PORTLAND GENERAL ELECTRIC CO /OR/ (POR) FY 2024 MD&A

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “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. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:

•governmental policies, legislative action, 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 ODEQ 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

38

Table of Contents

plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs, and capital investments, energy trading activities, 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;

•inflation and volatility in interest rates;

•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 rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered ESSs or the adoption of community choice aggregation;

•the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 7. and Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;

•natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability;

•unseasonable or 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 costs;

•ignitions caused by PGE assets or PGE’s ability to effectively implement a PSPS and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems are 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;

•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, which 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

39

Table of Contents

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 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, and compliance with, 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, 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;

•physical attacks upon Company employees;

•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 similar to that experienced by other employers and industries during the COVID-19 pandemic;

•new federal, state, and local laws that could have adverse effects on operating results;

•failure to achieve the Company’s GHG emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively respond to legislative requirements concerning GHG emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation;

•social attitudes regarding the electric utility and power industries;

•political and economic conditions;

•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,

40

Table of Contents

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;

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

•acts of war, terrorism, or civil disruption.

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

Overview

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

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

Company Strategy

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 being a clean energy leader 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 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.

41

Table of Contents

Climate Change

State-mandated GHG emissions reduction targets—In June 2021, the Oregon legislature passed HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and ESSs in the State. A number of provisions in the bill align with PGE’s strategic direction, and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG emissions reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the “Laws and Regulations” section of this Overview.

Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 230 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 municipality customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided PPAs for renewable resources and customers who enroll in Phase II can receive energy either from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions.

As of December 31, 2024, the Green Future Impact Program has an approved capacity of 750 MW nameplate, of which 482 MW have been subscribed. Through this voluntary program, the Company seeks to support the customers’ clean energy acceleration.

The Climate Pledge—In 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report GHG emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets.

Severe weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. 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. Beginning January 13, 2024, the Company’s service territory encountered the first of a series of severe winter weather events, 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 events, see “Declared States of Emergency” and “RCE” within the Regulatory Matters section of this Overview. The increase and impact of severe 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 meet the

42

Table of Contents

2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was filed in connection with, the Company’s 2023 Integrated Resource Plan (IRP). PGE filed its first combined IRP and CEP with the OPUC in March 2023. 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 then several times in subsequent comments in the CEP and IRP docket with the OPUC (LC 80). PGE currently estimates a total resource need of approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to make continual progress towards meeting the Company’s clean energy targets. Through the 2021 All-Source RFP, PGE procured 311 MW of wind resources and 475 MW of capacity, leaving a remaining need to procure approximately 2,700 to 3,700 MW.

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. However, the OPUC declined to acknowledge the CEP, directing the Company to provide additional forecast of its emission reductions based on new analysis in the CEP/IRP Update to be filed in April 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP.

2021 and 2023 All-Source RFPs

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 Wind Development—The 311 MW wind energy facility is part of the larger Clearwater Wind Development in Eastern Montana. PGE owns 208 MW of production capacity of the facility. 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. The Company owned portion of the facility was placed in-service during the first quarter of 2024. As of December 31, 2024, the Company has recorded $414 million in Electric Utility Plant, net, including Allowance for funds used during construction (AFUDC).

•Seaside Grid—The 200 MW Battery Energy Storage System (BESS) facility, located in Portland, Oregon has an estimated commercial operation date of June 30, 2025 and will be owned by PGE. As of December 31, 2024, the Company has recorded $225 million, including AFUDC, in construction work-in-progress (CWIP) for the Seaside Grid.

•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. As of December 31, 2024, the Company has recorded $156 million in Electric Utility Plant, net, including AFUDC.

•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 the Clearwater Wind Development 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 All-Source RFP and future RFPs.

All BESS projects will be directly interconnected to PGE’s transmission and distribution system. In the event emissions are associated with energy obtained to charge the BESS, they are accounted for when they are emitted from the generating facility. As such, BESS projects do not add incremental emissions to the grid, and therefore, are considered non-emitting dispatchable capacity resources. The BESS facilities qualify for ITCs. The agreements related to the Clearwater Wind Development qualify for PTCs and are eligible under Oregon’s RPS. The agreements will be subject to prudency review by the OPUC.

43

Table of Contents

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. On October 7, 2024, the Company filed notification that one project on the final shortlist was no longer available.

PGE constructed the final short list to provide optionality and address the Company’s future capacity need. The Company ranked the final shortlist in two groups, prioritized based on performance in the RFP price scoring evaluation, representing the optimal intersection of value to customers at the least-cost and the least-risk. These two groups together represented the final shortlist of projects recommended for regulatory acknowledgement. On November 19, 2024, the OPUC acknowledged, with conditions, PGE’s final shortlist of resources as follows:

•Group A, as shown below, consisted of three bids that are top performing and PGE expected to enter commercial negotiation for all of these projects. Group A included 375 megawatts (MW) nameplate of renewable resources and 400 MW nameplate of battery storage; and

•Group B, as shown below, consisted of five bids, all of which represent capacity options via BESS facilities. These projects are also high performing and PGE may enter commercial negotiations with some or all of these projects, allowing flexibility to address any remaining capacity need. Group B includes 885 MW nameplate of battery storage.

