameplate, of which 482 MW have been subscribed. Through this voluntary program, the Company seeks to support customers’ clean energy acceleration.
Severe weather—In recent years, PGE’s service territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. In December 2025, Portland, Oregon experienced the warmest December on record, averaging six degrees above normal temperatures for the region. In January 2024, the Company’s service territory encountered a severe winter weather event, including snow, ice, and high winds that caused catastrophic damage to physical assets and resulted in widespread customer power outages. For more information regarding the January 2024 severe winter weather event, see “Declared States of Emergency” within this Overview section. In August 2023 the region experienced a record-breaking heat wave with temperatures reaching all-time recorded highs for the month. This resulted in a peak load demand of 4,498 MW, exceeding the Company’s previous all-time peak load demand, and surpassing the prior summer peak load by nearly six percent. The increase and severity of weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.
Investing in a Clean Energy Future
The Resource Planning Process—PGE’s resource planning process includes preliminary and ongoing engagement with customers, stakeholders, regulators, and other interested parties to help inform the Company’s assessment of future energy needs and resource options. Through its Integrated Resource Plan (IRP) and Clean Energy Plan (CEP) processes, PGE evaluates multiple planning scenarios using forecasts, modeling, stakeholder input, surveys, and other available data.
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With the passage of HB 2021, PGE created a CEP which articulates the Company’s strategy to make continued progress toward 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.
In June 2025, PGE submitted a CEP/IRP Update to the OPUC. The CEP/IRP Update refreshed forecasts and planning assumptions used in the 2023 CEP/IRP and identified a new Preferred Portfolio as a result of the updated analysis. PGE did not propose changes to the Action Plan acknowledged in the 2023 CEP/IRP, which supports the Company's progress toward emissions targets and Preferred Portfolio resource procurement needs through the 2025 All-Source RFP. Based on the information available at the time, PGE concluded that this approach represented the best combination of cost, risk, community benefit, and decarbonization objectives.
To better distinguish resource needs, the CEP/IRP Update reports capacity from hybrid solar and battery storage resources by individual technology. The Update identified a need for approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity, inclusive of 2023 and 2025 RFP projects, or any other additional resource procurement activities outside of the RFP. These estimates are based on planning assumptions and forecasts that may change as market conditions, customer needs, stakeholder input, and regulatory requirements continue to evolve.
PGE is continuing discussions with customers, stakeholders, and the OPUC regarding PGE’s path forward through the engagement process for the 2026 Clean Energy Plan and Integrated Resource Plan, which the company plans to file in the third quarter of 2026. PGE is continuing to refine its analysis, forecasts, resource needs, and preferred strategies to support continued progress toward emission targets while serving customers safely, reliably, equitably, and at the lowest reasonable cost.
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 in addition to the Company’s 2023 RFP:
•Meadowlark BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project will be owned by Copenhagen Infrastructure Partners, LLC and has an estimated commercial operation date at the end of 2027.
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•Nottingham BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project has an estimated commercial operation date in 2028, 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 in April 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 submitted a request for acknowledgement of the final shortlist of bidders to the OPUC on February 17, 2026. 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, or any other additional resource procurement activities outside of the RFP, may involve the selection of multiple projects for both renewable and non-emitting dispatchable capacity resources, which PGE expects will be approximately 2,500 MWs in total.
On May 26, 2026 the OPUC acknowledged the 2025 RFP final shortlist. Additional details of the 2025 RFP (OPUC Docket UM 2371) are available on the OPUC website at www.oregon.gov/puc.
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Transmission Upgrades
In alignment with local and regional transmission plans, the 2023 IRP Action Plan, and CEP Update, PGE is evaluating and implementing upgrades to existing transmission resources and expansions of current transmission networks. Transmission resource actions are intended to alleviate congestion, improve regional adequacy and reliability, enable decarbonization goals, and address growing customer demand.
In May 2024, PGE signed a non-binding memorandum of understanding in the development of the North Plains Connector, an approximately 415-mile, high-voltage direct-current (HVDC) transmission line to be constructed with endpoints near Bismarck, North Dakota and Colstrip, Montana. The parties entered negotiations with the United States Department of Energy (U.S. DOE) to finalize the project objectives, terms, and conditions, including the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. In August 2024, the project was awarded a $700 million grant from the U.S. DOE’s Grid Resilience and Innovation Partnerships (GRIP) program to further support its development and would reduce the overall total investment of the project. A portion of the GRIP funding is also allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants and effect of Presidential executive orders.
The North Plains Connector would be the nation’s first HVDC transmission connection among three regional U.S. electric energy markets, providing additional flexibility and the sharing of resources across multiple time zones. PGE's resource planning process indicates the need for transmission to provide additional transfer capacity, access to diverse energy resources and enhanced wholesale markets, and ease congestion on the existing western transmission system. PGE continues to explore the North Plains Connector as a resource to help meet those load-service needs.
The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS), with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project (Warm Springs Power Pathway) will accelerate the development of transmission capacity, enabling new generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS communities by increasing resources available to the CTWS to support economic growth opportunities. See “Federal Grants” in the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants.
Building a resilient grid—To serve communities with clean energy, PGE’s grid of the future will need to be smart and adaptive. Highlights of PGE’s key investments and plans for building a resilient grid include:
•Wildfire Mitigation—PGE has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC, as required by State law, to coordinate activities across the Company and with State-wide stakeholders. In December 2025, PGE filed its 2026-2028 Wildfire Mitigation Plan, which forecasts $47 to $50 million annually in operations and maintenance costs and an additional $70 to $84 million annually in capital investments, for the 2026-2028 period, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the six months ended June 30, 2026, PGE invested $38 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 participation in PGE’s VPP grows, customer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.
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•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 2022 and 2023, respectively. The OPUC Staff finalized their review of modifications to the current DSP guidelines in the fourth quarter of 2024 and PGE filed its next DSP in December 2024, 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 “DSP recovery mechanism” in the Regulatory Matters section of this Overview.
Electrify the economy—To help Oregon reach its decarbonization goals, PGE is committed to increasing electrification of buildings and supporting vehicle electrification for customers.
Transportation electrification (TE) is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to manage EV charging load, develop infrastructure projects aimed at improving accessibility to EV charging stations, build electric fleet partnerships, and offer programs to support customers’ transitions to TE.
In December 2025, the OPUC accepted PGE's 2026-2028 TE Plan. The plan considers current and planned activities, along with forecasted EV loads for the 2026-2028 period, with expected capital expenditures to be approximately $11 million.
PGE continues to pursue advanced technologies to enhance the grid, pursue energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs.
