Portland General Electric Co: Form 10-Q for the period ended Sep 30, 2025

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 action, and regulatory audits, investigations, and actions, including those of the Federal Energy Regulatory Commission (FERC), the Public Utility Commission of Oregon (OPUC), and the Internal Revenue Service, with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs and capital investments, energy trading activities, tax credits, and current or prospective wholesale and retail competition;
• uncertainties associated with increased energy demand or significant accelerated growth in demand due to new data centers, including the concentration of data centers, and the ability to obtain regulatory approvals, environmental, and other permits to construct new facilities in a timely manner;
• economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers, and elevated levels of uncollectible customer accounts;
• increases to operating costs that could result from changes to trade tariffs, rising inflation, and volatility in interest rates;
• the impacts of changes in the tax code, including tax rates, minimum tax rates, adjustments made to deferred tax assets and liabilities, and changes impacting the availability of and ability to transfer renewable tax credits;
• risks and uncertainties related to current or future All-Source Request for Proposals (RFP) projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of trade tariffs), permitting and construction delays, available tax credits, counterparty credit risk, and legislative uncertainty;
• changing customer expectations and choices that may reduce customer demand for PGE’s services may impact the Company’s ability to make and recover its investments through prices and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from Electricity Service Suppliers (ESSs) or the adoption of community choice aggregation;
• the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 2, along with “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” of this Quarterly Report on Form 10-Q;
• natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages, and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability;
• severe weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers’ demand for power, and PGE’s financial health and ability and cost to procure adequate power and fuel supplies to serve its customers, access the wholesale energy market, or operate its generating facilities and transmission and distribution systems, and the Company’s costs to maintain, repair, and replace such facilities and systems, and recovery of such costs;
• ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (PSPS) and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems were involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through prices or insurance, resulting in impact to the financial condition or reputation of the Company;
• impacts from the lack of 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, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power, repair costs, or abandoned costs;
• delays in the supply chain and increased supply costs, failure to complete capital projects on schedule or within budget, failure to obtain permits, inability to complete negotiations on contracts for capital projects, failure of counterparties to perform under agreements, or the abandonment of capital projects, any of which could result in the Company’s inability to recover project costs, or impact PGE’s competitive position, market share, or results of operations in a material way;
• volatility in wholesale power and natural gas prices, including but not limited to volatility caused by macroeconomic and international issues, that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;
• changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes, including the potential impact of trade tariffs, on the Company’s power costs;
• capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, volatility of equity markets as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees;
• future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;
• changes in, compliance with, and general uncertainty around environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
• the effects of climate change, whether global or local in nature, including unseasonable or extreme weather and other natural phenomena that may affect energy costs or consumption, increase the Company’s costs, cause damage to PGE facilities and system, or adversely affect its operations;
• changes in residential, commercial, or industrial customer growth, or demographic patterns, including changes in load resulting in future transmission constraints, in PGE’s service territory;
• the effectiveness of PGE’s risk management policies and procedures;
• cybersecurity attacks, data security breaches, physical attacks and security breaches, or other malicious acts, internally or to third parties, that cause damage to the Company’s generation, transmission, or distribution facilities, information technology systems, or employees, or inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, vendor, employee, or Company information;
• reputational damage from negative publicity, protests, fines, penalties and other negative consequences resulting in regulatory and/or legal actions;
• employee workforce factors, including potential strikes, work stoppages, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees;
• failure to achieve the Company’s greenhouse gas (GHG) emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively respond to legislative requirements concerning GHG emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation;
• the impact of widespread health developments, and responses to such developments (such as 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; and
• acts of war, terrorism, or civil disruption.

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, 2024, filed with the SEC on February

14, 2025, 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.

OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.

PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State of Oregon (State). The Company participates in wholesale markets by purchasing and selling electricity, natural gas, and environmental credits in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory in the State.

Company Strategy

The Company exists to power the advancement of society. PGE energizes lives, strengthens communities, and fosters energy solutions that promote social, economic, and environmental progress. The Company is committed to our customers’ clean energy goals and delivering steady growth and returns to shareholders. PGE is focused on working with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing greenhouse gas (GHG) emissions, and responding to evolving customer expectations. At the same time, the Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region. PGE is transforming all aspects of its business to empower its workforce to be even more results oriented to serve customers well. To create a clean energy future, PGE is focused on the following strategic imperatives:

• *Decarbonize Power—*Reduce GHG emissions associated with electricity served to retail customers by at least 80% by 2030 and 100% by 2040;
• *Electrify the Economy—*Increase beneficial electricity use to capture the benefits of new technologies while building an increasingly clean, flexible, and reliable grid; and
• *Advance Performance—*Improve safety, efficiency, and system and equipment reliability while maintaining affordable energy service and growing earnings per share 5% to 7% annually.

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 228 thousand residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100% clean and renewable electricity by

2035 and 100% economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have similar goals and continue to consider similar goals for the future.

The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows large business and municipal customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy either from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.

As of September 30, 2025, 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 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 6%. The increase and severity of weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.

Investing in a Clean Energy Future

***The Resource Planning Process—***PGE’s resource planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. With the passage of HB 2021, PGE created a Clean Energy Plan (CEP), which articulates the Company’s strategy to make continued progress towards the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was 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 the new HB 2021 emissions reduction requirements.

Throughout the remainder of 2023, PGE refreshed its forecasts, first in an Addendum filed in July 2023, in OPUC Docket LC 80, then several times in subsequent comments provided to the OPUC. On January 25, 2024, the OPUC acknowledged PGE’s IRP, subject to certain conditions, providing regulatory support for the Company to pursue the near-term resource additions articulated in the Action Plan. The OPUC declined to acknowledge the CEP, directing the Company in Order 24-096 to revise and resubmit certain elements of the CEP with its next CEP/IRP Update.

On June 18, 2025, PGE submitted a CEP/IRP Update to the OPUC. The Update addresses specific inputs that may have changed since the most recent IRP was acknowledged, without attempting to fully revise the IRP. This CEP/IRP Update refreshes the analysis filed with the 2023 CEP/IRP and provides status reports on actions and requirements from Order 24-096.

