Portland General Electric Co: Form 10-K for the period ended Dec 31, 2024

General

Portland General Electric Company (PGE or the Company), a vertically-integrated electric utility with corporate headquarters located in Portland, Oregon, is engaged in the generation, wholesale purchase and sale, transmission, distribution, and retail sale of electricity to customers in the state of Oregon (State). The Company operates as a cost-based, regulated electric utility with revenue requirements and customer prices determined based on the forecasted cost to serve retail customers and a reasonable rate of return as determined by the Public Utility Commission of Oregon (OPUC). PGE meets its retail load requirement with both Company-owned generation and power purchased in the wholesale market. The Company participates in the wholesale market through the purchase and sale of electricity, natural gas, and environmental credits in an effort to obtain reasonably-priced power to serve its retail customers, manage risk, and administer its long-term wholesale contracts. PGE is committed to developing products and service offerings for the benefit of retail and wholesale customers. PGE, incorporated in 1930, is publicly-owned, with its common stock listed on the New York Stock Exchange (NYSE). The Company operates as a single business segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE owns unregulated, non-utility property that it utilizes for its corporate headquarters.

PGE’s State-approved service area allocation of four thousand square miles is located entirely within Oregon and includes 51 incorporated cities. During 2024, the Company added sixteen thousand customers, and as of December 31, 2024, served a total of 950 thousand retail customers.

Available Information

PGE’s periodic and current reports, and amendments to those reports, are available and may be accessed free of charge through the Investors section of the Company’s website at PortlandGeneral.com as soon as reasonably practicable after the reports are electronically filed with, or furnished to, the United States Securities and Exchange Commission (SEC). It is not intended that PGE’s website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K.

Regulation

Federal and State regulation each have a significant influence on PGE’s business operations. In addition to the agencies and activities discussed below, the Company is subject to regulation by certain environmental agencies, as described in the Environmental Matters section in this Item 1.

Regulatory Accounting

PGE prepares financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) and, as a regulated public utility, the effects of rate regulation are reflected in its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as: i) property, plant, and equipment; ii) regulatory assets and liabilities; iii) revenues; iv) certain operating expenses; v) depreciation expense; and vi) income tax expense. GAAP provides for the deferral, or recording of expenses and revenues in periods other than when an unregulated entity would. As a result, the Company may record regulatory assets, of certain actual or estimated costs that would otherwise be charged to expense, based on expected recovery from customers in future prices. Likewise, certain actual or anticipated credits that would otherwise be recognized as revenue, or reduce expense, can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. PGE records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

The Company periodically assesses the applicability of regulatory accounting to its business, considering both the current and anticipated future regulatory environment and related accounting guidance. For additional information, see “Regulatory Assets and Liabilities” in Note 2, Summary of Significant Accounting Policies, and Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Federal Regulation

Several federal agencies, including the Federal Energy Regulatory Commission (FERC), the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), and the Nuclear Regulatory Commission (NRC), have regulatory authority over certain aspects of PGE’s operations and activities, as described in the discussion that follows.

PGE is a “licensee,” a “public utility,” and a “user, owner, and operator of the bulk power system,” as those terms are defined in the Federal Power Act (FPA). As such, the Company is subject to regulation by the FERC in matters related to wholesale energy activities, transmission services, reliability and cybersecurity standards, natural gas pipelines, hydroelectric projects, accounting policies and practices, short-term debt issuances, and certain other matters.

*Wholesale Energy—*PGE has authority under its FERC Market-Based Rates tariff to charge market-based rates for wholesale energy sales in all markets in which it sells electricity except in its own Balancing Authority Area (BAA). The BAA is the area in which PGE is responsible for balancing customer demand with electricity supply, in real time, and the tariff exception within PGE’s BAA does not have a material impact on the Company.

*Transmission—*PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the FERC.

*Reliability and Cybersecurity Standards—*The FERC has adopted mandatory reliability standards for owners, users, and operators of the bulk power system. Such standards, which are applicable to PGE, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which have responsibility for compliance and enforcement of these standards, and are intended to help maintain and strengthen the reliable planning and operation of the bulk power system.

*Natural Gas Pipelines—*The FERC has authority in matters related to the construction, operation, extension, enlargement, safety, and abandonment of jurisdictional interstate natural gas pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority as the Company has a 79.5% ownership interest in the Kelso-Beaver (KB) Pipeline, a 17-mile, 20-inch diameter, interstate pipeline that provides natural gas to the Company’s three natural gas-fired generating plants located near Clatskanie, Oregon: i) Port Westward Unit 1 (PW1); ii) Port Westward Unit 2 (PW2), and iii) Beaver. In addition, the KB Pipeline serves the North Mist storage facility, which is owned and operated by a local natural gas distribution company, and one additional delivery point for a local manufacturing concern. As the operator of record of the KB Pipeline, PGE is subject to the requirements and regulations enacted under the Pipeline Safety Laws administered by the PHMSA, which include safety and operator qualification standards and public awareness requirements.

*Hydroelectric Licensing—*As required under the FPA, PGE holds FERC licenses for all Company-owned and operated hydroelectric generating plants. The FERC license process includes an extensive public review that involves the consideration of numerous natural resource issues and environmental conditions. For additional information, see the Environmental Matters section in this Item 1. and the Generating Facilities section in Item 2.—“Properties.”

*Accounting Policies and Practices—*PGE prepares periodic and current reports in accordance with GAAP. In addition, the Company prepares, pursuant to applicable provisions of the FPA, financial statements in accordance with the accounting requirements of the FERC, as set forth in its applicable Uniform System of Accounts and published accounting releases. Such financial statements are included in annual and quarterly reports filed with the FERC.

*Short-term Debt—*Pursuant to applicable provisions of the FPA and FERC regulations, regulated public utilities are required to obtain FERC approval to issue certain securities. For additional information on the Company’s Short-term Debt, see “Short-term Debt” in the Debt and Equity section of Liquidity and Capital Resources in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

*Spent Fuel Storage—*The NRC regulates the licensing and decommissioning of nuclear power plants, including PGE’s decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. For additional information on spent nuclear fuel storage activities, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” and “Hazardous Material” in the Environmental Matters section of this Item 1.