Laws and Regulations
Trade Tariffs—U.S. trade policy and tariff measures continue to evolve through a combination of existing and newly implemented tariff programs, ongoing litigation, and potential future trade actions. These evolving measures may increase the cost of raw materials and equipment, disrupt global supply chains, and contribute to volatility in commodity, capital, and credit markets. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase, which could affect materials and supplies balances and increase capital projects costs. Similarly, procurement costs may rise and lead times may lengthen for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. Although PGE does not expect a material impact on its Canadian natural gas imports from recent Canada-related actions, future trade actions involving Canada could affect commodity markets, supply chains, or procurement costs. Recent tariff actions affecting particular countries and product categories, as well as the possibility of additional trade measures, have increased uncertainty regarding future equipment costs and supply availability. The Company is unable to reasonably estimate the effects of the rapidly 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.
In October 2025, PGE received notice from the U.S. DOE of the termination of four federal grants that originally planned to provide $61 million in federal reimbursement over the life of the grants. PGE has incurred an immaterial amount of
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costs for projects associated with the terminated grants and does not expect the termination process to result in a material impact on the Company’s financial position and results of operations.
PGE has been awarded, either as a direct recipient or subrecipient, five additional grants totaling approximately $252 million. These grants remain in various stages of execution, with the largest being the Warm Springs Power Pathway. PGE continues to monitor these grants for potential modification or termination but has not received any formal notice of termination. To date, PGE has incurred only immaterial costs related to these grants. See “Transmission Upgrades” in the Investing in a Clean Energy Future section of this Overview for further discussion on the Warm Springs Power Pathway grant. The Company cannot predict the ultimate timing and success of securing funding from federal programs or predict the outcome of existing grants.
Inflation Reduction Act of 2022 (IRA)—The IRA was signed into law in 2022. The United States Treasury and the IRS released extensive rules addressing credit transfer eligibility and application, including but not limited to, required registration, filing, and documentation for transferors and transferees to elect and claim a credit transfer.
In 2024, PGE received approval from the OPUC to transfer PTCs generated in 2024 and 2025 and to record any difference between the full value and the discounted value in a property balancing account. On April 15, 2026, PGE received approval from the OPUC to transfer PTCs generated in 2026 and 2027 and to record any difference between the full value and the discounted value in a property balancing account.
PGE has entered into agreements to transfer tax credits and transferred $12 million and $13 million, net of discounts, for cash proceeds in the first six months of 2026 and 2025, respectively. PGE transferred tax credits, net of discounts, of $179 million in 2025. For the remainder of 2026, the Company expects to generate and transfer approximately $25 million of additional tax credits, net of discounts.
The One Big Beautiful Bill Act (OBBBA)—The OBBBA significantly amended or repealed several renewable-energy tax incentives originally enacted under the IRA. Projects previously placed in service that met applicable tax credit qualification requirements received PTC or ITC benefits, which are reflected in the Company’s condensed consolidated financial statements. The transferability of tax credits, as provided under the IRA, also remains in effect. In August 2025, the U.S. Treasury issued a notice for establishing the beginning of construction for wind and solar projects. The notice required large projects to satisfy a physical-work test after September 2, 2025, eliminated certain inventory-procurement safe harbors, and accelerated the placed in service deadline to December 31, 2027. A subsequent court ruling invalidated the August 2025 notice, although debate continues as to the repercussions. Since the effect of the court ruling on the Company remains unclear, PGE has not changed its method of determining qualifying projects, treating them as if the notice remains in effect.
These changes, together with the repeal of the permanent ten percent ITC, as outlined in the OBBBA, are expected to reduce or eliminate the availability of renewable energy tax incentives on future projects.
See “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview for information regarding the impact of the OBBBA on the RFP process.
HB 2021—Among other things, HB 2021 requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers to certain targets: 80% reduction by 2030; 90% by 2035; and 100% by 2040, compared to a baseline emission level. The baseline emission level is calculated for each provider by using average annual emissions associated with power generated and purchased for retail load for the years 2010 through 2012.
HB 2021 requires utilities to develop a CEP for meeting the reduction targets, concurrent with each IRP. In reviewing a CEP, the OPUC must ensure that utilities take actions as soon as practicable that facilitate rapid reduction of GHG emissions, demonstrate continual progress toward meeting the targets, and create a plan that is in the public interest. Further, the CEP must result in an affordable, reliable, and clean electric system. The law does not require particular GHG percentage reductions be attained until 2030. The law contains affordability and reliability related provisions that can slow or pause compliance with the GHG targets, if implicated. The OPUC has a current open docket, UM 2273, in which provisions regarding the cost cap are being investigated. In addition, a rulemaking docket, AR 685, seeks to develop a framework around the components and calculation of the cost cap, including costs already incurred in compliance.
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A separate law adopted in 2009 requires retail electricity providers to report annually to the Oregon Department of Environmental Quality (ODEQ) the GHG emissions associated with electricity used to serve retail customers. The OPUC must use the data reported to the ODEQ to determine whether the GHG targets have been met.
RPS standards and related laws—In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable sources by dates certain and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers on or before January 1, 2030, although an exception in the law may extend this date five years for the output of Colstrip Units 3 and 4 coal-fired generating plant (Colstrip).
The Company has a 20% ownership share in Colstrip and has fully depreciated the facility as of December 31, 2025. Any capital spending after 2025 is expected to be fully depreciated within the year of spending. The forecasted annual revenue requirement for Colstrip, including depreciation, is updated annually in a separate, supplemental tariff and recovery of power cost related items is sought annually under the AUT. In order to meet PGE’s regulatory, legislative, and reliability requirements, the Company continues to evaluate its ongoing ownership interest in Colstrip.
Any reduction in generation from Colstrip has the potential to provide additional capacity availability on the Colstrip transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in the Pacific Northwest and neighboring states. PGE has an approximate 15% ownership interest in, and capacity on, the Colstrip transmission facilities. See the Investing in a Clean Energy Future section of this Overview for information regarding development in eastern Montana.
Other provisions of SB 1547:
•established RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040, for the percentage of electricity that must come from renewable sources;
•limited the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continue unlimited lifespan for all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and
•provided opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s RAC filings.
During the second quarter of 2026, the Company submitted its RPS report for 2025, which indicated that the Company met the threshold for 2025. The report remains subject to final review by the Oregon Department of Energy. PGE believes it is on track to meet the RPS threshold for 2026.
HB 3179—In response to increasing utility bills and concerns about affordability, the Oregon Legislature in 2025 passed HB 3179. Under the provisions of the legislation, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multi-year rate plan (MRP) on a regular interval that is no less than three and no more than seven years long. The OPUC issued Order 26-191 on May 26, 2026, that began formal rulemaking in docket AR 677. In the proposed rules identified in Order 26-191, the OPUC is seeking to establish an initial filing schedule for MRPs, which calls for PGE to file its first MRP no earlier than May 1, 2029 and no later than July 31, 2029. The OPUC has also opened a docket, AR 676, as a multi-phased rulemaking to establish the MRP framework with a target to complete the framework in early 2027.