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

To better distinguish resource needs, the CEP/IRP Update reports the capacity from hybrid solar and battery storage resources by individual technology. This reporting change increased the stated need of the 2023 CEP/IRP Action Plan from a range of 2,700 to 3,700 MW, to an updated range of 3,500 to 4,500 MW of renewable energy and non-emitting capacity, inclusive of 2023 RFP projects, which remain under negotiation.

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

2021 All-Source RFP

Pursuant to the 2021 All-Source RFP process, which sought approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, PGE entered into agreements to acquire resources as follows:

• *Clearwater—*PGE owns 208 MW of production capacity of the wind facility, located in Eastern Montana. Subsidiaries of NextEra Energy Resources, LLC, which operates the facility, owns the remaining 103 MW of production capacity and sells their portion of the output to PGE under a 30-year PPA.
• *Seaside Grid—*The 200 MW Battery Energy Storage System (BESS) facility, located in Portland, Oregon was placed in service on July 8, 2025 and is owned by PGE.
• *Constable BESS (formerly Evergreen)—*The 75 MW BESS facility, located in Hillsboro, Oregon was placed in service on December 20, 2024 and is owned by PGE.
• *Sundial BESS (formerly Troutdale Grid)—*The 200 MW BESS facility, located in Troutdale, Oregon reached commercial operations on December 20, 2024. NextEra Energy Resources, LLC owns the resource and sells the capacity to PGE under a 20-year agreement.

The agreements related to Clearwater and all BESS agreements represent the final procurement from the 2021 All-Source RFP. Resources required to meet the remaining 2030 need are anticipated to be procured through future acquisition processes, including, but not limited to, the 2023 and 2025 All-Source RFPs and future RFPs.

The BESS facilities qualify for federal investment tax credits (ITCs). The agreements related to Clearwater qualify for production tax credits (PTCs) and are eligible under Oregon’s Renewable Portfolio Standard (RPS). These projects are estimated to produce approximately $262 million in combined ITC and PTC benefits over time on behalf of customers.

2023 All-Source RFP

PGE filed notice with the OPUC in January 2023 that an RFP was needed to procure resources to meet forecasted capacity shortfalls and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan. PGE filed the draft 2023 All-Source RFP with the OPUC in May 2023 and regulatory approval was granted in January 2024. The Company issued the 2023 All-Source RFP to market in February 2024, seeking bids for resources that can provide non-emitting dispatchable capacity and renewable generation.

After a robust and competitive bidding process performed in accordance with Oregon's competitive bidding rules, and with the active participation of, and oversight by, an OPUC-selected third-party independent evaluator, on September 17, 2024, PGE submitted a request for acknowledgement of the final shortlist of bidders to the OPUC. The final shortlist was acknowledged by the OPUC, with conditions, on November 19, 2024.

Following passage of House Resolution 1, the One Big Beautiful Bill Act (OBBB), on July 4, 2025, PGE provided an opportunity for all conforming 2023 RFP bidders to refresh their pricing to capture the impacts of the new legislation and recent trade tariffs. Evaluation of refreshed bids, including updates to bid scoring and ranking, was performed in collaboration with an OPUC-selected third-party independent evaluator.

On October 1, 2025, PGE submitted a regulatory filing to the OPUC requesting acknowledgement of an updated final shortlist of bidders for the 2023 RFP to meet PGE’s articulated resource needs, as shown in the table below:

2023 RFP Updated Final Shortlist

(1) Hybrid commercial structure includes a PPA portion and a Company-owned portion via a build transfer agreement (BTA) for project resources

The Company has requested acknowledgement of the updated final shortlist by the end of the year to enable PGE to finalize contract negotiations, keep project costs as low as possible, make continued progress towards Oregon’s decarbonization goals and support system reliability needs as identified in the 2023 Integrated Resource Plan and Clean Energy Plan update. PGE is proceeding to commercial negotiations with bidders for projects on the updated final shortlist and expects finalization of contracts for projects that meet selection criteria by the end of 2025 or in the first quarter of 2026, with projects in service by the end of 2027.

The 2023 RFP is a component of PGE’s multi-pronged procurement approach focused on customer affordability, system reliability, and decarbonization. In parallel with the 2023 RFP, the Company is seeking additional renewable energy and non-emitting capacity through PPAs, including a bilateral all-call for PPAs, community-based renewable energy procurement, and the ongoing 2025 RFP process.

The updated RFP final shortlist projects were evaluated and selected based on conditions as of the updated final shortlist date and are subject to risks and uncertainties, including, but not limited to, regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including the application of trade tariffs), securing of federal tax incentives and legislative uncertainty.

Additional details of the 2023 RFP (OPUC Docket UM 2274) are available on the OPUC website at www.oregon.gov/puc (http://www.oregon.gov/puc).

2025 All-Source RFP

PGE filed notice with the OPUC in November 2024 that an RFP in 2025 was needed to procure resources to meet a forecasted 2029 capacity shortfall and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan and CEP Update. PGE filed the draft 2025 All-Source RFP on April 17, 2025.

Following the enactment of the OBBB and related executive orders in July 2025, PGE continues to evaluate the potential impact of these federal tax credit changes on project economics and overall portfolio cost. Loss of tax credit availability could increase renewable project costs and corresponding customer prices. In response, PGE incorporated additional information requirements into the RFP to better assess tax credit eligibility, supply chain risks, and cost implications. Further detail on the federal policy changes and associated risks is provided in "The One Big Beautiful Bill Act” in the Laws and Regulations section of this Overview.

PGE received regulatory approval of the 2025 All Source RFP from the OPUC 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. Bids were submitted in October 2025 and are currently being evaluated based on the OPUC-approved scoring methodology. PGE plans to file for acknowledgement of a proposed final shortlist in the first quarter of 2026, allowing PGE to begin negotiations with shortlisted bids.

Legal Challenges to the RFP Process

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

NewSun was an intervenor in the Clearwater RAC proceeding in Docket UE 427, in which the OPUC rejected NewSun’s proposals to change the RFP oversight process, but adopted conditions on how PGE should recognize Clearwater’s capacity factor and transmission assumptions in its Annual Power Cost Update Tariff (AUT) and power cost adjustment mechanism (PCAM) beginning in 2025. PGE sought and received clarification of the OPUC’s February 21, 2025 order (Order 25-075) adopting the conditions, in Order 25-223, which granted certain of PGE’s requests and denied others. Both PGE and NewSun have Petitions for Judicial Review of Order 25-075 pending at the Oregon Court of Appeals. PGE cannot predict the outcome or potential impact, if any, on future RFP, AUT, or PCAM proceedings.