State Regulation

PGE is subject to the jurisdiction of the OPUC, which reviews and approves the Company’s retail prices and reviews the Company’s generation and transmission resource acquisition plans, pursuant to a biennial integrated resource planning process. In addition, PGE is required to create a Clean Energy Plan (CEP) to be filed in connection with the Company’s Integrated Resource Plan (IRP) that articulates the Company’s strategy to meet emission reduction targets through an equitable transition to a decarbonized grid. The OPUC also regulates the issuance of securities, prescribes accounting policies and practices, regulates the sale of utility assets, reviews transactions with affiliated companies, and has jurisdiction over the acquisition of, or exertion of substantial influence over, public utilities.

Retail customer prices are determined through formal public proceedings that generally include testimony by participating parties, discovery, public hearings, and the issuance of a final order by the OPUC. Participants in such proceedings may include PGE, OPUC staff, and intervenors representing PGE customer groups, as well as other interested parties. The following lists the more significant regulatory mechanisms and proceedings under which customer prices are determined:

• General Rate Cases (GRCs). PGE periodically evaluates the need to update its retail electric price structure as part of a comprehensive GRC process that reflects revenue requirements based on a forecasted test year. The OPUC authorizes the Company’s rate base, debt-to-equity capital structure, return on equity, overall rate of return, and customer prices.
• Annual Power Cost Updates. The OPUC has approved an Annual Power Cost Update Tariff (AUT) by which PGE can adjust retail customer prices annually to reflect forecasted changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased in the wholesale market and fuel the Company uses to generate electricity, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s consolidated statements of income). NVPC is net of wholesale revenues as well as gains and losses on the sale of excess natural gas, included in other operating revenue, that is not used to fuel PGE’s generation facilities, both of which are classified as Revenues, net in the consolidated statements of income. The OPUC has also authorized a Power Cost Adjustment Mechanism (PCAM), under which PGE may share with customers a portion of actual cost variances associated with NVPC.
• Renewable Adjustment Clause mechanism. The State has a Renewable Portfolio Standard (RPS) that requires PGE to serve a portion of its retail load with renewable resources. In conjunction with the RPS, the State established a Renewable Adjustment Clause (RAC) mechanism that allows for the recovery in retail customer prices, outside of a GRC, of prudently incurred costs to comply with the RPS.
• In 2016, the State passed Oregon Senate Bill (SB) 1547, a law referred to as the Oregon Clean Electricity and Coal Transition Plan, which, among its provisions, increased the RPS percentages in certain future years and required the elimination of coal from Oregon utility customers’ energy

supply. For further information on SB 1547, see “RPS standards and related laws” in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

• During 2021, the State legislature passed Oregon House Bill (HB) 2021, which established clean energy targets and set out a framework that includes, among other things, the development and submittal of CEPs for investor-owned utilities, including PGE, and Electricity Service Suppliers (ESSs) in the State. The targets are an 80% reduction in greenhouse gas (GHG) emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. The CEP may accelerate investment in RPS compliant resources, the cost of which may then be recoverable under the RAC, if the resulting resources are needed for RPS compliance. For further information on HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the Laws and Regulations portion of the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
• Wildfire Automatic Adjustment Clause mechanism. As required by the OPUC, PGE has developed and implemented a Wildfire Mitigation Plan, coordinating activities across the Company and with state-wide stakeholders. PGE strives to improve regional safety by reducing the risk of ignition from PGE assets, while limiting the impacts of public safety power shutoff (PSPS) events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. The OPUC has authorized an Automatic Adjustment Clause mechanism that allows the Company to recover a certain level of ongoing, prudent mitigation expenses in customer prices.

Customers and Revenues

PGE generates revenue primarily through the sale and delivery of electricity to retail customers located exclusively in Oregon. In addition, the Company distributes power to Direct Access customers that choose to purchase their energy from an ESS. Although the Company includes such customers in its customer counts, and energy delivered to such commercial and industrial customers in its total retail energy deliveries, retail revenues include only delivery charges and applicable transition adjustments for these Direct Access customers, as the customers purchase energy directly from the ESSs. The Company conducts retail electric operations within its State-approved service territory and competes with ESSs to supply certain commercial and industrial customer energy needs. In addition, PGE competes with the local natural gas distribution company for the energy needs of residential and commercial space heating, water heating, and appliances. Energy efficiency, demand response, conservation measures, and the advancement of technology around distributed generation, including rooftop solar, and storage resources also have an influence on customer demand.

Retail Revenues

Retail customers are classified as residential, commercial, or industrial, with no single customer representing more than 9% of PGE’s total retail revenues or 14% of total retail deliveries during 2024.

PGE’s Retail revenues, retail energy deliveries, and average number of retail customers consist of the following:

(1) Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.

(2) Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

The following table presents additional annual averages for retail customers. Certain supplemental tariff collections are excluded from revenues as they are not considered a part of the Company’s base retail prices for these calculations.

9

For additional information, see the Results of Operations section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), mobile homes, and small farms. Residential demand is sensitive to the effects of the weather and seasonal temperature changes lead to variations in both heating and cooling needs. Based on the climate in PGE’s service area, the heating season tends to span a longer time period while cooling needs, although robust, are reflected over a shorter span concentrated in the summer months of June through September.

Economic conditions can also affect residential demand as job growth and population increases in PGE’s service territory have led to customer growth. The COVID-19 pandemic introduced additional behavioral patterns that reflected the shift that occurred with respect to hybrid work schedules as residential customers spent more time at home, the impact of which has largely normalized in the last few years. Residential demand is also impacted by energy efficiency measures and increased rooftop solar penetration in the service territory.

Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. This customer class includes most businesses, small industrial companies, and public street and highway lighting accounts. The Company’s commercial customer demand is somewhat less susceptible to weather conditions than residential customer demand. Economic conditions and fluctuations in total employment in the region can be indicative of changes in energy demand from commercial customers. Energy efficiency measures also impact commercial demand, as measures have focused on the commercial sector in recent years.

Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having limited impact on this customer class. Strength in the high-tech manufacturing and digital service sector, along with new data center facilities coming online, continue to place upward pressure on deliveries to industrial customers. Favorable tax policies, both State and Federal, and connectivity both locally and to overseas markets via the transpacific cable have led to strong data center development in PGE's service area.

*Customer Choice Programs—*In addition to standard cost-of-service pricing, the Company offers different pricing options. Under cost-of-service pricing, residential and small commercial customers may select portfolio options from PGE that include time-of-use and renewable resource pricing. The Company also offers various energy shifting programs like Peak Time Rebates, Smart Thermostat, Time of Day, and Smart Charging, all of which enable PGE to safely reduce power use on the system during peak demand.