The proposals for renewable resources provide various combinations of solar and battery storage options that include PPAs along with Company-owned resources via Build Transfer Agreements (BTA). The proposals for non-emitting dispatchable capacity resources provide battery storage options that include PPAs along with Company-owned resources via BTAs.

(1) MW values do not include nameplate capacity of paired energy storage of 250 MW for project 1 and 125 MW for project 3.

(2) Hybrid commercial structure includes a PPA portion and a Company-owned portion of project resources.

On December 12, 2024, Project 1 in Group A notified PGE that it was withdrawing from commercial negotiations. PGE continues to negotiate with the remaining Group A projects and aims to finalize contracts over the course of 2025.

44

Table of Contents

RFP final shortlist projects were evaluated and selected based on conditions as of the 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), and legislative uncertainty.

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

Both the 2021 and 2023 RFPs were the subject of regulatory and legal challenges initiated by NewSun Energy LLC, focused on the scoring methodology of the RFPs and OPUC acknowledgement of the final shortlists. However, two of NewSun’s challenges to the 2021 RFP were dismissed as moot in recent court decisions. PGE has joined the proceedings as an intervenor, and the remaining challenges are in various stages of litigation or regulatory review. PGE cannot predict the outcome of these proceedings or potential impact, if any, on its 2021 and 2023 All-Source RFP process.

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. PGE plans to file the draft 2025 All-Source RFP in the first half of 2025.

Transmission Upgrades

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

On May 28, 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 have entered negotiations with the 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. On August 6, 2024, the project was awarded a $700 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships program to further support its development and would reduce the overall total investment of the project.

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, access to enhanced wholesale markets, and to 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 United States Department of Energy (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 carbon-free 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 CTWS to support adaptation and response strategies. See “Federal Grants” in this Overview for further discussion.

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:

45

Table of Contents

•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 $53 to $57 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 reducing the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. During 2024, PGE invested $40 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2024 WMP. See the “Wildfire Mitigation” section in Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data, for further discussion.

•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. Customer participation in the VPP helps avoid customer service interruptions and reduces exposure to scarcity pricing in energy markets. On July 8, 2024, customer actions, orchestrated through the VPP, reduced load by more than 100 MW. As their participation in PGE’s VPP grows, customer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.

•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 Solar Photovoltaic installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in meeting PGE’s clean energy goals.

Electrify the economy—To help Oregon reach its decarbonization goals, PGE is working to build a safe, reliable, and affordable, economy-wide, clean energy future. The Company is committed to increasing electrification of buildings and supporting vehicle electrification for customers, as well as its own vehicle fleet.

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 supporting customers’ transitions to TE.

In 2021, the Oregon legislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support TE.

In 2023, PGE’s second TE plan was filed and accepted by the OPUC in October 2023. The TE plan considers current and planned activities, along with forecasted EV loads and potential system impacts. The 2023 TE plan represents a continuation of the approach and programmatic efforts found within PGE’s 2019 TE plan while also outlining the Company’s current strategy to integrate TE into utility business in order to plan, service, and manage EV load.

46

Table of Contents

In the 2023 to 2025 period covered by the 2023 TE plan, capital expenditures are expected to be approximately

$14 million.

Businesses and families continue to turn to electricity to serve their home and workplace needs. PGE continues to pursue advanced technologies to enhance the grid, pursue distributed generation and 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

Executive Orders—A series of Presidential executive orders were recently issued that relate to changes in energy and environmental policies. These orders aim to accelerate fossil fuel development, reverse climate change and environmental justice initiatives, and halt wind farm construction on federal lands and waters. Key actions include potential tariffs on natural gas imports, reviewing agency actions that burden domestic energy resources, pausing disbursement of federal funding, streamlining permitting processes, and declaring a national emergency to expedite energy projects, particularly on the West Coast.

PGE is analyzing these executive orders to understand their potential impact on grant funding, which include Diversity, Equity, and Inclusion and Community Benefits Plans, and potential supply tariffs, including natural gas used as fuel that is imported from Canada. PGE plans to collaborate with industry groups to engage with the administration when appropriate, while closely monitoring the implementation and legal challenges arising from these executive orders. The Company is unable to predict the outcome of executive orders or the impact they may have on its financial position, results of operations, or cash flows.

Federal Grants—In November 2021, the $1.2 trillion IIJA, which includes approximately $550 billion of new federal spending, was signed into law. PGE continues to pursue multiple areas under the IIJA, and other state and federal programs, for potential grant funding 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, hydrogen production, and regional transmission capacity constraints.

As of December 31, 2024, PGE has been associated with the submission of 42 grant applications as the Prime or Sub-recipient/Supporter and has been awarded 10 grants totaling $315 million, including the following:

•U.S. DOE Bethel-Round Butte Transmission Line Upgrade—The U.S. DOE selected the CTWS, with PGE as a subrecipient under the grant, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The US DOE and CTWS, as the prime recipient, entered into a Cooperative Agreement on August 13, 2024. Subsequently CTWS entered into a subrecipient agreement with PGE on December 1, 2024. These agreements memorialize the funding and scope for the multiyear line upgrade. See “Transmission Upgrades” in this Overview for further discussion.