Under rules made effective March 19, 2026, each electric and natural gas company is required to, at least annually by December 31, file with the OPUC, and make publicly available, a report on any price adjustments that the electric or natural gas company expects within the next twelve months. Such report, must identify all price adjustment requests that an electric or natural gas company has filed or reasonably knows or anticipates to file. Any increase in residential prices may not take effect from November 1 to March 31.
United States Environmental Protection Agency (EPA) Regulations for Electric Generating Facilities—In 2024, the EPA released final regulations pertaining to electric generation facilities. The regulations included:
•GHG regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA);
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•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.
In April 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to the CAA Section 112(i)(4) for the EPA’s MATS rule. Colstrip was subsequently granted an exemption by the EPA until July 8, 2029. Environmental groups have filed court challenges to the MATS exemptions.
In June 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, in June 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 potential impact, which could be material, on the Company’s continuing investment in Colstrip. If upheld, not modified by the EPA, or the MATS compliance exemption is overturned, the 2024 MATS and GHG Rules would require compliance as early as 2027 and 2032, respectively. 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.
In addition to the EPA’s proposed rulemakings, several legal challenges have been filed regarding these rules and the revocation of the endangerment finding. 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. The endangerment finding revocation has not been stayed, and went into effect April 20, 2026, while the legal challenges are pending. 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 a number of such matters.
Corporate structure—In July 2025, the Company submitted an application to the OPUC seeking approval of a holding company reorganization. PGE believes it to be in the best interests of its customers and shareholders to update its corporate structure into a holding company structure. The structure currently contemplated involves placing a non-operating corporate entity over the Company’s existing structure. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure and to support reliability planning and economic development.
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
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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, all milestones in the procedural schedule have occurred with briefing complete and the OPUC having conducted oral argument with PGE and parties on July 23, 2026. Based on the current procedural schedule, the OPUC is targeting an Order date of August 25, 2026. On July 23, 2026, FERC issued an order authorizing the reorganization into a holding company structure.
General Rate Case - In early August 2026, PGE intends to file with the OPUC a general rate case based on a fiscal July 2026 through June 2027 test year (2027 GRC). The Company's filing will request a $179 million increase in the annual revenue requirement related primarily to deployment of capital since PGE’s last rate case (UE 435) to strengthen and safeguard the grid to meet growing customer demand and bolster reliability. The 2027 GRC, as requested, would result in an approximate 4.8% overall increase relative to currently approved prices. This increase excludes the effects of lower net variable power costs expected in 2027 as reflected in the Annual Power Cost Update Tariff, filed separately, with the OPUC in February 2026 (OPUC Docket UE 465). Based on a recently filed forecast of net variable power costs, customer prices would be expected to fall 2.4% on January 1, 2027, partially offsetting the proposed GRC increase.
The proposed GRC increase in annual revenue requirement is based upon:
• a capital structure of 50% debt and 50% equity;
• a return on equity of 9.75%;
• a cost of capital of 7.464%; and
• a rate base of $8.6 billion.
Another key item in the filing includes a request for a Bridge Framework to operate between the conclusion of this GRC and the establishment of PGE’s first multi-year rate plan in 2029 pursuant to HB 3179 and OPUC rulemakings in AR 676 and AR 677. Regulatory review of the 2027 GRC is expected throughout 2026 and 2027. The Company cannot predict the ultimate outcome of the regulatory process. We expect a final order to be issued by the OPUC by the end of June 2027. New customer prices are expected to become effective July 1, 2027. The 2027 GRC filing, including copies of direct testimony and exhibits, is expected to be made available on the OPUC website at www.oregon.gov/puc.
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 allowed PGE to seek recovery of incremental storm expenses through the previously authorized 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. On March 18, 2026, PGE received the OPUC's final order for the storm recovery docket, which included a disallowance for some operating and maintenance costs of $1 million and application of an earnings test. The OPUC ordered the application of an earnings test at 20 basis points below the Company's 2024 allowed return on equity of 9.5% on the deferred storm costs. The application of the earnings test resulted in an additional $3 million reduction of the previously deferred amounts. After application of adjustments per the final order, PGE’s deferred balance as of March 31, 2026 was $44 million, including interest, which began amortizing on April 1, 2026 over a two year period. The deferred balance as of June 30, 2026 was $42 million.
Reliability Contingency Event (RCE)—Under the RCE mechanism, originally authorized by the OPUC to be effective through 2025, PGE was 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
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and subject to the existing PCAM. Results of the PCAM are filed annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective in the following year. RCE costs incurred and deferred are included in each years' respective PCAM filing.
PGE filed the results of the 2024 PCAM with the OPUC on July 1, 2025, in Docket UE 457, initiating a regulatory review process. Included in the filing, the Company requested an extension of the RCE mechanism for one year, through 2026. On March 18, 2026, the OPUC issued its final order in the 2024 RCE mechanism docket which resulted in the approval for recovery of $70 million in deferred costs, before consideration of interest, after determining that costs should be shared at a level of 90%, resulting in a reduction of $8 million to the recovery request. In addition, the OPUC disagreed with PGE's method of estimating the impacts related to wind generating resources in the day ahead forecasts of $2 million, resulting in a total reduction of $10 million in previously deferred costs. The OPUC also declined to extend the sunset date for the RCE mechanism
After application of adjustments per the final order, PGE’s deferred balance as of March 31, 2026, related to RCEs was $80 million, which included $78 million related to RCEs deferred in 2024 and $2 million related to RCEs deferred in 2025. The 2024 deferred balance began amortizing into customer prices on April 1, 2026 and is to be collected over a two-year period. On July 1, 2026, under the Company's PCAM, Advice 26-26 was submitted to the OPUC seeking recovery to begin on April 1, 2027 of $2 million in costs deferred during RCEs in 2025. PGE believes the deferred amounts as of June 30, 2026 are probable of recovery.
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 2026 AUT included a final increase in power costs for 2026, and a corresponding increase in net variable power costs (NVPC), of $39 million from 2025 levels, which is now reflected in customer prices.
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 associated with complying with renewable mandates 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 and does not anticipate doing so in 2026.
Under the RAC, during 2023, the Company submitted a filing in OPUC Docket UE 427 for Clearwater proposing to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the twelve month period ending December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits, resulting in a net regulatory liability of $40 million, which amortized as a refund to customers over a twelve month period beginning on March 1, 2025, as approved by the OPUC in Order 25-075 issued in February 2025.