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 allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants and effect of Presidential executive orders.

The North Plains Connector would be the nation’s first HVDC transmission connection among three regional U.S. electric energy markets, providing additional flexibility and the sharing of resources across multiple time zones. PGE's resource planning process indicates the need for transmission to provide additional transfer capacity, access to diverse energy resources and enhanced wholesale markets, and ease congestion on the existing western transmission system. PGE continues to explore the North Plains Connector as a resource to meet those load-service needs.

The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS), with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project will accelerate the development of transmission capacity, enabling new generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS communities by increasing resources available to the CTWS to support economic growth opportunities. See “Federal Grants” 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. The 2025 WMP Update forecasts $46 to $49 million in operations and maintenance costs and an additional $57 to $78 million in capital investments, for the year ending 2025, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the nine months ended September 30, 2025, PGE invested $45 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2025 WMP Update.
• *Virtual Power Plant (VPP)—*PGE’s VPP is comprised of Distributed Energy Resources and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) charging solutions support grid reliability and increase portfolio flexibility and resource diversity. These Distributed Energy Resources and flexible loads are the foundation of PGE’s VPP that increasingly provides a growing suite of grid and system services over time. When coordinated through the Company’s Distributed Energy Resources Management Systems, Distributed Energy Resource and flexible loads support cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. As customer participation in PGE’s VPP grows, their actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.
• *Distribution System Plan (DSP)—*In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. The OPUC Staff finalized their review of modifications to the current DSP guidelines in the fourth quarter of 2024 and PGE filed its next DSP in December 2024, fully compliant with the updated requirements. The DSP outlines distribution system assets, describes how the Company plans for new load, including distributed resources such as EVs and rooftop solar installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in demonstrating continual progress towards PGE’s clean energy goals. For further information on recovery of costs related to the DSP, see “Distribution System Plan recovery mechanism” in the Regulatory Matters section of this Overview.

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

Transportation electrification (TE) is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to manage EV charging load, develop infrastructure projects aimed at improving accessibility to EV charging stations, build electric fleet partnerships, and offer programs to support customers’ transitions to TE.

In October 2023, the OPUC accepted PGE’s second TE plan, which covers the 2023 to 2025 time period and considers current and planned activities, along with forecasted EV loads. To date, PGE has incurred $14 million in capital expenditures under the current TE plan.

On July 25, 2025, PGE filed with the OPUC its draft 2026-2028 TE plan, which represents a continuation of the approach and strategy found within PGE’s 2023-2025 TE plan. In the 2026-2028 period covered by the 2026-2028 TE Plan, capital expenditures are expected to be approximately $11 million, pending regulatory approval. PGE anticipates OPUC acceptance of the 2026-2028 TE plan in the fourth quarter of 2025.

PGE continues to pursue advanced technologies to enhance the grid, pursue energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs.

Laws and Regulations

***Trade Tariffs—***Recently, trade tariffs were imposed through presidential executive orders. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect. Trade tariffs may increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase materials and supplies balances and elevate the cost of capital projects. Similarly, prices may rise and lead times may lengthen for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. While PGE’s Canadian natural gas imports are not expected to be impacted by the current state of trade tariffs due to the imports being U.S.-Mexico-Canada Agreement compliant, the future of trade tariff impacts on such imports is uncertain. The Company is unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, as those effects could include project delays and cost increases, and present obstacles to PGE’s strategic plan execution. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.

***Federal Grants—***PGE continues to monitor and pursue 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.

On October 2, 2025, PGE received notice from the U.S. DOE of the termination of four federal grants that originally planned to provide $61 million in federal reimbursement over the life of the grants. PGE has incurred an immaterial amount of costs associated with the terminated grants and does not expect the termination process to result in a material impact on the Company’s financial position and results of operations.

PGE has been awarded six additional grants totaling approximately $252 million, either as a direct recipient or subrecipient. These grants remain in various stages of execution, with the largest being the CTWS and PGE Regional 500kV Transmission Innovative Project. 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 transmission line upgrade grant. The Company cannot predict the ultimate timing and success of securing funding from federal programs or predict the outcome of existing grants.

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

The United States Treasury and the Internal Revenue Service released extensive rules addressing credit transfer eligibility and application, including but not limited to, required registration, filing, and documentation for transferors and transferees to elect and claim a credit transfer. In December 2023, PGE received approval from the OPUC to transfer 2023 PTCs and record any difference in the full value and the discounted value in a property balancing account. Consistent with options available under the IRA, the Company transferred 2023 credits with the final transfer occurring in the first quarter of 2024. On April 17, 2024, PGE received approval from the OPUC to transfer 2024 and 2025 PTCs and record any difference between the full value and the discounted value in a property balancing account. On December 11, 2024, PGE received approval from the OPUC to transfer 2024 ITCs and return the net proceeds from the sale to PGE customers.

PGE has entered into agreements to transfer 2023 through 2025 tax credits and transferred $153 million and $112 million, net of discounts, for cash proceeds in the first nine months of 2025 and in 2024, respectively. The Company expects to generate and transfer approximately $183 million in tax credits in 2025.

***The One Big Beautiful Bill Act—***The OBBB significantly amends or repeals several renewable-energy tax incentives originally enacted under the IRA. Projects currently under construction and expected to be placed in service during 2025 remain eligible for PTC or ITC benefits; accordingly, no adjustments were recorded in the quarter ended September 30, 2025. The transferability of tax credits, as provided under the IRA, also remains in effect. Following the July 7, 2025 executive order that added uncertainty with respect to the specific actions necessary to demonstrate a project’s start of construction, on August 15, 2025, the Treasury Department issued a notice for establishing the beginning of construction for wind and solar projects. The notice requires large projects to satisfy a physical-work test after September 2, 2025, eliminates certain inventory-procurement safe harbors, and accelerates the placed in service deadline to December 31, 2027.