•U.S. DOE Grid Edge Devices—The U.S. DOE selected and subsequently entered into an agreement on October 1, 2024 with PGE leading a consortium for a $50 million grant for the Grid Edge Devices project. The project will enable real-time information at each meter to improve the visibility of the electrical system to grid operators, providing detection of potential operational problems and shorten outage times, ultimately helping to anticipate and mitigate the impacts of extreme weather on grid resiliency.

As of December 31, 2024, PGE has incurred an immaterial amount of costs associated with its Federal grants, and continues to assess the impacts of these federal grants on the Company’s financial position and results of operations, including the effects of the Presidential executive orders noted above. Although PGE continues to apply for additional grants, the Company cannot predict the ultimate timing and success of securing funding from federal programs.

47

Table of Contents

Inflation Reduction Act of 2022—The Inflation Reduction Act of 2022 (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 to 2025 tax credits and transferred $112 million and $24 million, net of discounts, for cash proceeds in 2024 and 2023, respectively.

The Company believes the tax incentives in the IRA provide additional investment opportunities for PGE and provide benefits to customers. Increased capital expenditures in such investment opportunities would likely result in additional financing needs through debt and equity instruments. PGE continues to monitor for potential impacts to its business due to executive orders that may change tax incentives under IRA programs. See “Executive Orders” in this Overview section, for further information.

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 create a plan that is in the public interest, demonstrate continual progress toward meeting the targets, and take actions as soon as practicable that facilitate rapid reduction of GHG emissions. 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 the continuation of its ownership in Colstrip. See Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” for information regarding legal 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 “Investing in a Clean Energy Future” in this Overview for information regarding development in eastern Montana.

48

Table of Contents

Other provisions of SB 1547:

•establish RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040, for the percentage of electricity that must come from renewable sources;

•limit the life of RECs generated from facilities that become operational after 2022 to five years, but continue unlimited lifespan for all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and

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

PGE believes it is on track to meet the 2025 RPS threshold. For a more comprehensive review of Environmental Matters, see “Environmental Matters” in Item 1.—Business.

EPA Regulations for Electric Generating Facilities—On April 25, 2024, the United States Environmental Protection Agency (EPA) released final regulations pertaining to electric generation facilities. The regulations include:

•GHG regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA). The rule finalizes: i) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric units; and ii) revisions to existing performance standards for new, reconstructed, or heavily modified fossil fuel-fired stationary combustion turbine electric generating units.

•Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the ELG Rule), which applies to wastewater discharges from coal-based generating units and establishes pollution control requirements, building upon the 2015 and 2020 ELG Rules. The rule includes a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034.

•Updated Mercury and Air Toxics Standards, pursuant to section 112 of the CAA, which sets emissions limits for filterable particulate matter for coal-based generating units. The rule reduces those limits from the standards that were originally set in 2012.

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. PGE notes that a substantial number of legal challenges have been filed regarding these rules. 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. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.

In addition, the regulations included Disposal of Coal Combustion Residuals (CCR) from Electric Utilities – Legacy CCR Surface Impoundments. This rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants, and CCR management units at active and inactive power plants. PGE has assessed the potential impact of the CCR regulation changes and believes it will not have a material impact on the Company’s current Asset Retirement Obligations.

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.

49

Table of Contents

General Rate Case—On December 20, 2024, the OPUC issued a Final order (Order 24-454) in the 2025 GRC requested by PGE on February 29, 2024 that calls for the following:

•capital structure of 50% debt and 50% equity;

•ROE of 9.34%;

•cost of capital of 6.991%; and

•rate base of $6.8 billion.

The Final order results in an annual revenue requirement increase of $100 million, as required by the OPUC. The changes in revenue requirement from PGE’s originally filed 2025 GRC to the Final order consist of the following (in millions):

(1) Excluding $17 million related to NVPC and other Supplemental filings.

(2) Consists of adjustments related to load, capital forecast updates, ROE adjustments, and other revenue requirement items updated during the rate review process.

(3) Reduction relates primarily to: i) the Final order’s method of applying inflation rates to 2023 actual balances for general wages and salaries and Generation O&M, and ii) amounts related to incentives and stock compensation.

(4) The OPUC’s Final order authorized an ROE of 9.34%. At the time of Closing briefs, PGE’s adjusted requested ROE was 9.5%, which was also PGE’s previously approved ROE.

(5) The Final order and related revenue requirement reflects the following items: i) an adjustment for actual plant placed in-service compared to amounts forecasted in Closing briefs with cost recovery expected to be pursued in future regulatory proceedings and, ii) other immaterial items removed from rate base.