Order 25-075 also adopted conditions to be applied to the AUT and clarification of the applicability of those conditions was 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 was approved for recovery and began amortizing on April 1, 2026 over a twelve-month period. As of June 30, 2026, there was $9 million deferred as a regulatory liability in the balancing account.
Seaside Grid BESS recovery—In May 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).
In October 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. One key item in the Order was the adoption of an earnings test for the twelve-month period ended October 31, 2026 at PGE’s authorized return on equity (ROE), implemented via a deferral to track Seaside revenues and refund excess earnings, if applicable. The Company has
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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.
DSP recovery mechanism—On December 23, 2025, PGE and certain intervening parties submitted a stipulation to the OPUC reflecting an agreement that resolved 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 included:
•A rate base increase of $218 million;
•9.34% ROE per the MOU reflecting PGE's latest rate case; and
•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% were temporary in nature, allowing PGE to seek recovery of associated investments as applicable in its next GRC. These adjustments were driven primarily by non-distribution investments and were 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 OPUC's final order in Docket UE 459, issued on March 11, 2026, approved the terms of the stipulation, which were reflected in customer prices effective April 1, 2026. The Company has contested the applicability of an earnings test and, in addition, has not accrued any probable and reasonably estimable refunds.
More information about the DSP ARM docket, UE 459, is available on the OPUC website at www.oregon.gov/puc.
Portland Harbor Environmental Remediation Account (PHERA) mechanism—PGE has been identified by the EPA as a Potentially Responsible Party (PRP) for the Portland Harbor Superfund Site, however, significant uncertainties remain regarding the scope of remediation, cost allocation among PRPs, and PGE’s potential share of costs. The impact of such costs on the Company's results of operations is mitigated by the OPUC-approved PHERA mechanism, which allows for recovery of eligible costs through third-party proceeds and customer prices, subject to prudency reviews and earnings-test limitations. For further information regarding the PHERA mechanism as well as PGEs current estimated range of potential liability, see "Regulatory Assets and Liabilities" in Note 3, Balance Sheet Components, and “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”
New Large Load, Data Centers, and UM 2377—In 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 that proposed changes to PGE policies and tariffs that would: i) allocate the costs to the customers that are creating the costs; 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, which directed the OPUC to provide a classification for retail customers deemed large energy use data center facilities. HB 3546 also directed the OPUC to require that electric companies serving data centers enter into a contract for services with such customer under terms and conditions specified
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by the law. The OPUC 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.
On June 3, 2026, the Company submitted Advice filing 26-24 to the OPUC, which proposed to create a new tariff for Data Center Standard Service, update base rates and power costs, update DSP Alternative Recovery prices as agreed to via a stipulation adopted by the OPUC in Order No. 26-074 in Docket UE 459, and update the Energy Efficiency Funding Adjustment as directed in Order No. 26-154.
At a public meeting on July 7, 2026, the OPUC approved Advice 26-24, allowing new prices to become effective July 8, 2026. Collectively, the overall price changes result in an average rate decrease of 1.3% for residential customers, a 2.1% average rate decrease for commercial customers, an average rate decrease of 1.4% for industrial customers who do not qualify for PGE's new data center rate, and an average rate increase of 29.7% for data center customers.
Residential Exchange Program—The Pacific Northwest Electric Power Planning and Conservation Act, passed by Congress in 1980 (Northwest Power Act), established the Residential Exchange Program to ensure that residential and small farm electric customers of investor-owned utilities (IOUs) in the Pacific Northwest benefit from low-cost, federally-owned power marketed by the Bonneville Power Administration (BPA). Customers of both investor-owned and customer-owned utilities have received those benefits for over 40 years. In 2012, BPA approved a settlement agreement that established fixed customer benefits through October 2028. BPA's recent modeling indicates that these benefits for IOUs could be substantially reduced after the current settlement agreement expires. The modeling suggests a potential reduction of approximately 55%. Because IOUs pass these benefits directly to eligible customers as bill credits, such a reduction would increase residential and small farm customers' bills by an estimated average of 4%. On April 24, 2026, PGE joined several other utilities in filing a petition for review in the Ninth Circuit Court of Appeals against BPA, seeking to prevent BPA from violating the Northwest Power Act and depriving eligible IOU customers of the benefits of low-cost BPA hydropower to which they are entitled.
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 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 California Independent System Operator's (CAISO) western Energy Imbalance Market (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 CAISO’s Extended Day-Ahead Market (EDAM), which is expected to build on the success of the western EIM and help provide PGE and its customers additional 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, which began operation in May 2026, allows market participants to submit bids for their forecasted energy demand and available generation resources a day ahead of expected use. The EDAM optimizes transmission and resource use across all market participants, enabling access to the lowest-cost resources to meet regional needs. PGE plans to begin participation on October 1, 2026, to leverage 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
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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.
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.
Customers and Demand—The following tables present total energy deliveries, in thousands of Megawatt hours (MWh), and the average number of retail customers by customer type for the periods indicated:
Three Months Ended June 30, Six Months Ended June 30,
2026 2025 % Change % Change (Weather- Adjusted) 2026 2025 % Change % Change (Weather- Adjusted)*
Energy deliveries:
Retail:
Residential 1,591 1,571 1.3 % (1.4 )% 3,678 3,797 (3.1 )% (3.3 )%
Commercial 1,529 1,546 (1.1 ) (2.0 ) 3,123 3,178 (1.7 ) (1.8 )
Industrial 1,633 1,416 15.3 15.2 3,161 2,814 12.3 12.3
Subtotal 4,753 4,533 4.9 3.5 9,962 9,789 1.8 1.6
Direct access:
Commercial 118 135 (12.6 ) (12.6 ) 234 264 (11.4 ) (11.4 )
Industrial 513 513 — — 1,010 956 5.6 5.6
Subtotal 631 648 (2.6 ) (2.6 ) 1,244 1,220 2.0 2.0
Total retail 5,384 5,181 3.9 2.7 % 11,206 11,009 1.8 1.7 %
Wholesale 1,515 2,439 (37.9 ) 2,914 4,418 (34.0 )
Total 6,899 7,620 (9.5 )% 14,120 15,427 (8.5 )%
* The estimated impact of weather is based on various model assumptions related to temperature and customer response. Weather-adjusted estimates may not fully reflect the impacts of extreme weather variations and deviations in customer behavior to such extremes.
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Three Months Ended June 30, Six Months Ended June 30,
2026 2025 % Change 2026 2025 % Change
Average number of retail customers:
Residential 846,367 839,923 1 % 845,926 838,516 1 %
Commercial 114,523 114,230 — 114,533 114,211 —
Industrial 222 218 2 221 217 2
Direct access 502 729 (31 ) 518 659 (21 )
Total 961,614 955,100 1 % 961,198 953,603 1 %
Total retail energy deliveries for the six months ended June 30, 2026 were up 1.8% compared to the six months ended June 30, 2025. While industrial deliveries increased, declines occurred in both the residential and commercial categories.
