POR 10-K & 10-Q changes, risk factors and insider trading

Changes in the global and local climate could result in more intense, frequent, and extreme weather events such as ice and snowstorms, high wind, flooding, changes in regional rainfall and snowpack levels, high heat events, drought conditions, declining tree health, and increased risk of wildfires. These events may disrupt energy delivery, cause power outages, or impair the use of, and damage, the Company’s facilities and transmission and distribution system. Such events could result in a reduction in revenue and an increase in additional costs to restore service, repair facilities, purchase power and fuel to serve PGE load requirements, and procure insurance related to such impacts. The increase in additional costs could also have an adverse effect on cash flow and liquidity. In response to more intense, frequent, and severe weather events,events and increasing peak loads, PGE may need to make additional investments in generation, transmission, distribution, and distributionenergy storage assets to enhance reliability and resiliency. Weather-related events could also cause system constraints or disrupt transmission flows, resulting in decreased reliability for customers. Severe weather may also require increased PGE personnel availability, which could result in increased operating expenses as well as increased safety risk. In certain instances, PGE relies on mutual aid support to assist in the recovery from severe weather. Lack of availability of mutual aid support could result in increased time to restore services to customers as well as increased costs and decreased customer satisfaction.

Wildfires of greater size and prevalence, such as those of a magnitude seen in Oregonthe West Coast in recent years, could negatively affect public safety, the resilience of the electric grid, customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to provide reliable service to its customers, PGE’s ability to access the wholesale energy market, PGE’s ability to operate its generating facilities and transmission and distribution systems, PGE’s costs to maintain, repair, and replace such facilities and systems, and PGE’s ability to recover these additional costs. While PGE has wildfire mitigation programs in place, PGE may not be able to effectively implement its wildfire mitigation initiatives or wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. PGE may be unable to effectively implement a PSPS and de-energize its system in the event of heightened wildfire risk, or the PSPS may not be able to prevent a wildfire, which could lead to potential liability if energized systems are determined to be the cause of wildfires that result in harm.

In the normal course of business, PGE collects, processes, and retains sensitive and confidential customer and employee information, as well as proprietary business information, and operates systems that directly impact the availability and transmission of electric power in its service territory. PGE owns and operates generation, transmission, distribution, and other facilities that depend on information technology systems. The Company is exposed to, and may be adversely affected by, interruptions to its computer and information technology systems and sophisticated cyber-attacks. As with most companies, PGE has experienced attempts to breach the Company’s systemssystems, customer accounts and other similar incidents. A cyber-attack may cause large-scale disruption to the U.S. bulk power system or PGE operations and could target the Company’s computer systems, software, or networks to achieve such disruption. Generation, transmission, and distribution facilities, in general, have been identified as potential targets of physical or cyber-attacks. Employees could also be potential targets of both physical or cyber attacks. In addition, physical attacks on transmission and distribution facilities have occurred in the United States. Despite the security measures in place, the Company’s systems and assets, and those of third-party service providers, could be vulnerable to cybersecurity attacks, data security breaches, physical attacks and security breaches, acts of terrorism, civil unrest or other similar events that could disrupt operations, cause damage to the Company’s generation, transmission, or distribution facilities, impact reliability of the transmission and distribution system,systems or information technology systems, inhibit the capability of equipment or systems to function as designed or expected, prevent service to customers or collection of revenues, or result in the release of sensitive or confidential customer, employee, or Company information. Such events could cause a shutdown of service, expose PGE to liability, or cause reputational damage. In addition, the Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches. A breach of certain business systems could impact PGE’s ability to initiate, authorize, process, record, and report financial information. The cost of repairing damage to PGE’s facilities and infrastructure caused by acts of terrorism, and the loss of revenue if such events prevent PGE from providing utility service to its customers, could adversely impact its financial condition and results of operations. PGE maintains insurance coverage against some, but not all, potential losses resulting from these risks. However, insurance is limited in scope and subject to exceptions, and may not be adequate to protect the Company against liability in all cases. Insurers may dispute or be unable to perform their obligations to the Company, or may not be available at rates that are commercially reasonable. PGE continuously seeks to maintain a robust program of security and controls, but the impact of a physical or material information technology event could have a material adverse effect on the Company’s competitive position, reputation, results of operations, financial condition and cash flows.