(6) Per the OPUC's Final order, Clearwater is to be excluded from this rate case as prudency is being determined in a separate proceeding, OPUC Docket UE 427. The target rate effective date for Clearwater in UE 427 has been delayed to March 1, 2025. This adjustment reflects the removal of the revenue requirement of Clearwater from rate base, net of NVPC benefits. Under the RAC, PGE will continue to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater is reflected in customer prices.

(7) Primarily comprised of reductions of certain working capital and inventory items and other revenue credit items.

Other key items in the 2025 GRC Final order include:

•Invitation for PGE to file for a balanced cost-recovery tracker mechanism to incorporate the approximately $375 million Seaside Grid BESS system into rates under an expedited regulatory review; and

•Acceptance of PGE's rate base methodology in this GRC, which, after adjustments, resulted in $6.8 billion and included the following key elements:

◦A reduction of $402 million related to Clearwater to reflect the delay of the target rate effective date to March 1, 2025 and allow for further regulatory review;

◦A reduction of $112 million to reflect the planned sale of PTCs and inclusion of ITCs as a reduction of rate base and expected to be amortized as a refund to customers over the life of the related battery assets;

50

Table of Contents

◦A reduction of $69 million primarily related to actual plant placed in-service compared to amounts forecasted in Closing briefs and cost recovery expected to be pursued in future regulatory proceedings; and

◦A reduction of $61 million for amounts removed from rate base related to working capital, materials and supplies, and fuel.

All items included within NVPC have been resolved in OPUC Docket UE 436 and reflect the treatment of Clearwater in the GRC Final order. New customer prices, as approved by the OPUC, became effective January 1, 2025.

More information about the 2025 GRC (OPUC Docket UE 435) and NVPC (OPUC Docket UE 436) is available on the OPUC website at www.oregon.gov/puc.

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

Beginning January 13, 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. Along with over a dozen mutual assistance crews, PGE repaired damage and restored power to over 500,000 customers throughout the storm and the days that followed. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to seek recovery of incremental storm expenses through the previously filed emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC under Docket UM 2190 for emergency restoration costs related to the January storm. As of December 31, 2024, PGE had deferred $46 million, including interest, as a regulatory asset for costs associated with repairing damage to transmission and distribution systems and restoring power to customers.

As of September 30, 2024, PGE's forecasted preliminary regulated return on equity for the full-year 2024 exceeded the OPUC's authorized rate of return. Consequently, under the earnings test the Company's third quarter results included a $17 million decrease to the deferral and a corresponding charge to earnings. However, 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. As a result, the $17 million reduction recorded in the third quarter has been reversed as of December 31, 2024.

PGE believes that the full amount of the deferral is probable of recovery and plans to file with the OPUC in mid-2025, seeking recovery to begin during 2026. The OPUC has significant discretion in making the final determination of recovery based on its determination of prudency and interpretation of the earnings test application, either of which could result in all or a portion of the deferral being disallowed. Any disallowance would be a charge to earnings, which could be material to the Company’s financial condition, results of operations, or cash flows. For further information, see “January 2024 storm and damage” in Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

RCE—Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. As of December 31, 2024, PGE’s deferred balance related to RCEs was $90 million, which includes costs from multiple qualified RCEs during the year, the most significant of which was related to the January storm event. PGE files the results of the PCAM 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

51

Table of Contents

OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective January 1 of the following year. RCE costs incurred in 2024 will be included in the PCAM for 2024, which the Company expects to file no later than July 1, 2025. PGE believes the deferred amounts as of December 31, 2024 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.

Power costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2024 AUT included a final increase in power costs for 2024, and a corresponding increase in annual revenue requirement of $216 million from 2023 levels, which were reflected in customer prices effective January 1, 2024. The 2025 AUT contains a $72 million increase in NVPC and has been included in customer prices beginning January 1, 2025. For more information regarding the PCAM, see “Power operations” within this Overview section of Item 7.

Portland Harbor Environmental Remediation Account (PHERA) mechanism—The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of December 31, 2024, significant uncertainties still remained concerning the precise requirements 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. 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 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Decoupling—The decoupling mechanism, previously authorized by the OPUC through 2022, was intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provided for collection from (or refund to) customers if weather-adjusted use per customer was less (or more) than that projected in the Company’s most recent GRC.

In the 2022 GRC, parties reached an agreement that eliminated PGE’s decoupling mechanism upon the effective date of new customer prices that resulted in May 2022. Pursuant to the 2022 GRC Order, the OPUC adopted the agreement such that deferrals would not occur after 2022, although amortization of then previously recorded deferrals was to continue as scheduled until collected or refunded in future customer prices. For the year ended December 31, 2022, with OPUC approval, PGE collected $5 million in customer prices over a one-year period that began January 1, 2024.

52

Table of Contents

In the 2024 GRC filing, the Company included a concept proposal that would have led to resuming decoupling, with certain modifications. PGE then made a tariff filing that proposed weather-normalized decoupling, although at a public meeting in June 2024, the OPUC permanently suspended PGE’s proposed tariff, effectively denying the proposal.