Pricing options other than cost-of-service are available to certain commercial and industrial customers for a one-year period, including daily market index-based pricing under which the Company provides the electricity, and Direct Access, whereby customers purchase electricity directly from an ESS.

PGE receives revenue from Direct Access customers only for the transmission and delivery of the volume of electricity delivered, along with fixed transition adjustments intended to mitigate the shifting of excess charges to the Company’s cost-of-service customers. Certain large commercial and industrial customers may elect a fixed three-year or a minimum five-year term, to be served either by an ESS, or by the Company under the daily market index-based price option. Participation in the fixed three-year and minimum five-year opt-out programs for existing and planned load is capped at 300 average megawatts in aggregate.

PGE is also required to offer to eligible customers, enrollment in the New Large Load Direct Access program, which is capped at 119 average megawatts in total, for unplanned, large, new loads and large load growth at existing sites.

For further information regarding Direct Access deliveries, see “Customers and demand” in the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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. Oregon’s most populous city, Portland, and most populous county, Multnomah, have each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have set, or are considering, similar goals.

The Company’s Green Future Impact Program, which allows for customer-provided renewable resources, PGE-provided power purchase agreements (PPAs) for renewable resources, and Company-owned, cost-of-service resources under certain options, enables commercial and industrial customers access to bundled renewable attributes from those resources. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, and reliable, integrated power while providing customer choice and a cleaner energy system. The total available capacity under the program is 750 MW. For more information on the Company’s PPAs that currently serve the Green Future Impact Program, see “Green Future Impact Program” within Purchased Power in the Power Supply section of this Item 1.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Interconnected transmission systems in the western United States and Canada serve utilities with diverse load requirements and allow the Company to purchase and sell electricity, largely through bi-lateral agreements, within the region to serve retail demand. PGE’s engagement in the wholesale electricity marketplace depends upon numerous factors, including: 1) the relative price and availability of power, whether purchased, generated, or from storage facilities; 2) hydro, wind, and solar conditions; and 3) daily and seasonal retail demand. The Company also participates in the California Independent System Operator’s (CAISO) western Energy Imbalance Market (western EIM), which allows for load balancing with other western EIM participants in five-minute intervals. Wholesale revenues represented 16% of total revenues in 2024, and 14% in 2023 and 2022.

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, pole attachment rentals, and other electric services provided to customers. Other operating revenues represented 2% of total revenues in 2024, 2023, and 2022.

Seasonality

Demand for electricity by PGE’s residential and, to a lesser extent, commercial and industrial customers is affected by seasonal weather conditions. The Company uses various measures, including heating and cooling degree-days and wind speeds to determine the effect of weather on the demand for electricity. Heating and cooling degree-days, determined by taking the difference between the average daily temperature and a prescribed baseline, provide cumulative variances over a period of time, to indicate the extent to which customers are likely to have used electricity for heating or cooling. The greater the number of degree-days, the greater the expected demand for electricity.

The following table presents the heating and cooling degree-days for the most recent three-year period, along with current 15-year averages for the most recent year provided by the National Weather Service, as measured at Portland International Airport:

In August 2023, PGE set a new all-time high net system load peak of 4,498 megawatts (MW), surpassing the previous all-time peak that occurred in June 2021. In December 2022, the Company recorded its current winter peak of 4,113 MW. The following table presents PGE’s average winter (defined as January, February, and December) and summer (defined as June through September) loads for the periods presented, along with the corresponding peak load (in MWs) and month in which such peak occurred. As illustrated, although the average winter loads continue to exceed average summer loads, the Company has seen its highest annual peak loads during the summer months in recent years:

The Company tracks and evaluates both load growth and peak load requirements for purposes of long-term load forecasting, integrated resource planning, and preparing GRC assumptions. Behavior patterns, conservation, energy efficiency initiatives and measures, weather effects, economic conditions, including high-tech and digital services growth in its service territory, distributed generation including rooftop solar, transportation and building electrification, and demographic changes all play a role in determining expected future customer demand and the resulting resources the Company may need to adequately meet those loads and maintain adequate capacity reserves.

Power Supply

PGE utilizes its generating resources, as well as wholesale power purchases from third parties, to meet the needs of its retail customers. The volume of electricity the Company generates is dependent upon, among other factors, the capacity and availability of its generating resources and the price and availability of wholesale power and natural gas. As part of its power supply operations, the Company enters into short- and long-term power and fuel purchase and sale agreements. PGE executes economic dispatch decisions concerning its own generation and participates in the wholesale market in an effort to obtain reasonably-priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. 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. In addition, the Company encourages energy efficiency measures to help meet its energy requirements and promotes the use of various demand side management products to reduce load during peak time usage.

PGE’s resource and contracted capacity (in MW) was as follows:

(1) Capacity represents the MW the plants are capable of generating under normal operating conditions, which is affected by ambient temperatures, net of electricity used in the operation of the plant.

(2) Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 30 to 40% of capacity, dependent upon wind conditions.

(3) Capacity represents most favorable operating conditions and differs from expected energy to be generated, which is expected to range from 40 to 50% of capacity, dependent upon river flows.

(4) Capacity represents contracted capacity for PPAs under the Public Utility Regulatory Policies Act of 1978 (PURPA).

(5) Capacity represents a heat rate call option of a natural gas generating station, which does not commence until July 2025. For more information see “Natural gas heat rate call option” below.

(6) Capacity includes 50 MW from the solar component of the Wheatridge Renewable Energy Facility (Wheatridge).

For information regarding actual generating output and purchases for the years ended December 31, 2024 and 2023, see the Results of Operations section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Generation

PGE’s generating resources consist of six thermal plants (natural gas- and coal-fired), four wind farms, and seven hydroelectric facilities. The portion of PGE’s retail load requirements generated by its plants varies from year to year and is determined by various factors, including planned and unplanned outages, availability and price of coal and natural gas, precipitation and snow-pack levels, the market price of electricity, and wind variability. For a complete listing of these facilities, see “Generating Facilities” in Item 2.—“Properties.”

Thermal The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty Generating Station (Carty).

The Company also has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is located in Colstrip, Montana and operated by a third party. For additional information on Colstrip as it relates to environmental laws and regulations in the State, see “RPS standards and related laws” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Wind PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River Wind Farm (Tucannon River). Biglow Canyon, located in Sherman County, Oregon, consists of 217 turbines with a total nameplate capacity of 450 MW. Tucannon River, located in southeastern Washington, consists of 116 turbines with a total nameplate capacity of 267 MW.