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

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

***HB 2021—***Among other things, HB 2021 requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers to certain targets: 80% reduction by 2030; 90% by 2035; and 100% by 2040, compared to a baseline emission level. The baseline emission level is calculated for each provider by using average annual emissions associated with power generated and purchased for retail load for the years 2010 through 2012, which provide a representative sample of various hydroelectric production years.

HB 2021 requires utilities to develop a CEP for meeting the reduction targets, concurrent with each IRP. In reviewing a CEP, the OPUC must ensure that utilities take action as soon as practicable that facilitates rapid reduction of GHG emissions, demonstrate continual progress toward meeting the targets, and create a plan that is in the public interest. Further, the CEP must result in an affordable, reliable, and clean electric system. The law does not require particular GHG percentage reductions be attained until 2030. The law contains a cost cap and reliability related provisions that can slow or pause compliance with the GHG targets, if implicated. The OPUC has a current open docket, UM 2273, in which provisions regarding the cost cap are being investigated.

A separate law adopted in 2009 requires retail electricity providers to report annually to the Oregon Department of Environmental Quality (ODEQ) the GHG emissions associated with electricity used to serve retail customers. The OPUC must use the data reported to the ODEQ to determine whether the GHG targets have been met.

***RPS standards and related laws—***In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable sources by dates certain and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers no later than 2030.

The Company has a 20% ownership share in Colstrip and, in response to SB 1547, has accelerated depreciation of Colstrip to December 31, 2025. . In order to meet PGE’s regulatory, legislative, and reliability requirements, the Company continues to evaluate its ongoing ownership in Colstrip. See Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” for information regarding legal proceedings related to Colstrip.

Any reduction in generation from Colstrip has the potential to provide additional capacity availability on the Colstrip transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in the Pacific Northwest and neighboring states. PGE has an approximate 15% ownership interest in, and capacity on, the Colstrip transmission facilities. See the Investing in a Clean Energy Future section of this Overview for information regarding development in eastern Montana.

Other provisions of SB 1547:

• establish RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040, for the percentage of electricity that must come from renewable sources;
• limit the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continue unlimited lifespan for all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and
• provide opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s RAC filings.

PGE expects to meet the 2025 RPS threshold.

***HB 3179—***The Oregon Legislature in 2025 passed HB 3179 aimed at making energy bills more affordable and transparent for customers. Under the provisions of the legislation, which the Governor has now signed and which will require a significant amount of rulemaking to implement, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multiyear rate plan on a regular interval that is no less than three and no more than seven years long. The OPUC shall require each electric and natural gas company to, at least annually, file with the OPUC, and make publicly available, a report on any price adjustments that the electric or natural gas company expects within the next twelve months. Such report, the first of which would be due at the end of 2026 at the earliest, must identify all price adjustment requests that an electric or natural gas company has filed or reasonably knows or anticipates to file. Any increase in residential prices may not take effect from November 1 to March 31.

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

• GHG regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA);
• Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the ELG Rule), which applied to wastewater discharges from coal-based generating units and established 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 set emissions limits for filterable particulate matter for coal-based generating units.

On April 8, 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to the CAA Section 112(i)(4) for the EPA’s MATS rule. The EPA subsequently notified companies whether their sources had been granted the exemption. Colstrip was granted an exemption until July 8, 2029. Environmental groups have filed court challenges to the MATS exemptions.

On June 11, 2025, to advance the goals of the President’s Unleashing American Energy executive order, the EPA proposed to repeal the 2024 GHG emissions standards for fossil fuel-fired power plants promulgated under Section 111 of CAA. The EPA also proposed to repeal specific amendments to the updated MATS, that were promulgated in 2024, including the revised filterable particulate matter emissions standard. Additionally, on June 30, 2025, the EPA proposed to update the 2024 ELG Rule to extend compliance deadlines and explore flexibilities to promote reliable and affordable power generation. On July 29, 2025, the EPA proposed to rescind the 2009 endangerment finding, which, if approved, would remove the EPA’s authority to regulate GHGs.

PGE continues to evaluate each of these rules to assess the impact it may have on the Company’s continuing investment in Colstrip, which could be material. Compliance with the 2024 rules could require material upgrades at Colstrip with proposed compliance dates that may not be achievable or require the use of unproven technology, resulting in significant impacts to costs of Colstrip. If upheld, the 2024 MATS and GHG Rules would require compliance as early as 2027 and 2032, respectively. In addition to the EPA’s proposed rulemakings, several legal challenges have been filed regarding these rules. In challenges to all three rules, at the EPA’s request, the courts have granted stays to allow new EPA leadership to reevaluate the rule.

These challenges, or attempts by the federal government to withdraw or modify the regulations, if successful, could affect the applicability to PGE and Colstrip, specifically. Given the uncertainty surrounding applicability of these laws and regulations, PGE cannot reasonably estimate the impact to its results of operations, financial position, and cash flows, however, if the MATS Rule and GHG Rule are ultimately enforced, it would likely result in additional material compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.

Regulatory Matters

PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on such matters.

Corporate structure— On July 25, 2025, the Company submitted a formal application to the OPUC seeking approval of a holding company reorganization. PGE believes it to be in the best interests of its customers and shareholders to update its corporate structure into a holding company structure. The structure currently contemplated involves placing a non-operating corporate entity over the Company’s existing structure. Additionally, this structure would allow for the formation of a subsidiary of the holding company that could hold existing and future transmission assets. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure, and to support construction of new transmission assets, reliability planning, and economic development.

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

***Declared states of emergency—***The OPUC has approved a pre-authorized deferral of costs associated with qualifying declared states of emergency, which would include federal or state declared emergencies with impacts on PGE’s service territory. Under this mechanism, PGE could provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including, among other requirements, a review of utility prudence and application of an earnings test, in a future proceeding.

In January 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to seek recovery of incremental storm expenses through the previously filed emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC under Docket UM 2190 for emergency restoration costs related to the January storm. As of September 30, 2025, PGE had a deferred balance of $47 million, including interest, as a regulatory asset for costs associated with repairing damage to transmission and distribution systems and restoring power to customers.