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 GRC. During 2024, the Company did not submit a request for recovery of any renewable resources under the RAC. In 2023, the Company filed for Clearwater, which went into service January 5, 2024. Per the OPUC's Final order in the 2025 GRC, Clearwater was excluded from the rate case as prudency is being determined in a separate proceeding, OPUC Docket UE 427. The target rate effective date for price changes for Clearwater in UE 427 is March 1, 2025. Under the RAC, PGE will continue to defer the revenue requirement, net of NVPC benefits, from the in-service date in January 2024 until Clearwater is reflected in customer prices. As of December 31, 2024, the Company has recorded a $40 million regulatory liability, which represents the deferred revenue requirement that PGE believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC. For further information, see “Alternative Revenue Programs” in Note 2, Summary of Significant Accounting Policies and “Clearwater RAC” in Note 7, Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

New Large Load—In October 2023, in Docket UE 416, the OPUC directed a docket be opened to investigate new load connection costs and in December 2023, the OPUC established Docket UE 430 for that purpose. Following a lengthy regulatory process, on December 20, 2024, PGE filed Advice No. 24-38 with the OPUC. This filing introduces 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 by managing capacity requests over one MW; 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.

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, PGE purchases natural gas in the United States and Canada and sells excess gas back into the wholesale market. The Company also performs portfolio management and wholesale market sales services for third parties in the region and purchases and sells environmental credits in the wholesale marketplace.

PGE participates in the western EIM, which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. The Company recently signed the implementation agreement to join the EDAM, to build on the success of the western EIM and help provide PGE and its customers access to more affordable, reliable and clean energy. Utilities that participate in the EDAM, expected to begin operating in 2026, will bid their anticipated energy demand and generating resources into the market a day ahead of expected usage. The EDAM will then optimize generation resources and the energy needed for all market participants, allowing them to receive the least costly and cleanest energy to meet their energy needs. The EDAM is expected to build upon existing technology and systems the Company has deployed and leverage PGE’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 common market.

In its ongoing effort to benefit retail and wholesale customers, in 2023, PGE joined the Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP), which has announced that it is on a path to begin binding operation in 2027. The WRAP represents a regional framework to more

53

Table of Contents

effectively address resource adequacy, enhance reliability, integrate clean energy, and manage costs through resource diversification and capacity sharing across a wide geographic footprint and broad pool of participants across the west.

PGE generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Summer peak deliveries have continued to exceed those of the winter months for nearly ten years, generally resulting from growing air conditioning demand and the trend toward a warmer overall climate. In August 2023, demand reached a new all-time high, surpassing the previous mark, which was set in summer 2021. Historically, PGE had experienced its highest average megawatt deliveries and retail energy sales during the winter heating season and recorded its current winter peak load in December 2022. For further information regarding seasonal fluctuations, see “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to enhance the availability of supply chain-constrained items that are needed to serve new and existing customers, such as securing inventory of critical materials to improve reliability, reserving manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. PGE’s materials and supplies forecasting process is designed to secure materials availability as well as help mitigate cost increases through long-term agreements, supplier engagement, and expanding the supply base.

Customers and demand—The following tables present total energy deliveries and the average number of retail customers by type for 2024 and 2023.

54

Table of Contents

In 2024, retail energy deliveries increased 1.3% from 2023, with increases in demand from industrial customers outweighing the decreases seen in the residential and commercial classes. The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Compared to the prior year, weather had a negative impact on deliveries. The first quarter of 2023 was unseasonably cold, whereas the same period of 2024 was mild, as was the fourth quarter of 2024. Normally, the first and fourth quarters have the highest demand for heating.

Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 2.8% lower in 2024 than 2023, due to a 4.4% decrease in average usage per customer, which resulted largely from mild temperatures, and was partially offset by a 1.7% increase in the average number of customers. PGE has seen the number of rooftop solar installations increase in its service territory over the past few years, which continues to reduce the average usage per customer.

Commercial energy deliveries decreased 2.1% from the prior year due in large part to the mild temperatures in 2024. While COVID-19 related recovery has largely occurred, continued impacts of programmatic energy efficiency and uncertainty in economic conditions have tempered commercial growth in 2024.

Industrial energy deliveries increased 10.3% in 2024 due to continued strength in the high-tech manufacturing and digital service sector. Several large customers experienced continued growth in 2024 and new data center facilities came online.

Total heating degree-days, an indication of electricity use for heating, declined 5% in 2024 from 2023 in total, and was 9% below the 15-year moving average. In 2024, heating degree-days were lower in each quarter of the year, except for the fourth quarter, which was only slightly higher. The fourth quarter, which is normally a high heating demand period, in 2023, was among the warmest ever recorded. Correspondingly, cooling degree-days, a similar indication of the extent to which customers were likely to have used electricity for cooling, exceeded the 15-year average by 20%, although were 16% below the 2023 total, which was 43% above average, illustrating that the two most recent summer seasons have been exceedingly warm compared to historical averages.

The following table presents the number of heating and cooling degree-days in 2024 and 2023, along with the current 15-year averages, reflecting the influence that weather had on comparative energy deliveries.