During 2020, the wind component of Wheatridge, located in Morrow County, Oregon, was placed into service. Although PGE does not operate Wheatridge, it owns 40 turbines with a total nameplate capacity of 100 MW and purchases the output of the remaining turbines, with a nameplate capacity of 200 MW through a PPA.

On January 5, 2024, substantial completion was achieved on the Clearwater wind energy facility, located in Eastern Montana. Although PGE does not operate Clearwater, it owns 75 turbines with a total nameplate capacity of 208 MW.

Hydro The Company’s FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), four plants on the Clackamas River, and one on the Willamette River.

PGE has a 50.01% ownership interest in the 455 MW Pelton/Round Butte hydroelectric project, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. The CTWS has an option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If the second option is exercised, the CTWS’s ownership percentage would exceed 50%. PGE purchases 100% of the CTWS’s share of the project output. For more information see “CTWS” within Purchased Power in the Power Supply section of this Item 1.

*Fuel Supply—*PGE contracts for natural gas and coal supplies required to fuel the Company’s thermal generating plants, with certain plants also able to operate on fuel oil, if needed. In addition, the Company utilizes financial instruments such as forward, future, swap, and option contracts to manage its exposure to volatility in natural gas prices.

Natural Gas Physical supplies of natural gas are generally purchased up to twelve months in advance of delivery and based on anticipated operation of the plants. PGE manages the price risk of natural gas supply through the use of financial contracts up to 60 months in advance of expected need of energy.

PGE owns 79.5%, and is the operator of record, of the KB Pipeline, which directly connects PW1, PW2, and Beaver to the Northwest Pipeline, an interstate natural gas pipeline operating between British Columbia and New Mexico by Williams Northwest Pipeline. Currently, PGE transports natural gas on the KB Pipeline for its own use under a firm transportation service agreement, with capacity offered to others on an interruptible basis to the extent not utilized by the Company.

PGE has access to 159,726 Decatherms (Dth) per day of firm natural gas transportation capacity on the Northwest Pipeline to serve the three plants.

PGE has access to 4.1 billion cubic feet of natural gas storage in Mist, Oregon from which it can draw when economic factors favor its use or in the event that natural gas supplies are interrupted. The storage facility, owned and operated by NW Natural, may be utilized to provide fuel to PW1, PW2, and Beaver.

To serve Coyote Springs and Carty, PGE has access to 119,500 Dth per day of firm natural gas transportation capacity on three pipeline systems accessing the gas market in Alberta, Canada.

Coal The Colstrip co-owners obtain coal to fuel the plant via conveyor belt from a mine that lies adjacent to the facility and is the sole source of coal supply for the plant. The coal supply contract with the owner of the mine is scheduled to expire at the end of 2025. The terms of the contract and the quality of coal are expected to allow the facility to operate within required emissions limits.

Purchased Power

PGE supplements its own generation with power purchased in the wholesale market to meet its retail load requirements, manage risk, and administer its long-term wholesale contracts. The Company utilizes short- and long-term wholesale power purchase contracts in an effort to provide the most favorable economic mix on a variable cost basis.

PGE’s medium-term power cost strategy helps mitigate the effect of price volatility on its customers due to changing energy market conditions. The strategy allows the Company to take positions in power and fuel markets up to five years in advance of physical delivery. By purchasing a portion of anticipated energy needs for future years over an extended period, PGE attempts to mitigate a portion of the potential future volatility in the average cost of purchased power and fuel.

The Company’s major power purchase contracts consist of the following (also see the preceding table which summarizes the average resource capabilities related to these contracts):

*Hydro—*During 2024, the Company had the following agreements:

• *Public Utility Districts—*PGE has long-term power purchase contracts with certain public utility districts (PUDs) in the state of Washington for a portion of the output of certain hydroelectric projects on the mid-Columbia River. Although the projects currently provide PGE a total of 1,010 MW of nameplate capacity through contracts as shown below, actual energy received is dependent upon river flows and capacity amounts may decline over time:
• 258 MW of average variable capacity with Douglas County PUD that expires in 2025;
• 434 MW of capacity under a contract expiring in 2026 in which PGE will purchase a 20% share of the project output and sell varying amounts of energy in accordance with contract terms back to the PUD in order to meet their load requirements;
• 65 MW of average monthly capacity with Douglas County PUD that expires in 2028;
• 79 MW of capacity under a contract expiring in 2030, with an option to renew until 2032, in which PGE will purchase 10% of the project output. PGE will sell 25 MW back to the PUD from 2024 to 2025; and
• 174 MW of capacity with Grant County PUD that expires in 2052;
• *CTWS—*PGE has a long-term agreement under which the Company purchases output from the CTWS’ interest in the Pelton/Round Butte hydroelectric project. Although the agreement provides approximately 224 MW of net capacity, actual energy received is dependent upon river flows. The term of the agreement coincides with the term of the FERC license for this project, which expires in 2055. Under a separate PPA executed in 2014, PGE paid fixed capacity and

energy charges to the CTWS for 100% of its share of the project through 2024. The CTWS exercised their option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte effective January 1, 2022. As a result of the sale, capacity from Company-owned generation decreased by approximately 76 MW, and capacity from purchased power increased by a corresponding amount. Under the PPA, PGE purchases 100% of the CTWS’s additional share of the project and payments under the PPA increase proportionately. PGE and the CTWS executed an additional 16-year PPA which begins on January 1, 2025, that effectively extends the term from 2024 to 2040 and increases the capacity payments in the extension period.

• *Other—*The remaining capacity is primarily comprised of a contract with Portland Hydro, which expires in 2032, that provides for the purchase of power generated from hydroelectric projects with capacity of 36 MW.

*PURPA qualifying facilities—*PGE is required to purchase power from PURPA qualifying facilities (QFs), as mandated by federal law. QFs are generating facilities that fall within one of the following two categories: i) qualifying generation facilities with a capacity of 80 MW or less and whose primary energy source is renewable (hydro, wind, solar, biomass, waste, or geothermal); or ii) qualifying cogeneration facilities that sequentially produce electricity and another form of useful thermal energy (e.g., heat, steam) in a way that is more efficient than the separate production of each form of energy. As of December 31, 2024, PGE had contracts with 69 online QFs, providing a total of 315 MW of capacity. As of December 31, 2024, PGE had two contracts with QFs representing 116 MW of capacity that are not yet operational, of which two of the QF PPAs are in default because the QFs have failed to complete construction and become operational by the date required by the PPA. The PPAs provide that the QF must cure its default within a period specified under the contract terms. If the QF has failed to cure, PGE is permitted to immediately terminate the QF PPA upon expiration of the cure period. The term of a QF PPA generally ranges from 15 to 23 years.