PGE has exposure to natural and human-caused disasters and other risks, including, but not limited to, a pandemic, earthquake, accidents, equipment failure, acts of terrorism, civil unrest, acts of vandalism, computer system outages, and other events. Such events, which may be amplified by the fact that PGE’s business activities are concentrated in one region, could disrupt PGE operations, damage PGE facilities and systems, interrupt the delivery of electricity, increase repair and service restoration expenses, reduce revenues, cause the release of harmful materials, cause fires or flooding, and subject the Company to liability. Such events, if repeated or prolonged, can also affect customer satisfaction and the level of regulatory oversight.

The operation of electric generation, transmission, battery storage, and distribution infrastructure involves inherent risks, includingincluding, but not limited to, breakdown or failure of equipment, motor vehicle accidents, fires involving the utility’s equipment, dam failure at company-owned hydroelectric facilities, public and worker safety, human contact with energized equipment, and operator error. A portion of the Company’s operations relies on Company- or third party-owned natural gas transmission and distribution infrastructure and involves inherent risks, such as leaks, explosions, mechanical problems, and worker and public safety.

These risks could cause significant harm to workers and the public including loss of human life, significant damage to property, adverse impacts on the environmentenvironment, and impairment of PGE’s operations, all of which could result in financial losses that would have a material adverse effect on the Company’s results of operations and financial condition and reputational harm. PGE is also required to comply with new and changing regulatory standards involving safety compliance. The cost to comply with such requirements could be significant, and failure to meet these regulatory standards could result in substantial fines.

Long-term increases in both the number of customers and demand for energyenergy, as well as the natural aging of existing infrastructure, will require continued expansion and upgrade of PGE’s generation, transmission, and distribution systems. Construction of new facilities and modifications or replacements of existing facilities could be affected by factors such as unanticipated delays and cost increases, includingtariffs impacting the cost and availability of necessary equipment, supply chain disruption and cost inflation, community opposition, availability of a skilled workforce, increases in interest rates, failure of counterparties to perform under agreements, ability to build or secure transmission, and the failure to obtain, or delay in obtaining, necessary permits from state or federal agencies or tribal entities. Supply chain disruption could be exacerbated by government tariffs as well as inflation. Delays and cost increases could result in failure to complete the projects or the abandonment of capital projects, which could eliminate or impair PGE’s ability to recover related costs in the rate determination process. In addition, failure to complete construction projects according to specifications could result in reduced plant efficiency, equipment failure, and plant performance that falls below expected levels, which could increase operating costs.

The OPUC regulates the prices that PGE charges, which is a major factor in determining the Company’s operating income, financial position, liquidity, and credit ratings. As a general matter, PGE relies on customer prices to recover most of the costs incurred in connection with the operation of its business, including, among other things, costs related to capital projects (such as the construction of new facilities or the modification of existing facilities), the costs of compliance with legislative and regulatory requirements (including environmental laws), and the costs of damage from storms and other natural disasters.disasters, including the costs to implement wildfire mitigation plans. Prices paid by customers are impacted by commodity prices, costs and capital investments, particularly investments made to meet increased customer demand and meet the state’s clean energy goals. Regulators may deny recovery of costs it considersconsidered imprudently incurred. Regulators have delayed recovery of prudently incurred costs due to affordability concerns. Although the OPUC is required to establish customer prices that are fair, just, and reasonable, it has significant discretion in the interpretation of this standard. The Company’s cost recovery proceedings may not authorize sufficient revenues, or the actual costs could exceed its authorized or forecasted costs. Customer dissatisfaction with prices and national and statewide affordability concerns may result in decreased or delayed recovery of prudently incurred costs. PGE attempts to manage its costs at levels consistent with OPUC-approved prices. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the Company’s financial and operating results could be adversely affected.