Residential weather-adjusted deliveries decreased 3.3% in the aggregate, driven primarily by a decrease in average usage per customer of 4.2% during the first six months of 2026 compared with 2025, partially offset by an increase in the average number of residential customers of 1%. PGE has observed seasonal shifts in use per customer, such as higher air conditioning penetration in the summer in response to higher cooling degree days, as well as an increased number of rooftop solar installations within its service territory, and continued energy efficiency programs.
The industrial class continues to show growth as overall energy deliveries are up 10.6% in the six months ended June 30, 2026 compared to the same period in 2025, reflecting strength primarily in the digital services sector.
The following table indicates the number of heating degree-days for the three and six months ended June 30, 2026 and 2025, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:
Heating Degree-days Cooling Degree-days
2026 2025 Avg. 2026 2025 Avg.
First Quarter 1,737 1,772 1,828 — 4 —
April 303 248 349 — — 3
May 122 160 169 27 14 26
June 52 56 62 106 88 86
Second Quarter 477 464 580 133 102 115
Year-to-date 2,214 2,236 2,408 133 106 115
(Decrease)/Increase from the 15-year average (8 )% (7 )% 16 % (8 )%
During the three months ended June 30, 2026 compared to the same three months of 2025, weather had a more positive impact on Total Retail deliveries as the Company’s service territory saw 30% more cooling degree-days as well as 3% more heating degree-days than in 2025. Cooling degree-days were 16% above average in the second quarter of 2026 compared to 11% below average in 2025 while the number of heating degree-days recorded in the second quarter of 2026 was 18% below average compared to 20% below in the same period of 2025.
The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. Had the cap limit been fully subscribed and utilized, 12% of PGE’s total retail energy deliveries for the first six months of 2026 would have been to these customers.
PGE offers service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 16% of the Company’s retail energy deliveries could have been supplied by ESSs to Direct Access customers.
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Customers are measured and reported in terms of individual service points, with certain companies who are either commercial, industrial, or Direct Access customers having multiple service points. Deliveries to Direct Access customers increased 2.0% in the six months ended June 30, 2026 compared to the prior year, which is in line with PGE’s overall 1.8% increase in deliveries over the same comparative periods. Actual deliveries to Direct Access customers of energy supplied by ESSs represented 11% of PGE’s total retail energy deliveries for the first six months of both 2026 and 2025. The OPUC, under docket UM 2024, undertook an investigation of long-term Direct Access with program caps being one of the issues under consideration. On May 7, 2026, the OPUC issued Order 26-153, which left the present caps in place, although provided an allowance for waiver opportunity if ESSs were to meet certain reliability conditions in the future.
Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. The Company participates in wholesale markets by purchasing and selling electricity, natural gas, and environmental credits in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. PGE continuously makes economic dispatch decisions based on numerous factors, such as plant availability, customer demand, river flows, wind conditions, and current wholesale prices. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period and impacts NVPC and income from operations.
The following table provides information regarding the performance of the Company’s generating resources for the six months ended June 30, 2026 and 2025:
Plant availability (1) Actual energy provided compared to projected levels (2) Actual energy provided as a percentage of total system load
2026 2025 2026 2025 2026 2025
Generation:
Thermal:
Natural gas 77 % 84 % 74 % 104 % 28 % 37 %
Coal (3) 90 71 54 99 4 6
Wind (4) 86 90 88 98 10 10
Hydro 94 97 76 101 4 5
(1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability reflects Colstrip, which PGE does not operate.
(4)Plant availability includes Wheatridge Renewable Energy Facility and Clearwater, neither of which does PGE operate.
Energy received from PGE-owned and jointly-owned thermal plants during the six months ended June 30, 2026 compared to 2025 decreased 32%. This decrease was primarily driven by economic dispatch decisions. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.
Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, decreased 28% during the six months ended June 30, 2026 compared to 2025. Energy purchased from mid-Columbia and other regional hydroelectric projects decreased 29% and energy generated by the Company-owned facilities decreased 23% during the six months ended June 30, 2026. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 10 years of historical generation data. See “Purchased power and fuel” in the Results of Operations section in this Item 2, for further detail on regional hydro results.
Energy received from PGE-owned and under contract wind resources remained materially consistent during the six months ended June 30, 2026 compared to 2025. 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.
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Under the PCAM, the Company may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual 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 PCAM as calculated for regulatory purposes:
•For the six months ended June 30, 2026, actual NVPC was $10 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2026 is currently estimated to be below the baseline and approximately at the established deadband range. Accordingly, there is no estimated refund to customers expected under the PCAM for 2026.
•For the six months ended June 30, 2025, actual NVPC was $19 million below baseline NVPC. For the year ended December 31, 2025, actual NVPC was $6 million below baseline NVPC, which was within the established deadband range. Accordingly, there was no estimated refund to customers under the PCAM for 2025. A final determination regarding the 2025 PCAM results will be made by the OPUC through a public filing and review in 2026.
Operating and Maintenance
Business transformation and optimization expenses—During the three and six months ended June 30, 2026, PGE incurred $8 million and $25 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, as well as corporate structure update costs incurred for incremental accounting, legal, and consulting expenses related to the Company's submission of a regulatory application for approval of a holding company reorganization and the proposed Acquisition. For more information on the impact of these costs on annual results, see “Generation, transmission and distribution,” “Administrative and other,” “Depreciation and amortization,” and "Interest expense," in the Results of Operations section of this Overview. For more on the holding company application and pending Acquisition, see “Corporate Structure” in the Regulatory Matters section, and "Pending Acquisition" in the Company Strategy section of this Overview. The Company expects to incur business transformation and optimization expenses related to these initiatives throughout 2026.
System Operator Labor Negotiations—PGE is engaged in contract negotiations with approximately 30 System Operators who voted in 2024 to join the International Brotherhood of Electrical Workers (IBEW) Local 125 Bargaining Unit 1. On July 1, 2026, representatives of this bargaining unit provided notice of their intent to initiate a strike beginning August 2, 2026, if the parties are unable to reach agreement on a collective bargaining arrangement. PGE continues to engage in negotiations with the bargaining unit and is implementing contingency plans designed to maintain safe and reliable service to customers in the event of a work stoppage.
While PGE believes it has plans in place to continue providing safe and reliable electric service, if a strike were to occur, the Company could incur increased operating and labor-related costs, including costs associated with contingency staffing, contractor support, training, and other operational measures. PGE cannot predict the outcome of the negotiations or impact of a strike, if any. The ultimate operational or financial impacts of any work stoppage will depend on factors including its duration, number of individuals ultimately involved in the strike, the availability and effectiveness of contingency resources, and the outcome of ongoing negotiations. Accordingly, PGE is unable at this time to determine the potential impacts on its financial position, results of operations, or cash flows, however, such impacts could be material.