The expense and volume of purchases from QFs for the years ended December 31, 2024 and 2023 were as follows:

Expenses incurred related to PURPA contracts are included in PGE’s AUT.

*Dispatchable Standby Generation (DSG)—*PGE has a DSG program under which the Company can dispatch and monitor customer-owned backup generators to provide NERC-required operating reserves. As of December 31, 2024, there were 78 generators with a total DSG nameplate capacity of 129 MW. PGE continues to pursue expansion of the program through ongoing engagement with customers and incorporation of battery energy storage.

*Wind—*PGE has four contracts to purchase power generated from renewable wind resources. Although the projects as shown below currently provide PGE a total of 400 MW of capacity, the expected energy from these wind resources will vary from the nameplate capacity due to varying wind conditions:

• 25 MW of capacity that expires in 2028;
• 75 MW of capacity that expires in 2035;
• 200 MW of capacity that expires in 2051; and
• 100 MW of capacity that expires in 2053.

*Solar—*PGE has five contracts representing 219 MW of capacity to purchase power generated from photovoltaic solar projects. Two of these projects extend to 2036 while the other three extend to 2037, 2038, and 2042, respectively. The expected energy from these solar resources will vary from the nameplate capacity due to varying solar conditions.

Green Future Impact Program— PGE has three contracts representing 360 MW of capacity to purchase power generated from renewable resources to support the Green Future Impact Program:

• a 15-year contract with Avangrid Renewables representing 162 MW from a renewable solar facility in Gilliam County, Oregon that was placed in service in January 2023. This capacity is reflected within solar purchased power in the resource and contracted capacity table above;
• a 25-year contract with Avangrid Renewables representing 138 MW from a renewable solar facility in Wasco County, Oregon that is expected to be placed in service in January 2026. This additional capacity is not reflected in the resource and contracted capacity table above; and
• a 25-year contract with Avangrid Renewables representing 60 MW from a renewable solar facility in Wasco County, Oregon that is expected to be placed in service in January 2026. This additional capacity is not reflected in the resource and contracted capacity table above.

For additional information on the Green Future Impact Program, see “Customer Choice Programs” within the Customers and Revenues section of this Item 1.

*Biomass—*PGE had one contract to purchase biomass energy that expired in January 2025.

*Natural gas heat rate call option—*In order to provide additional dispatchable firm capacity to meet customer demand, PGE has entered into a physical heat rate call option for 250 MW of the capacity, energy, and attributes associated with the facility. The contract begins in July 2025.

*Short-term contracts—*These contracts are for delivery periods of one month to one year in length. They are entered into with various counterparties to provide additional firm energy to help meet the Company’s load requirements.

PGE also utilizes spot purchases of power in the open market to secure the energy required to serve its retail customers. Such purchases are made under contracts that range in duration from 15 minutes to less than one month. PGE is a market participant in the western EIM, which allows certain of the Company’s generating plants to receive automated dispatch signals from the CAISO for load balancing with other western EIM participants in five-minute intervals.

For additional information regarding PGE’s power purchase contracts, see Note 16, Commitments and Guarantees and Note 17, Leases, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Energy Storage

Resources in PGE’s energy storage portfolio that are in operation and under development as of December 31, 2024 are primarily as follows:

• *Wheatridge—*The Wheatridge Renewable Energy Facility includes a 30 MW battery component. Subsidiaries of NextEra Energy Resources, LLC own the solar and battery components, and sell their portion of the output to PGE.
• *Sundial (formerly Troutdale Grid)—*PGE entered into a storage capacity agreement for a 200 MW Battery Energy Storage System (BESS) in Troutdale, Oregon. NextEra Energy Resources, LLC owns the resource and sells the capacity to PGE under a 20-year agreement. The project was placed in-service in December 2024.
• *Coffee Creek—*PGE entered into an agreement to construct a 17 MW BESS in Sherwood, Oregon. PGE owns the resource. The project was placed in-service in November 2024.
• *Constable (formerly Evergreen)—*PGE entered into an agreement to construct a 75 MW BESS in Hillsboro, Oregon. PGE owns the resource. The project was placed in-service in December 2024.
• *Seaside Grid—*PGE entered into an agreement to construct a 200 MW BESS in Portland, Oregon. PGE will own the resource. The project has an estimated commercial operation date of June 30, 2025.

Certain other energy storage assets are considered immaterial and are not reflected in the resource and contracted capacity table above.

Future Energy Resource Strategy

PGE’s IRP outlines the Company’s plan to meet future customer demand and describes PGE’s future energy supply strategy. For a detailed discussion of the IRPs, see “Investing in a Clean Energy Future” within the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Transmission and Distribution

Transmission systems deliver energy from generating facilities to distribution systems for final delivery to customers. PGE schedules energy deliveries over its transmission system in accordance with FERC requirements and operates one BAA in its service territory. In 2024, PGE delivered approximately 31 million megawatt hours (MWh) through 1,269 circuit miles of transmission lines operating at or above 115 kilovolts (kV).

PGE’s transmission system is part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of 11 western states, two Canadian provinces and parts of Mexico, and is subject to the reliability rules of the WECC and the NERC. PGE relies on transmission contracts with BPA) to transmit a significant amount of the Company’s generation to serve its distribution system. PGE’s transmission system, together with contractual rights on other transmission systems, enables the Company to integrate and access generation resources to meet its customers’ energy requirements. PGE’s transmission system is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. PGE has joined the Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP), which is currently expected to become a binding commitment in 2027. The Company has participated in the western EIM for several years and plans to join the CAISO Extended Day Ahead Market (EDAM) in the near future. For further information, see “Operating Activities” within the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The Company’s wholesale transmission activities are regulated by the FERC and are offered on a non-discriminatory basis, with all potential customers provided equal access to PGE’s transmission system through PGE’s OATT. In accordance with its OATT, PGE offers several transmission services to wholesale customers, including:

• Network integration transmission service, a service that integrates generating resources to serve retail loads;
• Short- and long-term firm point-to-point transmission service, a service with fixed delivery and receipt points; and
• Non-firm point-to-point service, an “as available” service with fixed delivery and receipt points.