In the normal course of its business, PGE is subject to regulatory proceedings, lawsuits, claims, and other matters, which could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. Such matters include governmental policies, legislative action, and regulatory audits, investigations, and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, corporate structure, 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, and current or prospective wholesale and retail competition. These matters are subject to many uncertainties and involve many different parties with sometimes conflicting interests, which can increase regulatory scrutiny. Therefore, management cannot predict with certainty the ultimate outcome of any proceeding. The final resolution of certain matters in which PGE is involved could result in disallowance of capital and operating expenses previously deferred, increased litigation, changes to established regulatory procedures or could require that the Company incur expenditures over an extended period and in a range of amounts that could have an adverse effect on its cash flows and results of operations. Similarly, the terms of resolution could require the Company to change its business practices and procedures, which could also have an adverse effect on its cash flows, financial position, or results of operations. New laws, changes in legal precedent, or novel interpretations of existing regulations could also result in adverse effects on cash flows and results of operations.

PGE is subject to various environmental laws, regulations, and other standards including federal, state, and local environmental statutes, rules and regulations relating to air quality, water quality and usage, soil quality, permitting, GHG emissions such as carbon dioxide, waste management, hazardous wastes, fish, avian and other wildlife mortality and habitat protection, historical artifact preservation, natural resources, health, and safety. Compliance with such laws and regulations could, among other things, prevent or delay the development of power generation and transmission and distribution facilities, restrict output of facilities, limit the use of fuels required for power generation, require additional pollution control equipment, require investment in non-emitting resources, force early retirement of assets, and otherwise increase costs and increase capital expenditures.

Compliance with any new or additional GHG emissions reduction and air quality requirements could require PGE to incur significant expenditures, including those related to carbon capture and sequestration technology, purchase of emission allowances and offsets, fuel switching, and the retirement or replacement of high-emitting generation facilities with non-emitting facilities. The cost to comply with potential GHG emissions reduction and air quality requirements is subject to significant uncertainties, including those related to: i) the timing of the implementation of emissions reduction rules; ii) required levels of emissions reductions; iii) requirements with respect to the allocation of emissions allowances; iv) the maturation, regulation, and commercialization of carbon capture, sequestration, and storage technology; and v) PGE’s compliance alternatives. Although the Company cannot currently estimate the effect of future laws and regulations on its results of operations, financial condition, or cash flows, the costs of compliance with such legislation or regulations could be material.

PGE participates in a federal grant program established for the modernization of energy infrastructure through the Infrastructure Investment and Jobs Act (IIJA),Act, and some PGE customers receive funds through the CHIPS actand Science Act of 2022 to support the domestic production of semiconductors and various federal science agencies. Failure to continue these programs, or revocation of grants or funds allocated through these programs could impact the ability to continue to make certain infrastructure investments, or could result in the customers’ demand forecast being lower than anticipated, resulting in stranded assets.

PGE has experienced load growth in recent years, and projects a significant amount of growth in the future. Significant growth may result in PGE’s inability to generate or procure enough energy to meet customer demand. PGE's ability to invest in infrastructure necessary to support growth is dependent on regulatory approvals as is PGE's ability to allocate the costs of growth appropriately to customer classes. Unfavorable economic conditions in Oregon, such as, for example, increased inflation, may result in reduced demand for electricity and impair the financial stability of PGE’s customers. Such reductions in demand could adversely affect PGE’s results of operations and cash flows. Significant growth may result in PGE’s inability to generate or procure enough energy to meet customer demand. Economic conditions and regulatory outcomes could also result in an increased level of uncollectible customer accountsaccounts. and cause theThe Company’s business customers, vendors and service providers tocould experience cash flow problems and be unable to perform under existing or future contracts and could result in investment in assets to accommodate higher load that are no longer needed.