On a weather-adjusted basis, total retail deliveries increased 3.1% from 2023. The increase was driven by a 10.7% growth in industrial deliveries, and a 0.5% increase in weather-adjusted deliveries to residential customers, as average use per customer has declined from the highs seen during the COVID-19 pandemic, partially offset by a 0.9% decline in commercial energy deliveries. The Company projects that retail energy deliveries for 2025 will be between 2.5% and 3.5% above 2024 weather-adjusted levels, reflecting continued growth in industrial deliveries.

ESSs supplied Direct Access customers with energy representing 11% of PGE’s total retail energy deliveries during 2024 and 2023. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 12% of the Company’s total retail energy deliveries for 2024. With the adoption of the

55

Table of Contents

New Large Load Direct Access program in 2020, as much as 17% of the Company’s 2024 energy deliveries could have been supplied by ESSs.

Power operations—PGE utilizes a combination of its own generating and energy storage resources and wholesale market transactions to meet the energy needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period and impacts NVPC and income from operations.

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

(1)Plant availability represents the percentage of the year plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.

(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.

(3)Plant availability reflects Colstrip, which PGE does not operate.

(4)Plant availability includes Wheatridge Renewable Energy Facility and Clearwater, which PGE does not operate.

Energy received from PGE-owned and jointly-owned thermal plants in 2024 compared to 2023 decreased by 3%. This decrease is primarily driven by economic dispatch decisions. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from all hydroelectric sources, both PGE-owned generation and purchased, increased 39% in 2024 compared to 2023 primarily due to the addition of capacity under two purchased hydro contracts in 2024. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 45% while energy generated by the Company-owned facilities increased 11% in 2024. Energy expected to be received from hydroelectric resources in 2024 was projected in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. For further detail on regional hydro results, see “Purchased power and fuel” in the Results of Operations section in this Item 7.

Energy received from PGE-owned wind resources and under contracts increased 56% in 2024 compared to 2023 primarily due to the addition of Clearwater in 2024. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available.

Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC, which is reset annually by means of the AUT filings) and actual NVPC for the

56

Table of Contents

year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2024 and 2023:

•For 2024, actual NVPC was below baseline NVPC by $78 million, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE was below 10.5%, there is 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.

•For 2023, actual NVPC was above baseline NVPC by $5 million, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2023.

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 2024 RCE, see Note 7, Regulatory Assets and Liabilities in the Notes to Condensed Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

57

Table of Contents

Results of Operations

The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations.

The results of operations are as follows for the years presented (dollars in millions):

* Includes an allowance for borrowed funds used during construction of $15 million in 2024 and $13 million in 2023.

2024 Compared to 2023

Net income for 2024 increased $85 million from 2023, as higher Purchased power and fuel costs were more than offset by increases in Retail revenues authorized by the OPUC in the AUT in anticipation of higher NVPC. In 2023, the opposite was true as higher Purchased power and fuel expenses exceeded the corresponding increases in prices resulting from the AUT. Retail revenues also increased due to an overall increase in deliveries, although that demand impact was somewhat offset by the lower average price result of the relative mix of deliveries among customer classes. Temperature variations in 2024 had a lesser impact on demand than what was experienced in 2023, although total system load increased 12% year over year, as the industrial class continued to show strength, and wholesale sales continue to increase. The Company saw a 13% increase in the average variable power cost per MWh driven primarily by higher physical power and natural gas prices due in part to severe weather events in the first quarter of 2024. Wholesale revenues increased during 2024, driven by a 40% increase in deliveries, which contributed to reducing NVPC. Generation, transmission and distribution expenses were up primarily due to vegetation management and major maintenance activities. The increase in Administrative and general expense reflects increases in various categories including compensation and benefits, customer related items, and regulatory and professional services 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 anticipated and largely offset in net income by increased revenues.

58

Table of Contents

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

Total retail revenues—The following items contributed to the increase in Total retail revenues for the year ended December 31, 2024 compared to the year ended December 31, 2023 (dollars in millions):

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

In 2024, a $140 million, or 33%, increase from 2023 in wholesale revenues occurred as sales volumes increased 40%, which resulted in a $166 million increase, and the Company sold $26 million more environmental credits in 2024 than in the prior year. Partly offsetting the increase was a 27% decrease in average prices received when the Company sold power into the wholesale market. Elevated sales prices existed during 2023 and resulted from several factors, including reduced hydro generation in the region, the economic recovery, strong demand, and ongoing

59

Table of Contents

capacity limitations in the region. In 2024, milder weather and lower natural gas prices contributed to bring average sales prices down from the levels seen in 2023.

Other operating revenues increased $9 million, or 16%, in 2024 from 2023, primarily as a result of the amortization of deferrals related to the transmission rate case that are offset in Retail revenues.

Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts.

The following items contributed to the change in Purchased power and fuel for the year ended December 31, 2024 compared to the year ended December 31, 2023 (dollars in millions, except for average variable power cost per MWh):

For the year ended December 31, 2024, the $121 million increase related to the change in average variable power cost per MWh was primarily driven by a 7% increase in the average cost for purchased power due largely to fixed capacity fees for hydro contracts in 2024, and a 12% increase in the average cost for the Company’s own generation, driven mainly by price risk management activity. The $194 million increase related to total system load was primarily due to the change in mix of sources of energy with purchased power increasing 22% resulting in a $176 million increase, and a 5% increase in energy obtained from PGE’s own generation resulting in a $18 million increase.