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Results of Operations
The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations.
The results of operations are as follows for the periods presented (dollars in millions):
Three Months Ended June 30, % Increase Six Months Ended June 30, % Increase
2026 2025 (Decrease) 2026 2025 (Decrease)
Total revenues $ 814 $ 807 1 % $ 1,693 $ 1,735 (2 )%
Operating expenses:
Purchased power and fuel 296 294 — 657 662 (1 )
Generation, transmission and distribution 112 114 (2 ) 222 224 —
Administrative and other 90 96 (6 ) 196 192 2
Depreciation and amortization 143 139 3 287 279 3
Taxes other than income taxes 52 46 13 103 92 12
Total operating expenses 693 689 1 1,465 1,449 1
Income from operations 121 118 3 228 286 (20 )
Interest expense, net* 61 57 7 121 113 7
Other income:
Allowance for equity funds used during construction 6 6 — 9 11 (18 )
Miscellaneous income, net 14 7 100 18 12 50
Other income, net 20 13 54 27 23 17
Income before income tax expense 80 74 8 134 196 (32 )
Income tax expense 12 12 — 21 34 (38 )
Net income and Comprehensive income $ 68 $ 62 10 % $ 113 $ 162 (30 )%
* Includes an allowance for borrowed funds used during construction of $3 million and $3 million for the three months ended June 30, 2026 and 2025, respectively, and $5 million and $7 million for the six months ended June 30, 2026 and 2025, respectively.
Net income for the three months ended June 30, 2026 increased $6 million, or 10%, compared to the same period of 2025. The current quarter results included $8 million of business transformation and optimization expense. Retail revenues increased due to the OPUC approved recovery of several regulatory deferrals in customer prices during 2026 along with a nearly 4% increase in retail deliveries. Wholesale revenues dropped primarily as a result of lower sales volumes. Purchased power and fuel expense was comparable to the prior year, reflecting an increase in average cost per MWh while total system load declined as a result of the reduction in Wholesale sales volume, which suppressed Total revenues. Administrative and General expense reflects a reduction of $7 million in business transformation and optimization expenses in 2026. Increases in Depreciation and amortization expense were driven by higher depreciable asset balances and Interest expense was up due to higher debt balances.
Net income for the six months ended June 30, 2026 was down $49 million, or 30%, from the same period of 2025. Total revenues declined as a decrease in Wholesale revenues more than offset the increase in Retail revenues that resulted from the combination of OPUC approved recovery of several regulatory deferrals in customer prices during 2026 along with a nearly 2% increase in retail deliveries. The slight reduction in Purchased power and fuel reflects largely offsetting impacts of the RCE deferrals in 2025 that were not repeated in 2026 along with changes in average variable power costs and system loads. The increase in Depreciation and amortization expense was driven by higher depreciable asset balances. The increase in Taxes other than income taxes reflects higher property and payroll taxes. Interest expense, net, was higher due to increased debt balances. Income tax expense was down due to lower pretax income.
Total revenues consist of the following for the periods presented (dollars in millions):
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Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Retail:
Residential $ 334 41 % $ 311 39 % $ 728 43 % $ 740 43 %
Commercial 248 31 234 29 483 29 476 27
Industrial 156 19 128 16 295 17 255 15
Subtotal 738 91 673 84 1,506 89 1,471 85
Direct access:
Commercial 4 — 4 — 7 — 8 —
Industrial 8 1 6 1 14 1 11 1
Subtotal 12 1 10 1 21 1 19 1
Subtotal Retail 750 92 683 85 1,527 90 1,490 86
Alternative revenue programs, net of amortization 3 0 9 1 19 1 5 —
Other accrued revenues, net (2 ) — 6 — (5 ) — 10 1
Total retail revenues 751 92 698 86 1,541 91 1,505 87
Wholesale revenues 39 5 88 11 102 6 188 11
Other operating revenues 24 3 21 3 50 3 42 2
Total revenues $ 814 100 % $ 807 100 % $ 1,693 100 % $ 1,735 100 %
Total retail revenues—The following items contributed to the increase in Total retail revenues for the three and six months ended June 30, 2026 compared to the same periods in 2025 (in millions):
Three Months Ended Six Months Ended
June 30, 2025 $ 698 $ 1,505
Seaside BESS 9 19
Clearwater RAC deferral 7 19
Retail energy deliveries 17 16
DSP cost recovery 10 10
PCAM collection for 2024 deferral 8 7
Average price of energy deliveries due primarily to changes in customer prices, partially offset by changes in delivery mix to customers 2 1
Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel) 7 (14 )
Annual Colstrip tariff update (10 ) (20 )
Combination of various supplemental schedules and adjustments 3 (2 )
June 30, 2026 $ 751 $ 1,541
Change in Total retail revenues $ 53 $ 36
Wholesale revenues result from sales of electricity and environmental credits to utilities and power marketers made in the Company’s efforts to meet the needs of, and obtain reasonably priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.
Wholesale revenues for the three months ended June 30, 2026 decreased $49 million, or 56%, from the three months ended June 30, 2025, resulting from a combination of a 38% decrease in sales volume, lower average wholesale sales price, and a reduction of $7 million from environmental credit sales.
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For the six months ended June 30, 2026, Wholesale revenues decreased $86 million, or 46%, from the six months ended June 30, 2025 as the Company experienced a $64 million reduction from a decline in the quantity of MWhs sold, which was down 34% from the prior year and a $7 million reduction due to lower prices. In addition, the sale of environmental credits produced $15 million less revenue in 2026 than during the same period of 2025.
Other operating revenues for the three months ended June 30, 2026 were up $3 million from the comparable period in 2025, as a result a combination of factors, the most prominent being the sale of excess fuel oil during 2026.
In the six months ended June 30, 2026, Other operating revenues were up $8 million compared to the same period of 2025, due to a combination of factors, the largest of which being revenue deferrals recorded as a result of HB 3179, sale of excess fuel oil, and joint pole revenue.
Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts.
The following items contributed to the change in Purchased power and fuel for the three and six months ended June 30, 2026 compared to the same periods in 2025 (dollars in millions):
Three Months Ended Six Months Ended
June 30, 2025 $ 294 $ 662
Average variable power cost per MWh (16 ) (44 )
Total system load 9 16
RCE deferral activity, net 9 23
June 30, 2026 296 657
Change in Purchased power and fuel $ 2 $ (5 )
Average variable power cost per MWh (in dollars):
June 30, 2025 $ 41.34 $ 45.40
June 30, 2026 $ 44.05 $ 47.52
Total system load (MWhs in thousands):
June 30, 2025 7,095 14,638
June 30, 2026 6,498 13,402
For the three months ended June 30, 2026, the $16 million decrease related to the change in average variable power cost per MWh was driven by an 18% decrease in the average cost of purchased power, and a 46% increase in the average cost for the Company’s own generation. The $9 million increase related to total system load was comprised of a 17% increase of energy obtained from purchased power, and a 31% decrease in the Company’s own generation.