Credit rating agencies routinely evaluate the Company, and their ratings of long-term and short-term debt are based on a number of factors, including the perceived supportiveness of the regulatory environment affecting the utility operations, the Company's ability to recover costs through customer pricing, the Company's ability to effectively manage risks, the Company’s cash generating capability, level of indebtedness, overall financial strength, the status of certain capital projects, as well as factors beyond PGE’s control, such as tax reform, the state of the economyeconomy, and industry generally. A ratings downgrade could increase fees on PGE’s syndicated unsecured revolving credit facility, commercial paper program, and letter of credit facilities, increasing the cost of funding day-to-day working capital requirements, and could also result in higher interest rates on future long-term debt. A ratings downgrade could also restrict the Company’s access to the commercial paper market, a principal source of short-term financing, or result in higher interest costs.

The risk of volatility in power costs is partially mitigated through the AUT and the PCAM. Application of the PCAM requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, the PCAM is expected to only partially mitigate the potentially adverse financial impacts of forced generating plant outages, reduced hydro and wind availability, interruptions in fuel supplies, and volatile wholesale energy prices. A new mechanism, theThe Reliability Contingency Event (RCE), which,mechanism, likewhich operates under the PCAM,PCAM tariff, allows for cost sharing and deferral of certain costs for specific events, was introduced through the 2024 GRC. This mechanism expiresexpired at the end of 2025.

PGE meets its customers’ energy demand requirements based on capacity obtained from its generating facilities and third-party PPAs. The Company continuously evaluates how much capacity it will need to meet reasonably expected demands of customers and provide reasonable reserves. PGE is also required to file IRPs with the OPUC that detail the Company’s plan to meet the future energy and capacity needs of its customers through a least-cost, least-risk combination of energy generation and demand reduction, while also aggressively reducing GHG emissions from the power supply. If the capacity provided by the Company’s generating facilities and purchased power is not adequate to meet customers’ energy demands, or if customer demand increases beyond forecasts, PGE may be required to purchase more power from third parties, which may not come from non-emitting resources, invest in acquiring additional generating or battery storage facilities, or invest in extending the operating life of existing generating assets, which could increase GHG emissions. Any failure to obtain adequate capacity to meet customers’ energy demand requirements could increase its costs and negatively impact PGE’s customer satisfaction, all of which could have an adverse impact on PGE’s business and results of operations.

A basic premise of PGE’s business as a vertically integrated utility is the ability to produce electricity at competitive prices due to economies of scale. Furthermore, a key component of PGE’s growth is its ability to construct, own, and operate facilities. Many companies and organizations conduct research and development activities to seek improvements in alternative technologies and distributed generation. Advancements in and creation of new technologies could include fuel cells and micro turbines, wind turbines, photovoltaic solar cells, distributed generation, modular nuclear energy, hydrogen, ongoing customer energy efficiency, two-way grid enabling customer-owned generation, and advances in batteries or energy storage. It is possible that advances in such technologies, or other current technologies, will reduce the cost of alternative methods of electricity production or storage to a level that is equal to or below that of existing methods.

Rapidly changing stakeholderStakeholder expectations and standards with respect to PGE’s environmental, social, and governance (ESG) programs could result in increased costs and exposure to incremental risk.

Investors, lenders, rating agencies, customers, regulators, state legislatures, employees, and other stakeholders areoften increasing their focus on evaluatingevaluate companies as corporate citizens based on their ESG programs and metrics. Based on PGE’s ESG profile, investors and lenders may elect to increase their required returns on capital offered to the Company, reallocate capital, or not commit capital as a result of their assessment of the Company’s ESG profile. Such actions by investors and lenders could increase PGE’s cost of, or access to, capital and financing.