For additional information regarding the Company’s transmission and distribution facilities, see “Transmission and Distribution” in Item 2.—“Properties.”

Environmental Matters

PGE’s operations are subject to a wide range of environmental protection laws and regulations, which pertain to air and water quality, endangered species and wildlife protection, and hazardous materials. Various state and federal agencies also regulate environmental matters that relate to the siting, construction, and operation of generation, transmission, and substation facilities and the handling, accumulation, clean-up, and disposal of toxic and hazardous substances. In addition, certain of the Company’s hydroelectric projects and transmission facilities are located on property under the jurisdiction of federal and state agencies, and/or tribal entities that have authority in environmental protection matters. The following discussion provides further information on certain environmental regulations that affect the Company’s operations and facilities.

Air Quality

*Clean Air Act—*PGE’s operations, primarily its thermal generating plants, are subject to regulation under the federal Clean Air Act (CAA), which addresses particulate matter, hazardous air pollutants, and GHG emissions, in terms of both quantity and rate, among other things. Oregon and Montana, the states in which PGE’s thermal facilities are located, also implement and administer certain portions of the CAA and have set standards that are at least as stringent as federal standards. PGE manages its air emissions at its thermal generating plants by the use of low sulfur fuel, emissions and combustion controls and monitoring, and sulfur dioxide allowances awarded pursuant to the CAA.

*Climate Change—*In 2019, the United States Environmental Protection Agency (EPA) finalized the Affordable Clean Energy (ACE) rule, which established guidelines for states to develop plans to address GHG emissions from individual, existing coal-fired plants, such as Colstrip in the case of PGE, to repeal and replace the Clean Power Plan (CPP), which was originally released in 2015. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it, in full, back to the EPA. Notwithstanding objections that the EPA intended to issue a new rule that took recent changes in the electricity sector into account, in October 2021, the U.S. Supreme Court agreed to hear an appeal of the D.C. Circuit decision. The Supreme Court, in a 2022 decision, determined that the broad approach in the CPP regulating emissions exceeded the powers granted to the EPA by Congress. The Court did not expressly determine whether the EPA can regulate power sector GHG emissions through its other regulatory authority. In May 2023, the EPA proposed a successor rule to the CPP including CAA emissions limits and guidelines for carbon dioxide emissions from fossil-fuel fired power plants based on cost-effective and available control technologies. On April 25, 2024, the EPA released final regulations pertaining to electric generation facilities. For further information on the final regulations, see “EPA Regulations for Electric Generating Facilities” in the Laws and Regulations section of the Overview in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

PGE continues to evaluate the final rules to assess the impact they may have on the Company’s continuing investment in Colstrip and on the Company’s operation of its existing natural gas fleet. Any impacts could be material. PGE notes that a substantial number of legal challenges have been filed regarding these rules. Such challenges, 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 2020, the Governor of Oregon issued Executive Order 20-04 that directed State agencies to integrate climate change and the State’s GHG emissions reduction goals into their plans, budgets, investments, and decisions to the extent allowed by law. Among other things, Executive Order 20-04, which remains in place until withdrawn or superseded:

• directed the Oregon Department of Environmental Quality (ODEQ) to adopt a program to cap and reduce GHG emissions within the State from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. In response, in 2021, the ODEQ adopted the Climate Protection Program, which among various provisions, included an exemption for electricity generation from the Company’s natural gas-fired resources; and
• modified the reduction goals of the State’s Clean Fuels Program and extended the program while increasing the required reduction in average carbon intensity of transportation fuels.

In December 2023, the Oregon Court of Appeals invalidated the ODEQ’s initial Climate Protection Program rules on the basis that the program failed to comply with certain procedural requirements when adopting rules under the CAA. In November 2024, the ODEQ adopted rules to establish the Climate Protection Program 2024 in Oregon. The Climate Protection Program set an enforceable declining cap on GHG emissions from fossil fuels used throughout Oregon, including diesel, gasoline, and natural gas. The Climate Protection Program is designed to reduce these emissions 50% by 2035 and 90% by 2050.

*HB 2021—*In 2021, the Oregon Legislature passed HB 2021, which requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. The baseline levels for PGE are the average annual emissions for the years 2010, 2011, and 2012 associated with the electricity sold to its retail electricity consumers as reported to the ODEQ. For additional information, see “HB 2021” in the Laws and Regulations section of the Overview section of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Any laws that would impose taxes or mandatory reductions in GHG emissions may have a material impact on PGE’s operations, as the Company utilizes fossil fuels in its own power generation and other companies use such fuels to generate power that PGE purchases in the wholesale market. If incremental costs were incurred as a result of changes in the regulations regarding GHG emissions, the Company would seek recovery in customer prices.

For more information regarding GHG emissions and related environmental regulation, including Oregon’s RPS and the Company’s goals in this area, see “Renewable Adjustment Clause mechanism” under State Regulation in the Regulation section of this Item 1. and “Company Strategy” in the Overview of Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Water Quality

Under the federal Clean Water Act, entities that require any federal license or permit to conduct an activity that may result in a discharge to waters of the United States must first receive a water quality certification or permit from the state in which the activity will occur, or obtain an appropriate waiver. In Oregon, Montana, and Washington, the environmental regulatory agencies of each state are responsible for reviewing proposed projects under such requirements to ensure that federally approved activities will meet water quality standards and policies established by the respective state. PGE works continually with state agencies to obtain permits or certificates of compliance needed for its hydroelectric operations under the FERC licenses and continues to monitor and update equipment to meet federal and state standards.

Threatened and Endangered Species and Wildlife

*Fish Protection—*The federal Endangered Species Act (ESA) has granted protection to many populations of migratory fish species in the Pacific Northwest. Long-term recovery plans for these species continue to have operational impacts on many of the region’s hydroelectric projects. PGE continues to implement fish protection measures at its hydroelectric projects that were prescribed by the U.S. Fish and Wildlife Service and the National Marine Fisheries Service under their authority granted in the ESA and the FPA. Conditions required with the operating licenses are expected to result in a minor reduction in power production and continued capital spending to modify the facilities to enhance fish passage and survival.

*Avian Protection—*Various statutes, including the Migratory Bird Treaty Act and Bald and Golden Eagle Protection Act, contain provisions for civil, criminal, and administrative penalties resulting from the unauthorized take of migratory birds and eagles. Because PGE operates facilities that can pose risks to a variety of such birds and eagles, the Company developed an Avian Protection Plan to help address and reduce risks to avian species that may be affected by Company operations. PGE has implemented such a plan for its transmission, distribution, and thermal generation facilities and additional, specific plans for its wind generation facilities.