PGE believes that the deferral is probable of recovery and submitted a request for recovery early in the third quarter of 2025, with price changes to be effective over a two-year period beginning April 1, 2026. The OPUC has adopted a procedural schedule in Docket UE 458 for the regulatory review process that expects an order in March 2026. The OPUC has significant discretion in making the final determination of recovery based on its assessment of prudency and interpretation of the earnings test application, either of which could result in all, or a portion of, the deferral being disallowed. As of December 31, 2024, PGE's preliminary return on equity, based on actual results, did not exceed the OPUC's authorized rate of return. Any disallowance would be a charge to earnings, which could be material to the Company’s financial condition, results of operations, or cash flows. For further information, see “January 2024 storm and damage” in the Regulatory Assets and Liabilities section of Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

PGE is requesting the OPUC authorize recovery of the principal amount of the January 2024 Storm deferral, totaling $44 million plus relevant accrued interest at the cost of capital through and until the time the OPUC issues a decision in this case. PGE estimates this total to be $51 million on April 1, 2026.

***Reliability Contingency Event (RCE)—***Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. As of September 30, 2025, PGE’s deferred balance related to RCEs was $89 million, which includes $87 million related to multiple qualified RCEs deferred during 2024, the most significant of which was related to the January storm event, and $2 million related to RCEs deferred during the first nine months of 2025. PGE filed the results of the 2024 PCAM with the OPUC on July 1, 2025, in Docket UE 457, which included a request for $86 million, without interest, in RCE costs incurred in 2024, initiating a regulatory review process, The OPUC has adopted a procedural schedule for the regulatory review process that expects an order in March 2026. Any resulting refund or collection impacting customer prices is expected to be effective April 1, 2026. PGE believes the deferred amounts as of September 30, 2025 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

The Company requested an extension of the RCE mechanism for one year to extend it through 2026, as market conditions that led to the need for an RCE mechanism have persisted and, in some cases, intensified since the OPUC’s approval of the RCE at the end of 2023. The ongoing volatility in energy markets, increasing frequency of severe weather, and the continued transition to intermittent renewable energy sources, underscores the importance of maintaining this protective measure for both the Company and its customers.

***Power costs—***Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2025 AUT included a final increase in power costs for 2025, and a corresponding increase in net variable power costs (NVPC), of $72 million from 2024 levels, which were reflected in customer prices effective January 1, 2025.

***Renewable recovery framework—***As previously authorized by the OPUC, the RAC is a primary method available to recover costs associated with renewable resources and the inclusion of prudent costs of energy storage projects associated with renewables, under certain conditions. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a General Rate Case (GRC). In 2023, the Company filed for Clearwater, which went into service in January 2024. During 2024, PGE did not submit a request for recovery of any renewable resources under the RAC and has not requested recovery of any renewable resources under the RAC during 2025, nor does it plan to do so.

Under the RAC, during 2023, the Company submitted a filing in OPUC Docket UE 427 for Clearwater proposing to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the twelve month period ending December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits resulting in a net regulatory liability of $40 million, which began amortizing as a refund to customers on March 1, 2025 over a twelve month period, as approved by the OPUC in Order 25-075 issued February 21, 2025.

The OPUC’s order also adopted conditions to be applied to the AUT and clarification of the applicability of those conditions were subsequently provided by the OPUC in Order 25-223, which granted certain of PGE’s requests and denied others. PGE has a Petition for Judicial Review of Order 25-075 pending at the Oregon Court of Appeals. For the period of January 1, 2025 through February 28, 2025, PGE deferred an additional net $7 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that the Company believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC for that period. The OPUC has significant discretion on overall prudence and in making the final determination of recovery or refund. Any cost disallowance or increased refunds would be recognized as a charge to earnings.

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

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

The Order calls for the following:

• a rate base increase of $220 million, net of estimated Investment Tax Credit benefits of $125 million;
• a 9.34% return on equity (ROE); and
• an annual revenue requirement increase of $42 million, excluding impacts related to Net Variable Power Costs (NVPC), compared to PGE’s filed request of $46 million at closing briefs.

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

Other key items in the Order include the adoption of an earnings test at PGE’s authorized ROE, implemented via a deferral to track Seaside revenues and refund excess earnings, if applicable.

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

More information about the Seaside filing (OPUC Docket UE 455) is available on the OPUC website at www.oregon.gov/puc (http://www.oregon.gov/puc).

***Distribution System Plan recovery mechanism—***On July 25, 2025, PGE submitted to the OPUC a request for recovery of costs associated with the Company’s DSP. The regulatory filing allows PGE the opportunity to recover its revenue requirement for these capital investments outside of a general rate case while balancing the interests of customers and PGE.

As a part of the filing, PGE requested that the DSP Alternative Recovery Mechanism be authorized for inclusion in customer prices by April 1, 2026. PGE’s request for recovery includes an annualized revenue requirement increase of $72 million, which includes a 9.34% return on equity as approved in UE 435, and a rate base increase of $317 million.

PGE and parties will work through the regulatory review process for the DSP Alternative Recovery Mechanism during the coming months. The OPUC has adopted a procedural schedule for the regulatory review process in Docket UE 459 that expects an order in March 2026. PGE cannot predict the ultimate outcome of the regulatory process.

***Portland Harbor Environmental Remediation Account (PHERA) mechanism—***The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of September 30, 2025, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision (ROD) issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. Stakeholders have raised concerns that

EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the recovery mechanism allows the Company to defer and recover estimated liabilities and incurred legal and technical analysis expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including, but not limited to, insurance recoveries, and customer prices, as necessary. PGE received settlement proceeds related to Portland Harbor Superfund insurance coverage settlement agreements in the second quarter of 2025, which were deferred into the PHERA mechanism. PGE is continuing insurance recovery activity with additional insurers. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE’s results of operations may be impacted to the extent such expenditures were to be deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

***New Large Load—***In December 2023, the OPUC established Docket UE 430 to investigate new load connection costs. Following a lengthy regulatory process, in December 2024, PGE filed Advice No. 24-38 with the OPUC. This filing introduced several proposed changes to PGE policies and tariffs that, if approved, would: i) reasonably protect other customers from the cost to connect new large load customers; ii) improve transmission system planning and capacity; iii) provide fair recovery of distribution investment costs from large load users; and iv) implement contractual requirements designed to appropriately allocate and recover distribution and transmission costs and mitigate the risk of stranded assets, while providing flexibility to meet large customer needs.