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “may,” “plans,” “predicts,” “projects,” “will likely result,will,” “will continue,” “should,” “based on,” “conditioned upon,” “considers,” “could,” “expected,” “forecast,” “goals,” “needs,” “promises,” “subject to,” “strategic imperatives,” “targets,” or similar expressions are intended to identify such forward-looking statements.

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,actions, and regulatory audits, investigations and actions, including those of the FERC, the OPUC, the SEC, the Division of Enforcement of the Commodity Futures Trading Commission, the EPA, and the ODEQInternal 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;

•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; and

new or revised governmental policies, executive orders, legislative actions, and regulatory audits, investigations, and actions, including those of the Federal Energy Regulatory Commission (FERC), the Public Utility Commission of Oregon (OPUC), and the Internal Revenue Service,Service (IRS), with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs and capital investments, energy trading activities, tax credits, and current or prospective wholesale and retail competition;

uncertainties associated with increased energy demand orthat differs from forecasts, including significant or accelerated load growth in demand due tofrom new data centers,centers includingand the concentration of data centers,center load, and the ability to obtaintimely regulatoryserve approvals,such growth due to regulatory, environmental, and other permitspermitting to construct new facilities in a timely mannerrequirements;

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

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

volatility in wholesale power and natural gas prices, including but not limited to volatility caused by macroeconomic and international issues, such as the warescalation involvingof US operations in the UnitedMiddle States, Iran and Israel,East, that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;

changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes, including the potential impact of trade tariffs and the warescalation involvingof US operations in the UnitedMiddle States, Iran and Israel,East, on the Company’s power costs;

cybersecurity attacks, data security breaches, physical attacks and security breaches, the use or misuse of artificial intelligence technologies, including AI-enabled cyberattacks, fraud, misinformation, unauthorized disclosure of sensitive information, operational errors, or other malicious acts, internally or to third parties, that cause damage to the Company’s generation, transmission, or distribution facilities, impact information technology or operational technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, vendor, employee, or Company information;

employee workforce factors, including potentiallabor strikes, work stoppages, collective bargaining negotiations that result in increased labor costs or other less favorable terms, the inability to obtain contracted workers at reasonable rates during a labor disruption, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover dueresulting tofrom macroeconomic trendsconditions such as voluntaryelevated resignationlevels of largevoluntary numbersresignations, any of employeeswhich could increase costs and adversely affect operations and financial results;

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

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

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

As of MarchJune 31,30, 2026, the Green Future Impact Program has an approved capacity of 750 megawatts (MW) nameplate, of which 482 MW have been subscribed. Through this voluntary program, the Company seeks to support customers’ clean energy acceleration.

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 towardstoward the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was submitted to the OPUC in connection with, the Company’s 2023 Integrated Resource Plan (IRP) in March 2023, the first combined IRP and CEP. That filing projected PGE’s resource and capacity needs over the next 20 years and proposed an Action Plan to meet near-term needs, subject to HB 2021 emissions reduction requirements.

OnIn June 18, 2025, PGE submitted a CEP/IRP Update to the OPUC. The CEP/IRP Update refreshed forecasts and planning assumptions used in the 2023 CEP/IRP and identified a new Preferred Portfolio as a result of the refreshedupdated analysis. PGE did not propose any changes to the Action Plan that was acknowledged withinin the 2023 CEP/IRP, which supports the Company's progress toward emissions targets and Preferred Portfolio resource needprocurement procurementneeds through the 2025 All-Source RFP. ThisBased on the information available at the time, PGE concluded that this approach representsrepresented the best combination of cost, risk, community benefit, and decarbonization.decarbonization objectives.

To better distinguish resource needs, the CEP/IRP Update reports the capacity from hybrid solar and battery storage resources by individual technology. The capacityUpdate identified a need isfor approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity, inclusive of 2023 and 2025 RFP projects.projects, or any other additional resource procurement activities outside of the RFP. These estimates are based on planning assumptions and forecasts that may change as market conditions, customer needs, stakeholder input, and regulatory requirements continue to evolve.