For the six months ended June 30, 2026, the $44 million decrease related to the change in average variable power cost per MWh was driven by a 19% decrease in the average cost of purchased power and a 35% increase in the average cost for the Company’s own generation. The $16 million increase related to total system load was comprised of a 17% increase of energy obtained from purchased power, offset by a 27% decrease in the Company’s own generation.
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PGE’s sources of energy, total system load, and retail load requirement are as follows for the periods presented (MWhs in thousands):
Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Generation:
Thermal:
Natural gas 1,395 21 % 2,279 32 % 3,735 28 % 5,396 37 %
Coal 193 3 294 4 515 4 827 6
Total thermal 1,588 24 2,573 36 4,250 32 6,223 43
Hydro 242 4 328 5 591 4 770 5
Wind 767 12 866 12 1,315 10 1,465 10
Total generation 2,597 40 3,767 53 6,156 46 8,458 58
Purchased power:
Hydro 1,196 18 2,024 29 2,691 20 3,772 26
Wind 416 6 302 4 735 5 591 4
Solar 672 10 419 6 934 7 593 4
Natural Gas 193 3 — — 624 5 — —
Waste, Wood, and Landfill Gas 26 — 29 — 49 — 54 —
Source not specified 1,398 23 554 8 2,213 17 1,170 8
Total purchased power 3,901 60 3,328 47 7,246 54 6,180 42
Total system load 6,498 100 % 7,095 100 % 13,402 100 % 14,638 100 %
Less: wholesale sales (1,515 ) (2,439 ) (2,914 ) (4,418 )
Retail load requirement 4,983 4,656 10,488 10,220
Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows:
Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Sources of energy (MWhs in thousands):
PURPA purchased power:
Hydro 7 9 17 19
Wind 9 10 14 14
Solar 198 204 300 301
Waste, Wood, and Landfill Gas 25 30 49 54
Total 239 253 380 388
The following table presents the forecasted April-to-September 2026 and actual 2025 runoff at particular points of major rivers relevant to PGE’s hydro resources:
Runoff as a Percent of Normal*
Location 2026 Forecast 2025 Actual
Columbia River at The Dalles, Oregon 83 % 77 %
Mid-Columbia River at Grand Coulee, Washington 92 78
Clackamas River at Estacada, Oregon 54 69
Deschutes River at Moody, Oregon 76 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.
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Actual NVPC for the three and six months ended June 30, 2026 increased compared to the same periods in 2025 as follows (in millions):
Three Months Ended Six Months Ended
June 30, 2025 $ 206 $ 474
Purchased power and fuel expense (7 ) (28 )
Wholesale revenues 49 86
RCE deferral activity, net 9 23
June 30, 2026 $ 257 $ 555
Change in NVPC $ 51 $ 81
For further information regarding NVPC in relation to the PCAM, see “Purchased power and fuel expense” within this “Results of Operations” for more details.
For the three months ended June 30, 2026 and 2025, actual NVPC was $1 million above and $12 million below baseline NVPC, respectively. For the six months ended June 30, 2026 and 2025, actual NVPC was $10 million above and $19 million below baseline NVPC, respectively.
Based on forecast data, NVPC for the year ending December 31, 2026 is currently estimated to be below the baseline and approximately at the deadband. Accordingly, there is no estimated refund to customers expected under the PCAM for 2026.
Generation, transmission and distribution decreased as follows for the three and six months ended June 30, 2026 compared to the same periods in 2025 (in millions):
Three Months Ended Six Months Ended
June 30, 2025 $ 114 $ 224
Generating facility expenses 1 4
Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses (3 ) (9 )
Service restoration and storm response costs 7 3
Business transformation and optimization expenses (1 ) 1
Energy Storage 1 1
Regulatory disallowances — 4
Miscellaneous expenses (7 ) (6 )
June 30, 2026 $ 112 $ 222
Change in Generation, transmission and distribution $ (2 ) $ (2 )
In the table above, for the three and six months ended June 30, 2026, respectively, $2 million and $5 million related to wildfire mitigation and $2 million for each of the three and six month periods related to storm response costs have been offset through customer prices or specific regulatory mechanisms.
Administrative and other changed as follows for the three and six months ended June 30, 2026 compared to the same periods in 2025 (in millions):
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Three Months Ended Six Months Ended
June 30, 2025 $ 96 $ 192
Regulatory and professional services costs 1 —
Employee compensation and benefits (2 ) 8
Customer related costs 1 (2 )
Amortization of COVID-19 bad debt expense deferral 3 (1 )
Business transformation and optimization expenses (7 ) 4
Miscellaneous expenses (2 ) (5 )
June 30, 2026 $ 90 $ 196
Change in Administrative and other $ (6 ) $ 4
In the table above, for both the three and six months ended June 30, 2026, $4 million of the change in customer related costs is due to regulatory programs that have been offset through customer pricing or specific regulatory mechanisms.
Depreciation and amortization expense increased $4 million and $8 million in the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. The increase was primarily due to higher utility plant balances and regulatory amortization. Included in expense for the three and six months ended June 30, 2026 is $1 million and $2 million, respectively, related to business transformation and optimization.
Taxes other than income taxes increased $6 million and $11 million in the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. The increase was driven by higher property and payroll taxes and higher franchise fees.
Interest expense, net increased $4 million and $8 million in the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. The increase was primarily due to interest on short and long term debt and business transformation and optimization. Included in expense for the three and six months ended June 30, 2026 is $1 million and $4 million related to business transformation and optimization.
Other income, net increased $7 million and $4 million in the three and six months ended June 30, 2026, respectively, compared to the same periods in 2025. The increase was primarily driven by regulatory asset interest income. Included in expense for the six months ended June 30, 2026 is $1 million related regulatory disallowances.
Income tax expense remained consistent for the three months ended June 30, 2026 and decreased $13 million in the six months ended June 30, 2026 compared to the same periods in 2025, primarily driven by lower pre-tax income.
Critical Accounting Policies and Estimates
There have been no material changes to the Company’s critical accounting policies and estimates as previously disclosed in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 17, 2026.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.