Hazardous Materials

The handling and disposal of hazardous materials from Company facilities is subject to regulation under the federal Resource Conservation and Recovery Act. In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, are regulated under the federal Toxic Substances Control Act. PGE has a comprehensive program to comply with requirements of both federal and state regulations related to the storage, handling, and disposal of hazardous materials

PGE is also subject to the Comprehensive Environmental Response Compensation and Liability Act, commonly referred to as Superfund, which provides authority to the EPA to assert joint and several liability for investigation and remediation costs for designated Superfund sites.

An investigation by the EPA that began in 1997 of a segment of the Willamette River in Oregon known as Portland Harbor, revealed significant contamination of river sediments and prompted the EPA to designate Portland Harbor as a Superfund site. The EPA has listed PGE among the more than one hundred Potentially Responsible Parties (PRPs) in this matter, as PGE historically owned or operated property near the river. For additional information regarding the EPA action on Portland Harbor, see Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

PGE is subject to regulation by the United States Department of Energy (USDOE), which, under the Nuclear Waste Policy Act of 1982, is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel from Trojan that is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel. The NRC approved the transfer of spent nuclear fuel to the ISFSI where it is expected to remain until permanent off-site storage is available. Shipment of the spent nuclear fuel from the ISFSI to off-site storage is not expected to be completed prior to 2059. For additional information regarding this matter, see “Trojan decommissioning activities” in Note 8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Human Capital Management

PGE’s talent and culture are vital to its ability to execute its business strategy and realize continued success. Accordingly, the Company seeks to attract and retain a talented, motivated, and diverse workforce and maintain a culture that reflects PGE’s Guiding Behaviors, drive for performance, and commitment to acting with the highest levels of honesty, integrity, compliance, and safety.

*Employees and Collective Bargaining Agreements—*PGE had 2,915 employees in its workforce as of December 31, 2024, with 648 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (IBEW). One agreement, which expires February 2028, covers 582 employees, and the other, which expires August 2027, covers 66 employees. The partnership with IBEW is key to a holistic labor relations approach. In addition, PGE utilizes independent contractors and temporary personnel to supplement its workforce.

*Competitive Pay and Benefits—*PGE is committed to pay equity among its employees and offers a wide range of market-competitive benefits, including comprehensive health and welfare benefits and a 401(k) retirement plan, designed to support the physical, mental, and financial well-being of its employees.

*Talent Development—*PGE provides a variety of training and development programs for employees, as well as tuition reimbursement for job-related coursework. PGE offers a mentorship program for all regular, non-represented PGE employees to help support their growth and development. The PGE Board of Directors oversees executive talent development with the assistance of the Nominating, Governance, and Sustainability Committee and the Compensation, Culture and Talent Committee in an effort to increase the pool of internal candidates. At least annually, the Board conducts reviews of succession plans for senior management, which includes a review of the qualifications and development plans of potential internal candidates and diversity of the succession pipeline. PGE conducts employee engagement surveys periodically to give employees the opportunity to share their perspectives and provide feedback. Survey results are shared with PGE management so that managers can take action towards improving the employee experience.

*Health and Safety—*PGE is committed to providing a safe and healthy place of business for employees, customers, and the public. Management has established an Executive Safety Committee that has oversight of the Company’s efforts to create a safe workplace. This committee partners closely with International Brotherhood of Electrical Workers Local No. 125 and has active bargaining unit employees in attendance to voice concerns and suggestions and work with PGE management on solutions for continual improvement of the Company’s safety programs and culture. In addition, PGE provides various safety resources to its employees, such as safety manuals, trainings, and incident reporting tools that are all designed to incorporate safe practices into all daily activities and promote in all employees a sense of personal commitment, responsibility, and obligation regarding safety. PGE has also introduced an Industrial Injury Prevention Specialist (IIPS) and accompanying 24/7 nurse line/injury care program, which focuses on building a culture of total worker health for field employees, providing coaching on ergonomics, muscle care, and acute/chronic injury prevention. The IIPS is also a mid-level medical service provider for employees, providing early intervention and first aid care for employees, focusing on timely and appropriate care for employees. PGE offers a variety of competitive wellness benefits to support physical, mental, social, emotional, and financial well-being. Programs include a digital wellness platform, an Employee Assistance Program that provides free and confidential wellness counseling to all employees and their families, financial education, on-site fitness facilities, volunteer opportunities, company-match on charitable contributions, and tuition reimbursement.

*Investing in PGE’s Workforce—*PGE promotes an inclusive workforce through pay equity practices, training, and development opportunities for employees looking to advance into, and within, management. Black, Indigenous, and People of Color comprise over 25% of its employees and management, and 34% of its employees and over 36% of management, including its CEO, are female. PGE also promotes diversity and economic development through its suppliers. The Company’s supplier diversity program provides an opportunity in competitive bid events for qualified minority-owned, women-owned, disabled veteran-owned, and emerging small business suppliers.

Information about Executive Officers

The following are PGE’s current executive officers:

22

When evaluating PGE and any investment in its securities, investors should consider carefully the following risk factors and all other information contained in this Annual Report on Form 10-K and in the other documents that the Company files from time to time with the SEC. The events described in the risk factors could have material effects on PGE’s business, financial condition, results of operations, or cash flows, or that materially adversely affect PGE’s results and cause such results to differ materially from projected results. Risk and uncertainties not currently known to the Company or that are currently deemed to be immaterial may also harm PGE. If any of these risks occur, PGE’s business, financial condition, results of operations, and/or cash flows could be materially adversely affected, and the trading prices of the Company’s securities could substantially decline.

BUSINESS AND OPERATIONAL RISKS

The effects of unseasonable or severe weather and other natural phenomena can adversely affect the Company’s financial condition and results of operations, and the effects of climate change could result in more intense, frequent, and extreme weather events.

Weather conditions can adversely affect PGE’s revenues and costs, impacting the Company’s results of operations. Variations in temperatures can affect customer demand for electricity, with warmer-than-normal winter seasons or cooler-than-normal summer seasons reducing demand for energy. Weather conditions are the dominant cause of usage variations from normal seasonal patterns, particularly for residential customers. Rapid increases in load requirements resulting from unexpected weather changes, particularly if coupled with transmission constraints, could adversely impact PGE’s cost and ability to meet the energy needs of its customers. Conversely, rapid decreases in load requirements could result in the sale of excess energy at depressed market prices.