PGE 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 onin April 17, 2025,2025 and regulatory approval was granted on July 22, 2025. The Company issued the RFP to market on July 31, 2025, seeking bids for resources that can provide non-emitting dispatchable capacity and renewable generation.

PGE is proceeding to commercial negotiations with projects on the final shortlist, prioritizing those that include renewable generation and that have a viable pathway to achieve commercial operations earlier in the 2028 - 2030 eligibility period. The ultimate outcome of the RFP processprocess, or any other additional resource procurement activities outside of the RFP, may involve the selection of multiple projects for both renewable and non-emitting dispatchable capacity resources, which PGE expects will be approximately 2,500 MWs in total.

PGEOn anticipatesMay 26, 2026 the OPUC to consider acknowledgement ofacknowledged the 2025 RFP final shortlist in May 2026.shortlist. Additional details of the 2025 RFP (OPUC Docket UM 2371) are available on the OPUC website at www.oregon.gov/puc.

In May 2024, PGE signed a non-binding memorandum of understanding in the development of the North Plains Connector, an approximately 415-mile, high-voltage direct-current (HVDC) transmission line to be constructed with endpoints near Bismarck, North Dakota and Colstrip, Montana. The parties entered negotiations with the United States Department of Energy (U.S. DOE) to finalize the project objectives, terms, and conditions, including the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. In August 2024, the project was awarded a $700 million grant from the U.S. DOE’s Grid Resilience and Innovation Partnerships (GRIP) program to further support its development and would reduce the overall total investment of the project. A portion of the GRIP funding is also allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants and effect of Presidential executive orders.

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

The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS), with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project (Warm Springs Power Pathway) will accelerate the development of transmission capacity, enabling new generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS communities by increasing resources available to the CTWS to support economic growth opportunities. See “Federal Grants” in the Laws and Regulations section of this Overview for further discussion over the impacts of Federal grants.

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. OnIn December 31, 2025, PGE filed its 2026-2028 Wildfire Mitigation Plan, which forecasts $47 to $50 million annually in operations and maintenance costs and an additional $70 to $84 million annually in capital investments, for the 2026-2028 period, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the threesix months ended MarchJune 31,30, 2026, PGE invested $14$38 million in capital projects related to wildfire mitigation and resiliency and utility asset management.

Virtual Power Plant (VPP)—PGE’s VPP is comprised of Distributed Energy Resources and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) charging solutions support grid reliability and increase portfolio flexibility and resource diversity. When coordinated through the Company’s Distributed Energy Resources Management Systems, Distributed Energy Resource and flexible loads support cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. As customer participation in PGE’s VPP grows, theircustomer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.

Distribution System Plan (DSP)—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. The OPUC Staff finalized their review of modifications to the current DSP guidelines in the fourth quarter of 2024 and PGE filed its next DSP in December 2024, fully compliant with the updated requirement. The DSP outlines distribution system assets, describes how the Company plans for new load, including distributed resources such as EVs and rooftop solar installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in demonstrating continual progress towards PGE’s clean energy goals. For further information on recovery of costs related to the DSP, see “Distribution System PlanDSP recovery mechanism” in the Regulatory Matters section of this Overview.

OnIn December 9, 2025, the OPUC accepted PGE's 2026-2028 TE Plan. The plan considers current and planned activities, along with forecasted EV loads for the 2026-2028 period, with expected capital expenditures to be approximately $11 million.