On April 15, 2025, the OPUC approved PGE's filing, as revised, with an effective date of April 16, 2025, on condition that the issues raised in the filing would continue to be evaluated in a new Commission docket, UM 2377. This initial approval allowed PGE to begin working with large load customers to form a load interconnection queue, conduct studies to assess and allocate connection costs, and offer study and service agreements. Applicable agreements with new large load customers may be revised and updated based on the outcome in the separate OPUC proceeding, UM 2377, that was opened to address PGE’s proposed tariff changes and related issues.

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

Operating Activities

In addition to providing electricity from PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, manage risk, and administer its long-term wholesale contracts, the Company purchases and sells electricity in the wholesale market. To fuel its generation portfolio, the Company purchases natural gas in the United States and Canada and sells excess gas back into the wholesale market. PGE also performs portfolio management and wholesale market sales services for third parties in the region and purchases and sells environmental credits bundled with electricity in the wholesale marketplace.

The Company 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.

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

The EDAM, anticipated to begin operation in 2026, will allow market participants to submit bids for their forecasted energy demand and available generation resources a day ahead of expected use. The EDAM will then optimize transmission and resource use across all market participants, enabling access to the lowest-cost resources to meet regional needs. The EDAM is expected to leverage PGE’s existing technology and systems and utilize the Company’s transmission system to connect regional resources, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert Southwest, across a unified market platform.

Given significant uncertainties in key elements of the Western Resource Adequacy Program (WRAP)—including program structure, reliability metrics, and technological readiness—planning for the first binding season has become more challenging. As a result, PGE has notified the Western Power Pool of its intent to withdraw from the WRAP.

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 WRAP. While PGE continues to support the regional planning and analytical framework established by the WRAP, the Company is also in collaboration with utilities committed to the EDAM 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.

PGE generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Summer peak deliveries have continued to exceed those of the winter months for nearly ten years, generally resulting from growing air conditioning demand and the trend toward a warmer overall climate. In August 2023, demand reached a new all-time high, surpassing the previous mark, which was set in summer 2021. Historically, PGE had experienced its highest average megawatts (MWa) deliveries and retail energy sales during the winter heating season and recorded its current winter peak load in December 2022. Summer peak deliveries in each year since 2021 have exceeded that winter peak.

Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to enhance the availability of supply chain- constrained items that are needed to serve new and existing customers, such as securing inventory of critical materials to improve reliability, reserving manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. The Company’s materials and supplies forecasting process is designed to secure materials availability as well as mitigate cost increases through long-term agreements, supplier engagement, and expanding the supply base. PGE is monitoring the fluid situation around tariffs and trade policies and continues to evaluate any potential impact to its operations and the need to implement applicable mitigation strategies.

**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:

Total retail energy deliveries for the nine months ended September 30, 2025 increased 5.0% compared with the nine months ended September 30, 2024, driven by an increase in industrial deliveries. The first nine months of 2025 contained one fewer delivery day due to leap year in 2024.

Residential weather-adjusted deliveries saw average usage per customer 0.6% higher during the first nine months of 2025 compared with 2024, while the average number of residential customers was 1.4% greater. PGE has seen seasonal shifts in residential average usage in recent years as the number of rooftop solar installations have increased in its service territory and funding of energy efficiency programs continues. Customers also continue to respond with increased air conditioning saturation and utilization as the region has experienced cooling degree days well above the 15-year averages for the last five consecutive cooling seasons.

The industrial class continues to show growth as overall energy deliveries are up 15.2% in the nine months ended September 30, 2025 compared to the same period in 2024, reflecting strength primarily in the digital services sector.

The following table indicates the number of heating and cooling degree-days for the three and nine months ended September 30, 2025 and 2024, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

During the three months ended September 30, 2025 compared to the same three months of 2024, weather had a less positive impact on Total Retail deliveries as the Company’s service territory saw fewer heating and cooling degree-days than in 2024, although cooling degree-days continue to run well above average. While temperatures were above average during the third quarters of both 2025 and 2024, the number of cooling degree-days recorded in the third quarter of 2025 were 13% above average compared to 23% above in the same period of 2024.

The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. Had the cap limit been fully subscribed and utilized, 12% of PGE’s total retail energy deliveries for the first nine months of 2025 would have been to these customers.

PGE offers service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 16% of the Company’s retail energy deliveries could have been supplied by ESSs to Direct Access customers.

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 8% in the nine months ended September 30, 2025 compared to the prior year, which is comparable to PGE’s overall 6% increase in deliveries over the same comparative periods. As a result, actual deliveries to Direct Access customers of energy supplied by ESSs continue to represent 11% of PGE’s total retail energy deliveries for the first nine months of 2025 and as they did in 2024. The OPUC, under docket UM 2024, has undertaken an investigation of long-term Direct Access with program caps being one of the issues under consideration. This regulatory proceeding is expected to conclude in early 2026.

**Power Operations—**PGE utilizes a combination of its own generating 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 nine months ended September 30, 2025 and 2024:

(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 nine months ended September 30, 2025 compared to 2024 increased 7%. This increase was primarily driven by fewer outages in 2025 as compared to 2024. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 4% during the nine months ended September 30, 2025 compared to 2024 primarily due to more favorable hydro conditions in the current period. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 5% while energy generated by the Company-owned facilities increased 1% during the nine months ended September 30, 2025. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 10 years of historical stream flow data. See “Purchased power and fuel” in the Results of Operations section in this Item 2, for further detail on regional hydro results.

Energy received from PGE-owned and under contract wind resources decreased 11% during the nine months ended September 30, 2025 compared to 2024. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available.

Under the PCAM, the Company may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual

NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the PCAM as calculated for regulatory purposes:

• For the nine months ended September 30, 2025, actual NVPC was $3 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2025 is currently estimated to be below the baseline and within the established deadband range. Accordingly, there is no estimated refund to customers expected under the PCAM for 2025.
• For the nine months ended September 30, 2024, actual NVPC was $87 million below baseline NVPC. For the year ended December 31, 2024, actual NVPC was $78 million below baseline NVPC, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE was below 10.5%, there was no estimated refund to customers under the PCAM for 2024. A final determination regarding the 2024 PCAM results will be made by the OPUC through a public filing and review in 2025 and early 2026.