60

Table of Contents

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

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

The following table presents the forecasted April-to-September 2025 and actual April-to-September 2024 and 2023 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.

61

Table of Contents

Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $87 million in 2024 compared with 2023. The increase attributable to changes in Purchased power and fuel expense was the result of a 13% increase in the average variable power cost per MWh and a 12% increase in total system load. This was partially offset by an increase in wholesale revenues driven by a 40% increase in the volume of wholesale energy deliveries and a 5% lower average price per MWh sold.

The following items contributed to the increase in actual NVPC for the year ended December 31, 2024 compared to the year ended December 31, 2023 (in millions):

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

Generation, transmission and distribution expense increased $62 million or 17% for the year ended December 31, 2024 compared to the year ended December 31, 2023, with the change attributed largely to the following items (in millions):

In the table above, $24 million related to vegetation management, $5 million related to wildfire mitigation, and $4 million related to major maintenance have been offset through customer prices or specific regulatory mechanisms.

Administrative and other expense increased $62 million, 18%, for the year ended December 31, 2024 compared to the year ended December 31, 2023 due largely to the following items (in millions):

62

Table of Contents

In addition to the $4 million related to amortization of COVID-19 bad debt expense deferral, another $2 million increase is due to other regulatory-related programs that have been offset through customer prices or specific regulatory mechanisms.

Depreciation and amortization expense increased $38 million or 8% for the year ended December 31, 2024 compared to year ended December 31, 2023, with the change largely resulting from the following items (in millions):

Taxes other than income taxes expense increased $11 million, or 7%, in 2024 compared with 2023, primarily due to higher franchise fees and property tax expenses.

Interest expense increased $38 million, or 22%, in 2024 compared with 2023 driven by higher average balances of outstanding debt.

Other income, net decreased $1 million, or 2%, in 2024 compared to 2023. The decrease was primarily attributable to $2 million in lower regulatory interest income and $2 million in lower pension non-service costs offset by $4 million higher AFUDC equity income driven by higher construction work-in progress balances in 2024.

Income tax expense decreased $8 million, or 18%, in 2024 compared to 2023 primarily driven by increased PTC benefits partially offset by higher pre-tax income as compared to the prior year.

2023 Compared to 2022

For a comparison of the Company’s results of operations for the fiscal year ended December 31, 2023 to the year ended December 31, 2022, see Item 7.—” Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 20, 2024.

Liquidity and Capital Resources

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

63

Table of Contents

Capital Requirements

The following table presents actual capital expenditures and debt maturities for 2024 and projected capital expenditures and future debt maturities for 2025 through 2029 (in millions, excluding AFUDC):

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

(2) Amounts subsequent to 2024 are estimates as of the date of this report and may be affected by economic conditions, including but not limited to, impacts of inflation, changes to the cost of materials and labor, and financing costs.

During 2024, PGE funded its capital expenditures through a combination of cash from operations in the amount of $778 million, proceeds from the issuance of FMBs in the total amount of $450 million, net proceeds from the issuance of shares pursuant to the at-the-market offering program of $346 million, and $170 million in net proceeds from a term loan. Capital expenditures in 2025 are expected to be approximately $1.3 billion. PGE plans to fund the 2025 capital expenditures with cash from operations during 2025, which is expected to range from $900 million to $1 billion, the issuance of debt securities of up to $550 million, issuances of shares pursuant to the at-the-market offering program, and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt, equity, and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Liquidity

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

64

Table of Contents

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

2024 Compared to 2023

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 2024 compared to 2023 (dollars in millions):

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

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 2025 will range from $550 million to $575 million. Combined with all other sources, cash provided by operations in 2025 is estimated to range from $900 million to $1 billion.

Cash provided by operations includes the recovery in customer prices of cash charges related to various long-term contractual obligations such as interest on long-term debt and purchased power and fuel contracts. PGE’s anticipated employer contributions for its defined benefit pension plan and other postretirement plans is $24 million in 2025, $25 million in 2026, $22 million in 2027, $19 million in 2028, and $18 million in 2029. Contributions are expected to be covered by cash provided by operations. For additional information regarding contractual obligations, see Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation, transmission, and distribution

65

Table of Contents

facilities. The $61 million decrease in net cash used in investing activities in 2024 compared with 2023 is primarily due to Clearwater, which was placed in service in January 2024, offset by capital expenditures related to BESS projects and other new construction and improvements to PGE’s distribution, transmission, and generation facilities.