Trade Tariffs—Recently, theU.S. trade landscapepolicy shiftedand followingtariff measures continue to evolve through a Supreme Court ruling that struck down broad executive-ordered tariffs, leading the administration to pivot toward targeted actions under Section 122combination of the Trade Act of 1974existing and Sectionnewly 232implemented oftariff theprograms, Tradeongoing Expansion Act of 1962. While some universal tariffs were rolled back, significant duties have been imposed on steel, aluminum,litigation, and copperpotential derivatives,future withtrade a temporary rate reduction for specific electrical grid equipment through 2027.actions. These evolving measures continuemay to drive potential increases inincrease the cost of raw materials and equipment, disrupt global supply chains, and contribute to the volatility ofin capitalcommodity, capital, and credit markets. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increaseincrease, which could affect materials and supplies balances and elevate the cost ofincrease capital projects.projects costs. Similarly, pricesprocurement costs may rise and lead times may lengthen for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. WhileAlthough PGE’sPGE does not expect a material impact on its Canadian natural gas imports arefrom notrecent expectedCanada-related toactions, befuture impactedtrade byactions involving Canada could affect commodity markets, supply chains, or procurement costs. Recent tariff actions affecting particular countries and product categories, as well as the current statepossibility of additional trade tariffsmeasures, duehave toincreased theuncertainty imports being U.S.-Mexico-Canada Agreement compliant, theregarding future ofequipment tradecosts tariffand impactssupply on such imports is uncertain.availability. The Company is unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, as those effects could include project delays and cost increases, and present obstacles to PGE’s strategic plan execution. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.

OnIn 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 for projects associated with the terminated grants and does not expect the termination process to result in a material impact on the Company’s financial position and results of operations.

PGE has been awardedawarded, either as a direct recipient or subrecipient, five additional grants totaling approximately $252 million, either as a direct recipient or subrecipient.million. These grants remain in various stages of execution, with the largest being the Warm Springs Power Pathway. PGE continues to monitor these grants for potential modification or termination but has not received any formal notice of termination. To date, PGE has incurred only immaterial costs related to these grants. See “Transmission Upgrades” in the Investing in a Clean Energy Future section of this Overview for further discussion on the Warm Springs Power Pathway grant. The Company cannot predict the ultimate timing and success of securing funding from federal programs or predict the outcome of existing grants.

Inflation Reduction Act of 2022 (IRA)—The IRA was signed into law in August 2022. The United States Treasury and the Internal Revenue ServiceIRS 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.

On April 17,In 2024, PGE received approval from the OPUC to transfer PTCs generated in 2024 and 2025 PTCsand andto record any difference between the full value and the discounted value in a property balancing account. On April 15, 2026, PGE received approval from the OPUC to transfer PTCs generated in 2026 and 2027 PTCsand andto record any difference between the full value and the discounted value in a property balancing account.

PGE has entered into agreements to transfer 2024 through 2025 tax credits and transferred $3$12 million and $13 million, net of discounts, for cash proceeds in both the first threesix months of 2026 and 2025.2025, respectively. PGE transferred tax credits, net of discounts, of $179 million in 2025. TheFor the remainder of 2026, the Company has also entered into agreementsexpects to transfer 2026 through 2027 tax credits and forecasts the generationgenerate and transfer of approximately $32$25 million inof additional tax credits, net of discounts, in 2026.discounts.

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

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

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

RPS standards and related laws—In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable sources by dates certain and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers on or before January 1, 2030, although an exception in the law may extend this date five years for the output of Colstrip.Colstrip Units 3 and 4 coal-fired generating plant (Colstrip).

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

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

HB 3179—In response to increasing utility bills and concerns about affordability, the Oregon Legislature in 2025 passed HB 3179. Under the provisions of the legislation, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multiyearmulti-year rate plan (MRP) on a regular interval that is no less than three and no more than seven years long. UnderThe OPUC issued Order 26-191 on May 26, 2026, that began formal rulemaking in docket AR 677. In the proposed rules madeidentified effectivein MarchOrder 19,26-191, 2026,the eachOPUC electricis seeking to establish an initial filing schedule for MRPs, which calls for PGE to file its first MRP no earlier than May 1, 2029 and naturalno gaslater companythan is required to, at least annually by DecemberJuly 31, file2029. The OPUC has also opened a docket, AR 676, as a multi-phased rulemaking to establish the MRP framework with the OPUC, and make publicly available, a reporttarget onto any price adjustments thatcomplete the electric or natural gas company expects within the next twelve months. Such report, must identify all price adjustment requests that an electric or natural gas company has filed or reasonably knows or anticipates to file. Any increaseframework in residentialearly prices may not take effect from November 1 to March 31.2027.