As approved by the OPUC in PGE’s 2024 GRC, the RCE mechanism allows PGE to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. For more on the RCE, see “Reliability contingency events” in the Regulatory Assets and Liabilities section of Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Operating and Maintenance

**Business transformation and optimization expenses—**PGE has incurred incremental costs, which include strategic advisory and workforce realignment expenses, focused on a multi-year cost management initiative to realize long-term benefits. Additionally, PGE has incurred incremental accounting, legal, and consulting costs related to its submission of a regulatory application for approval of a holding company reorganization. For more on the corporate structure see “Corporate Structure” in the Regulatory Matters section of this Overview.

For more information on the impact of these costs on quarterly results, see “Generation, transmission and distribution,” “Administrative and other, and “Depreciation and amortization ” in the Results of Operations section of this Overview. The Company expects to incur business transformation and optimization expenses related to these initiatives throughout 2025 and 2026.

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):

* Includes an allowance for borrowed funds used during construction of $2 million and $4 million for the three months ended September 30, 2025 and 2024, respectively, and $9 million and $12 million for the nine months ended September 30, 2025 and 2024, respectively.

Net income for the three months ended September 30, 2025 increased $9 million, or 10%, compared to the same period of 2024. Retail revenues increased as a result of both price changes as authorized by the OPUC and higher customer demand. Purchased power and fuel declined slightly, reflecting a reduction in overall system load, while average variable power costs per MWh showed little change. Generation, transmission and distribution expenses were down reflecting the recognition of an earnings test deferral release recorded in the comparative period in 2024 that is not recurring. Although Administrative and General expense decreased slightly compared to 2024, a total of $10 million in business transformation and optimization expenses was recorded in 2025 of which $7 million is reflected in Administrative and General Expense with the balance being in Generation, transmission and distribution expense and Depreciation and amortization expense. Increases in Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, were largely anticipated and somewhat offset in net income by increased revenues. Income tax expense was up primarily due to lower PTC benefits.

Net income for the nine months ended September 30, 2025 decreased $10 million, or 4%, compared to the same period of 2024. Retail revenues increased primarily due to price changes to cover anticipated higher NVPC and general cost increases, as authorized by the OPUC. Wholesale revenues have decreased, driven by a decline in the average price of wholesale deliveries, although lower sales volumes also contributed to the decline. The reduction in Purchased power and fuel reflects lower average variable power costs per MWh and lower overall system load being mostly offset by the reduced costs in 2024 due to the deferral under the RCE mechanism that did not recur. Generation, transmission and distribution expenses were relatively unchanged in total although 2024 included the recognition of an earnings test deferral release recorded in the comparative period in 2024 that is not recurring. While total Administrative and General expense remained fairly flat compared to 2024, a total of $25 million business transformation and optimization expenses was recorded in 2025 of which $21 million was in Administration and General Expense and was slightly more than offset by savings, with the balance being in Generation, transmission and distribution expense and Depreciation and amortization expense. Increases in Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, were largely anticipated and somewhat offset in net income by increased revenues. Income tax expense was up due primarily to lower PTC benefits.

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

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*Total retail revenues—*The following items contributed to the increase in Total retail revenues for the three and nine months ended September 30, 2025 compared to the same periods in 2024 (in millions):

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 September 30, 2025 decreased $56 million, or 29%, from the three months ended September 30, 2024, resulting from a combination of a 19% decrease in sales volumes, lower average wholesale sales price, and reduced environmental credit sales.

For the nine months ended September 30, 2025, Wholesale revenues decreased $143 million, or 31%, from the nine months ended September 30, 2024 as the Company experienced a $79 million reduction in revenues due to a decline in average sales prices resulting from market volatility around specific regional weather events in January 2024 and milder overall weather in 2025. In addition, the sale of environmental credits produced $34 million less revenue and the reduction in Wholesale sales volume produced $30 million less revenue in 2025 than during the same period of 2024.

Other operating revenues for the three months ended September 30, 2025 were down $1 million from the comparable period in 2024. In the nine months ended September 30, 2025, Other operating revenues were up $9 million compared to the same period of 2024, primarily the result of an increase from imbalance transactions with ESS providers, which is offset in Purchased power and fuel expense.

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 nine months ended September 30, 2025 compared to the same periods in 2024 (dollars in millions):

For the three months ended September 30, 2025, the $1 million decrease related to the change in average variable power cost per MWh was driven by a 3% decrease in the average cost of purchased power, and a 6% increase in the average cost for the Company’s own generation. The $20 million decrease related to total system load was comprised of a 5% decrease of energy obtained from purchased power, and a 6% decrease in the Company’s own generation.

For the nine months ended September 30, 2025, the $64 million decrease related to the change in average variable power cost per MWh was driven by a 8% decrease in the average cost of purchased power and a 1% decrease in the average cost for the Company’s own generation. The $41 million decrease related to total system load was comprised of a 7% decrease of energy obtained from purchased power, offset by a 4% increase in the Company’s own generation.

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

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

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

* Volumetric water supply forecasts and historical averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center, with the Natural Resources Conservation Service and other cooperating agencies.

Actual NVPC for the three and nine months ended September 30, 2025 increased compared to the same periods in 2024 as follows (in millions):

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 September 30, 2025 and 2024, actual NVPC was $15 million above and $35 million below baseline NVPC, respectively. For the nine months ended September 30, 2025 and 2024, actual NVPC was $3 million and $87 million below baseline NVPC, respectively.

Based on forecast data, NVPC for the year ending December 31, 2025 is currently estimated to be below the baseline and within the deadband. Accordingly, there is no estimated refund to customers expected under the PCAM for 2025.

Generation, transmission and distribution decreased as follows for the three and nine months ended September 30, 2025 compared to the same periods in 2024 (in millions):

In the table above, changes shown for the three and nine months ended include $(1) million and $2 million related to vegetation management, respectively, zero and $13 million related to wildfire mitigation, $3 million and $4 million related to major maintenance costs, and zero and $3 million related to storm response costs that have been offset through customer prices or specific regulatory mechanisms.

Administrative and other is as follows for the three and nine months ended September 30, 2025 compared to the same periods in 2024 (in millions):

In the table above, for the three and nine months ended September 30, 2025, respectively, $1 million and $9 million of the decrease in customer related costs is due to regulatory programs that have been offset through customer pricing or specific regulatory mechanisms.