The Company plans for $1.3 billion of capital expenditures in 2025 related to upgrades to and replacement of generation, transmission, and distribution infrastructure as well as costs related to BESS projects. PGE plans to fund the 2025 capital expenditures with cash from operations during 2025, as discussed above, as well as with the issuance of debt, issuances of shares pursuant to the at-the-market offering program, and short-term debt as necessary. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2024, cash provided by financing activities was primarily the result of the funding of $450 million in FMBs, $346 million in proceeds from the issuance of common stock pursuant to at-the-market offering programs, and $220 million in proceeds from the term loan. This was partially offset by payments of dividends in the amount of $200 million and $130 million of long-term debt.

2023 Compared to 2022

For a comparison of liquidity and capital resources and the Company’s cash flow activities for the fiscal year ended December 31, 2023 and 2022, see Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC on February 20, 2024.

Credit Ratings and Debt Covenants

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

In June 2024, Moody’s revised the Company’s outlook from Stable to Negative. This change is not expected to have a material impact on the Company’s liquidity or collateral obligations.

In the event Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to higher fees on its revolving credit facility. The Company could also be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE’s consolidated balance sheets, while any letters of credit issued are not reflected in the Company’s consolidated balance sheets.

As of December 31, 2024, PGE had posted $143 million of collateral with these counterparties, consisting of $125 million in cash and $18 million in bank letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2024, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $92 million and increases to $94 million by December 31, 2025 and decreases to $44 million by December 31, 2026. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade as of

66

Table of Contents

December 31, 2024 is $187 million and decreases to $185 million by December 31, 2025 and $102 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 securing the bonds. PGE estimates that on December 31, 2024, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $677 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt to total capital ratio). As of December 31, 2024, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 55.1%.

Debt and Equity Financings

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

Short-term Debt—Pursuant to an order issued by the FERC on January 18, 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 December 31, 2024 (in millions):

(1)Scheduled to expire in September 2029. PGE has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay outstanding commercial paper. As of December 31, 2024, PGE had no of commercial paper outstanding, therefore, the elected available credit capacity is $750 million.

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

As of December 31, 2024, PGE had a $750 million unsecured revolving credit facility scheduled to expire in September 2029. 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

67

Table of Contents

cash flows and provides a primary source of liquidity. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may borrow for one, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2024, PGE had no commercial paper outstanding.

PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets.

Under the revolving credit facility, as of December 31, 2024, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2024, the aggregate unused available credit capacity under the revolving credit facility was $750 million.

In addition, PGE has four letter of credit facilities under which the Company has total capacity of $320 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, which are considered off-balance sheet arrangements, letters of credit for a total of $85 million were outstanding as of December 31, 2024. PGE works to optimize its use of its letter of credit facility to manage energy trading margin.

Long-term Debt—During 2024, PGE issued and funded a total of $670 million of Long-term Debt and repaid a total of $130 million.

On February 22, 2024, PGE entered into a Bond Purchase Agreement related to the sale of $450 million in FMBs. The Bonds were issued and funded in full on February 22, 2024 and consist of:

•a series, due in 2029, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 5.15%;

•a series, due in 2034, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 5.36%; and

•a series, due in 2054, in the amount of $250 million that will bear interest from its issuance date at an annual rate of 5.73%.

On November 14, 2024, PGE obtained a 366-day term loan from lenders in the aggregate principal of $300 million under a 366-Day Bridge Credit Agreement. Pursuant to the Agreement, on November 14, 2024, PGE drew a loan from the Lenders in the aggregate principal of $220 million, utilizing a portion of the proceeds to make a scheduled $80 million repayment of a 3.51% Series of First Mortgage Bonds. The term loan bears interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 80.0 basis points. The interest rate is subject to adjustment pursuant to the terms of the loan. On December 31, 2024, PGE repaid $50 million of the term loan, leaving an outstanding balance of $170 million.

As of December 31, 2024, total long-term debt outstanding, net of $15 million of unamortized debt expense, was $4,524 million, of which $170 million is scheduled to mature in 2025.

Equity—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at-the-market offering programs. In 2023, pursuant to the terms of the equity

68

Table of Contents

distribution agreement, PGE entered into separate forward sale agreements with forward counterparties. In March 2024, the Company issued 1,714,972 shares pursuant to the forward sale agreements and received net proceeds of $78 million. In 2024, PGE entered into additional forward sale agreements with forward counterparties, exhausting the $300 million facility. In the third quarter of 2024, the Company issued 2,351,070 shares pursuant to the additional forward sale agreements and received net proceeds of $100 million. In October 2024, the Company issued 2,788,431 shares pursuant to the additional forward sale agreements, settling the transaction, and received net proceeds of $119 million.

On July 26, 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 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 could have physically settled the remaining amount by delivering 353,500 shares in exchange for cash of $17 million as of December 31, 2024. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

For additional information on the at-the-market offering program, see Note 13, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Capital Structure—PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 45.6% and 44.6% as of December 31, 2024 and 2023, respectively.

Critical Accounting Policies and Estimates

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

Regulatory Accounting

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

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

69

Table of Contents

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

Asset Retirement Obligations

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

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

As a co-owner of Colstrip, PGE has provided surety bonds, which are considered off-balance sheet arrangements, of $22 million as of December 31, 2024 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC.

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

Contingencies

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

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

70

Table of Contents