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

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

PGE continues to evaluate each of these rules to assess the impactpotential itimpact, maywhich havecould be material, on the Company’s continuing investment in Colstrip,Colstrip. whichIf couldupheld, benot material.modified by the EPA, or the MATS compliance exemption is overturned, the 2024 MATS and GHG Rules would require compliance as early as 2027 and 2032, respectively. Compliance with the 2024 rules could require material upgrades at Colstrip with proposed compliance dates that may not be achievable or require the use of unproven technology, resulting in significant impacts to costs related to Colstrip. If upheld, or not modified by the EPA, the 2024 MATS and GHG Rules would require compliance as early as 2027 and 2032, respectively.

In addition to the EPA’s proposed rulemakings, several legal challenges have been filed regarding these rules and the revocation of the endangerment finding. In challenges to all three rules, at the EPA’s request, the courts have granted stays to allow new EPA leadership to reevaluate the rule. The endangerment finding revocation has not been stayed, and went into effect April 20, 20262026, while the litigationlegal ischallenges are pending. These challenges, or attempts by the federal government to withdraw or modify the regulations, if successful, could affect the applicability to PGE and Colstrip, specifically. Given the uncertainty surrounding applicability of these laws and regulations, PGE cannot reasonably estimate the impact to its results of operations, financial position, and cash flows, however, if the MATS Rule and GHG Rule are ultimately enforced, it could require material additional compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.

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

As of the date of this filing, theall OPUC proceeding remainsmilestones in the evidentiaryprocedural phase.schedule Writtenhave testimonyoccurred haswith beenbriefing submitted,complete and the OPUC ishaving continuingconducted tooral compileargument additionalwith filingsPGE and publicparties input.on July 23, 2026. Based on the current procedural schedule, a hearing is set for June 2026 and the OPUC is targeting an Order date of August 25, 2026. On July 23, 2026, FERC issued an order authorizing the reorganization into a holding company structure.

In January 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allowed PGE to seek recovery of incremental storm expenses through the previously filedauthorized emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC under Docket UM 2190 for emergency restoration costs related to the January storm. On March 18, 2026, PGE received the OPUC's final order for the storm recovery docket, which included a disallowance for some operating and maintenance costs of $1 million and application of an earnings test. The OPUC ordered the application of an earnings test at 20 basis points below the Company's 2024 allowed return on equity of 9.5% on the deferred storm costs. The application of the earnings test is expected to resultresulted in an additional $3 million reduction of the previously deferred amounts. After application of adjustments per the final order, PGE’s deferred balance as of March 31, 2026 iswas $44 million, including interest, which will beginbegan amortizing on April 1, 2026 over ana two year period. The deferred balance as of June 30, 2026 was $42 million.

Reliability Contingency Event (RCE)—Under the RCE mechanism, originally authorized by the OPUC to be effective through 2025, PGE was allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. Results of the PCAM are filed annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective in the following year. RCE costs incurred and deferred are included in each years' respective PCAM filing. PGE filed the results of the 2024 PCAM with the OPUC on July 1, 2025, in Docket UE 457, initiating a regulatory review process. Included in the filing, the Company requested an extension of the RCE mechanism for one year, through 2026. On March 18, 2026, the OPUC issued its final order in the 2024 RCE mechanism docket which resulted in the approval for recovery of $70 million in deferred costs, before consideration of interest, after determining that costs should be shared at a level of 90%, resulting in a reduction of $8 million to the recovery request. In addition, the OPUC disagreed with PGE's method of estimating the impacts related to wind generating resources in the day ahead forecasts of $2 million, resulting in a total reduction of $10 million in previously deferred costs. The OPUC also declined to extend the sunset date for the RCE mechanism.