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The following summarizes PGE’s cash flows for the periods presented (in millions):
Six Months Ended June 30,
2026 2025
Cash and cash equivalents, beginning of period $ 76 $ 12
Net cash provided by (used in):
Operating activities 488 567
Investing activities (650 ) (609 )
Financing activities 121 86
Change in cash and cash equivalents (41 ) 44
Cash and cash equivalents, end of period $ 35 $ 56
Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the six months ended June 30, 2026 compared with the six months ended June 30, 2025 (in millions):
Increase/ (Decrease)
Net income $ (49 )
Accounts receivable and Unbilled revenue (5 )
Margin deposits activity (27 )
Accounts payable (18 )
Regulatory deferral activity 26
Depreciation and amortization 8
Deferred income taxes (12 )
Tax credit sales (1 )
Alternative revenue programs (14 )
Other miscellaneous changes 13
Net change in cash flow from operations $ (79 )
PGE estimates that non-cash charges for depreciation and amortization in 2026 will range from $570 million to $590 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $1 billion to $1.2 billion.
Cash Flows from Investing Activities—Net cash used in investing activities for the six months ended June 30, 2026 increased $41 million when compared with the six months ended June 30, 2025. Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $39 million.
Excluding AFUDC, the Company plans to make capital expenditures of $1.7 billion in 2026, which it expects to fund with cash to be generated from operations during 2026, as discussed above, the issuance of short- and long-term debt, and issuances of shares pursuant to the equity forward sale agreement and at-the-market offering programs. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.
Cash Flows from Financing Activities—During the six months ended June 30, 2026, net cash used by financing activities was primarily the result of the payment of $120 million of dividends.
Capital Requirements
The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2026 through 2030, excluding AFUDC (in millions):
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2026 2027 2028 2029 2030
Ongoing capital expenditures (1) $ 865 $ 895 $ 925 $ 925 $ 925
Transmission 215 390 420 515 525
2023 RFP Hybrid Projects 575 455 — — —
Total capital expenditures (2) $ 1,655 $ 1,740 $ 1,345 $ 1,440 $ 1,450
Long-term debt maturities $ — $ 160 $ 450 $ 200 $ 325
(1)Consists primarily of upgrades to, and replacement of, generation and distribution infrastructure, as well as new customer connections. Includes accrued capital additions, preliminary engineering, removal costs, and certain intangible working capital assets.
(2)Amounts are estimates as of the date of this report and may be affected by economic conditions, including but not limited to, impacts of inflation, changes to the cost of materials and labor, and financing costs.
The pending Acquisition to acquire select portions of PacifiCorp’s Washington state regulated utility retail business will require financing of $1.9 billion. Upon execution of the Agreement, the acquisition was supported by a fully committed bridge facility with Barclays Bank PLC and JPMorgan Chase Bank, N.A. for $1.9 billion. On March 23, 2026, the bridge facility was amended to an amount of approximately $1.3 billion and at the same time, the Company entered into a Delay Draw Term Loan in the amount of approximately $700 million. 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.
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 1, Basis of Presentation, in Notes to Consolidated Financial Statements in Item 1.—“Financial Statements.”
Debt and Equity Financings
PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, credit ratings, capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to inflationary pressures and interest rate increases by the federal reserve. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.
For 2026, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $1 billion to $1.2 billion, and issuances of long-term debt of up to $350 million. PGE plans to fund any shortfall through the combination of issuance of common stock and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt, equity, and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments.
Short-term Debt. Pursuant to an order issued by the FERC in January 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 June 30, 2026 (in millions):
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As of June 30, 2026
Capacity Outstanding Available
Revolving credit facility (1) $ 750 $ — $ 750
Letters of credit (2) 320 126 $ 194
Total credit $ 1,070 $ 126 $ 944
Cash and cash equivalents 35
Total liquidity $ 979
(1)Scheduled to expire September 10, 2030.
(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.
On September 10, 2025, PGE entered into an amendment of its existing revolving credit facility. As of June 30, 2026, PGE had a $750 million unsecured revolving credit facility scheduled to expire in September 2030. The Company has the ability to expand the revolving credit facility to $850 million, if needed, subject to the requirements of the agreement. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may borrow for one, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the remaining term of the applicable credit facility. As of June 30, 2026, PGE had a $750 million outstanding balance on the revolving credit facility.
The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of June 30, 2026, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $750 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.
Long-term Debt. As of June 30, 2026, PGE’s total long-term debt outstanding, net of $21 million of unamortized debt expense, was $4,928 million.
On March 23, 2026, PGE entered into a 24-month credit agreement with lenders in the aggregate principal of $350 million. PGE drew four loans from the Lenders in the aggregate principal amount of $350 million, with $270 million outstanding as of June 30, 2026. The final loan, in the amount of $80 million, occurred on July 2, 2026. The loans bear interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus an Applicable Margin of 110.0 basis points.
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 (ATM) program. Pursuant to the 2024 ATM program, the Company entered into forward sale agreements for 1,420,049 shares and 5,756,432 shares in 2024 and 2025, respectively. The Company issued 1,066,549 shares and received net proceeds of $50 million in 2024, and issued 5,919,618 shares and received net proceeds of $250 million in 2025. As of June 30, 2026, the Company could have physically settled the remaining amount by delivering 190,314 shares in exchange for cash of $8 million.
In February 2026, PGE entered into an agreement under which it could sell up to $500 million of its common stock through the ATM program. No forward sale agreements were entered into pursuant to the 2026 ATM program as of June 30, 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.
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In February 2026, PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 9,467,455 shares of its common stock. Pursuant to the terms of the EFSA, the forward counterparties borrowed 10,848,125 shares of PGE's common stock, including 1,380,670 shares in connection with the underwriters' exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters for $50.70 per share, less an underwriting discount equal to $1.4576 per share. PGE will not receive any proceeds from the sale of common stock until the EFSA is settled, and at that time PGE will record the proceeds, if any, in equity.
As of June 30, 2026, the Company could have physically settled the EFSA by delivering 10,848,125 shares in exchange for cash for $528 million.
For additional information on the EFSA and ATM programs, see Note 7, Shareholders’ Equity, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”
Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 45.6% and 47.0% as of June 30, 2026 and December 31, 2025, respectively.
Credit Ratings and Debt Covenants
PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows:
Moody’s S&P
Issuer credit rating A3 BBB+
Senior secured debt A1 A
Commercial paper P-2 A-2
Outlook Stable Stable
In the event Moody’s or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits in PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.
As of June 30, 2026, PGE had posted $108 million of collateral with these counterparties, consisting of $66 million in cash and $42 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of June 30, 2026, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $76 million, and decreases to $27 million by December 31, 2026 and to $11 million by December 31, 2027. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $206 million and decreases to $130 million by December 31, 2026 and to $99 million by December 31, 2027.
PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facilities would increase.
The indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on June 30, 2026, under the most restrictive issuance test in the Indenture, the Company could have issued up to $563 million of additional FMBs. Any issuances of FMBs would be
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subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.
PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of June 30, 2026, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 54.4%.