Depreciation and amortization expense increased $22 million and $58 million in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024. The increases were primarily due to higher utility plant balances. Included in expense for 2025 is $1 million related to business transformation and optimization.

Taxes other than income taxes increased $3 million and $7 million in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024. The increases were driven by higher property taxes and higher franchise fees, partially offset by lower payroll taxes.

Interest expense, net increased $7 million and $17 million in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to higher long-term debt balances.

Other income, net decreased $3 million and $6 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024. The decreases were primarily driven by lower AFUDC on construction work in progress balances.

Income tax expense increased $9 million and $23 million in the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily driven by lower PTC benefits resulting from the expiration of the 10-year PTC generation window at Tucannon near the end of 2024 and higher 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, 2024, filed with the SEC on February 14, 2025.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

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

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**Cash Flows from Operating Activities—**Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the nine months ended September 30, 2025 compared with the nine months ended September 30, 2024 (in millions):

PGE estimates that non-cash charges for depreciation and amortization in 2025 will range from $550 million to $575 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $950 million to $1.05 billion.

**Cash Flows from Investing Activities—**Net cash used in investing activities for the nine months ended September 30, 2025 increased $16 million when compared with the nine months ended September 30, 2024. Cash flows used in investing activities consist primarily of capital expenditures related to BESS projects and other new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $23 million.

Excluding AFUDC, the Company plans to make capital expenditures of $1.2 billion in 2025, which it expects to fund with cash to be generated from operations during 2025, as discussed above, the issuance of short- and long-term debt, and issuances of shares pursuant to the at-the-market offering program. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

**Cash Flows from Financing Activities—**During the nine months ended September 30, 2025, net cash provided by financing activities was primarily the result of the funding of $310 million in First Mortgage Bonds (FMBs) and $49 million in proceeds from the issuance of common stock pursuant to at-the-market offering programs. This was partially offset by payment of $167 million of dividends and $102 million of long-term debt.

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2025 through 2029, excluding AFUDC (in millions):

(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.

Debt and Equity Financings

PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, credit ratings, capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to inflationary pressures and interest rate increases by the federal reserve. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.

For 2025, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $950 million to $1.05 billion, and issuances of long-term debt of up to $450 million. PGE plans to fund any shortfall through the combination of issuance of common stock and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt, equity, and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments.

Short-term Debt. Pursuant to an order issued by the FERC in January 2024, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2026. The following table shows available liquidity as of September 30, 2025 (in millions):

(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 September 30, 2025, 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 September 30, 2025, PGE had no outstanding balance on the revolving credit facility.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of September 30, 2025, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $750 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.

Long-term Debt. As of September 30, 2025, PGE’s total long-term debt outstanding, net of $17 million of unamortized debt expense, was $4,730 million.

On March 25, 2025, PGE entered into a Bond Purchase Agreement related to the sale of $310 million in First Mortgage Bonds (FMBs). The FMBs were issued and funded in full on March 25, 2025 and consist of:

• a series, due in 2035, in the amount of $60 million that will bear interest from its issuance date at an annual rate of 5.36%;
• a series, due in 2045, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 5.72%; and
• a series, due in 2055, in the amount of $200 million that will bear interest from its issuance date at an annual rate of 5.84%.

On November 14, 2024, PGE drew a $220 million loan under a 366-day term loan agreement. On December 31, 2024, PGE repaid $50 million of the term loan and, on March 31, 2025, the Company repaid another $102 million, leaving an outstanding balance of $68 million.

Equity. In July 2024, PGE entered into an equity distribution agreement under which it could sell up to $400 million of its common stock through at-the-market offering programs. In the fourth quarter of 2024 the Company entered into forward sale agreements for 1,420,049 shares. In December 2024, the Company issued 1,066,549 shares pursuant to the forward sale agreements and received net proceeds of $50 million. The Company entered into forward sale agreements for 1,996,890 shares, 1,707 shares, and 3,757,835 shares in the first, second, and third quarter of 2025, respectively. In August 2025, the Company issued 1,114,529 shares pursuant to the forward sale agreements and received net proceeds of $49 million. The Company could have physically settled the remaining amount by delivering 4,995,403 shares in exchange for cash of $209 million as of September 30, 2025. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

For additional information on the at-the-market offering programs, see Note 7, Shareholders’ Equity, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 45.5% and 45.6% as of September 30, 2025 and December 31, 2024, respectively.

Credit Ratings and Debt Covenants

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

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 September 30, 2025, PGE had posted $160 million of collateral with these counterparties, consisting of $59 million in cash and $101 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 September 30, 2025, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $83 million, and decreases to $29 million by December 31, 2025 and to $2 million by December 31, 2026. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $173 million and decreases to $97 million by December 31, 2025 and to $57 million by December 31, 2026.

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 September 30, 2025, under the most restrictive issuance test in the Indenture, the Company could have issued up to $671 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of September 30, 2025, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 54.5%.

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

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2025, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in PGE’s internal control over financial reporting that occurred during the quarter ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Other than the items noted below, there have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 14, 2025.

Trade tariffs and related market volatility and supply chain disruptions could increase PGE’s operating costs, impair PGE’s ability to complete capital projects, and impede access to capital markets.

Recently imposed trade tariffs could negatively impact PGE’s financial condition, results of operations, and cash flows. While the impact of these trade tariffs is difficult to predict at this time, economic volatility, supply chain disruption, or cost increases triggered by these trade tariffs could negatively affect PGE’s ability to execute its strategic plan. Adverse capital and credit market conditions caused by the new trade tariffs could negatively affect the Company’s access to capital, cost of capital, and ability to complete capital projects.

The perceived risk of wildfire exposure could adversely affect PGE’s access to capital, hinder the Company’s ability to execute its strategic plan, and increase costs.

The lack of legislation limiting wildfire-related liability or providing a wildfire relief fund may impact PGE’s credit rating, which could hamper the Company’s ability to attract capital and invest in the infrastructure required to meet emissions targets and customer reliability needs. PGE may face barriers to securing cost-efficient contracts if there is a perceived risk of utility financial losses related to wildfire. Business partners may be forced to increase prices to recognize the unresolved financial exposure that PGE presents as a counterparty.