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

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

Capital investment and operating expenses related to this risk may not be recoverable through increases in customer prices or insurance proceeds.

Cybersecurity attacks, data security breaches, physical attacks and security breaches, acts of terrorism, or other similar events could disrupt PGE’s operations, require significant expenditures, or result in claims against the Company.

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

Natural or human-caused disasters and other risks could damage the Company’s facilities and disrupt delivery of electricity resulting in significant property loss, repair costs, and reduced customer satisfaction.

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

Electric utility operations may pose risk to workers, the public, and property, and may have adverse impacts on the environment.

The operation of electric generation, transmission, battery storage, and distribution infrastructure involves inherent risks, including breakdown or failure of equipment, motor vehicle accidents, fires involving the utility’s equipment, dam failure at company-owned hydroelectric facilities, public and worker safety, human contact with energized equipment, and operator error. A portion of the Company’s operations relies on Company- or third party-owned natural gas transmission and distribution infrastructure and involves inherent risks, such as leaks, explosions, mechanical problems, and worker and public safety.

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

The inability to attract and retain a qualified workforce and to maintain satisfactory collective bargaining agreements without prolonged labor disruptions may adversely affect PGE’s results of operations.

PGE’s workforce includes a diverse mix of skilled professional, managerial, and technical employees, including employees represented under collective bargaining agreements. Workforce management risks include the risk of retaining key employees or attracting and retaining employees skilled in new energy technologies, turnover due to demographic challenges as certain employees approach retirement age, and turnover due to macroeconomic trends such as the impacts of inflation on pensions and other retirement funding. Any turnover will require that the Company attract, train, and retain skilled workers to prevent loss of institutional knowledge or skills gaps. PGE faces competition for employees within the industry and in local geographies. The Company faces the risk of labor disruption due to the outcomes of labor negotiations or the possibility that employees not currently subject to collective bargaining agreements may organize. PGE relies on a contracted workforce for specific business purposes, and may experience increased costs or inability to find contracted workforce, which may result in a negative impact on operations as well as financial impact.

The construction of new facilities and the modifications or replacements of existing facilities are subject to risks that could result in the disallowance of certain costs for recovery in customer prices or higher operating costs.

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

REGULATORY, LEGAL, AND COMPLIANCE RISKS

PGE is subject to extensive price regulation and relies on recovery of costs, the uncertainty of which could affect the Company’s operations and costs.

PGE is subject to ongoing regulation by the FERC, the OPUC, and by certain federal, state, and local authorities under environmental, permitting, and other laws. Such regulation significantly influences the Company’s operating environment and affects many aspects of its business. The Company cannot predict with certainty the future course of such changes or the ultimate effect that they might have on its business, and such changes could delay or adversely affect business planning and transactions and substantially increase the Company’s costs.

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

PGE is subject to various legal and regulatory proceedings, the outcome of which is uncertain, and resolution unfavorable to PGE could adversely affect its results of operations, financial condition, or cash flows.

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

There are certain pending legal and regulatory proceedings that may have an adverse effect on results of operations and cash flows for future reporting periods. For additional information, see Item 3.—“Legal Proceedings,” Regulatory Matters within the “Overview” of Item 7.— “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Compliance with environmental laws and regulations may result in capital expenditures, increased operating costs and various liabilities, and adverse impacts on the Company’s results of operations.

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

A portion of PGE’s total system load is supplied with power generated from hydroelectric and wind generating resources. Operation of these facilities is subject to regulation related to the protection of fish and wildlife. Changes to the listing of various plants and species of fish, birds, and other wildlife as threatened or endangered could result in increased mitigation activities, which could have a material impact on PGE’s financial condition and results of operations. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, laws relating to the protection of migratory birds and other wildlife could impact the development and operation of transmission and distribution lines and wind projects. Also, changes to and new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the availability of hydroelectric or wind generating resources to meet the Company’s energy requirements.

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

Changes in federal laws and programs may have an adverse impact on the Company’s financial position, results of operations, and cash flows.

Changes in federal laws and programs, either through executive order or legislation, including to tax laws and federal grant programs, may have an adverse impact on the Company’s financial position, results of operations and cash flows. PGE makes judgments and interpretations about the application of tax law when determining the provision for taxes. Such judgments include the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. Additionally, treatment of tax benefits and costs for ratemaking purposes could be different than what the Company anticipates or requests from the OPUC, which could have a negative effect on the Company’s financial condition and results of operations.

PGE owns and operates renewable generating facilities and battery storage facilities, which generate federal production tax credits (PTCs) and investment tax credits (ITCs) that PGE uses to reduce its federal tax obligations. The amount of PTCs earned depends on the level of electricity output generated and the applicable tax credit rate. A variety of operating and economic parameters, including adverse weather conditions and equipment reliability, could significantly reduce the PTCs generated by the Company’s wind facilities resulting in a material adverse impact on PGE’s financial condition and results of operations. These PTCs generate tax credit carryforwards that the Company plans to utilize in the future to reduce income tax obligations. If PGE cannot generate enough taxable income in the future to utilize all of the tax credit carryforwards before the credits expire, the Company may incur material charges to earnings. The Inflation Reduction Act of 2022 allows for the sale or transfer of renewable tax credits to other taxpayers. The Company has sold and plans to continue to sell tax credits. PGE’s inability to generate, transfer, or sell these credits could have a material impact on results of operations.

PGE’s results of operations may be also be materially impacted by indemnification obligations to buyers of certain tax credits. These obligations cover potential losses resulting from PGE’s failure to meet PTC and ITC qualifications or transferability requirements under the Internal Revenue Code. While PGE is not responsible for losses due to the buyer's actions, legal tax status, or changes in tax law, any other circumstances leading to indemnification could significantly affect the Company's results of operations.

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

ECONOMIC, FINANCIAL, AND MARKET RISKS

A change in forecasted customer demand for electricity may negatively impact PGE’s business.

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

Customer demand could also be negatively impacted by PGE’s ability to attract and retain customers, mandated energy efficiency measures, demand side management programs, potential formation of community choice aggregation programs, distributed generation resources and small scale generation projects, and economic and demographic conditions, such as population changes, job and income growth, new construction, new business formation and the overall level of economic activity. Development, improvement, and adoption of technological advances could lead to declines in energy use per customer. Some or all of these factors could impact the demand for electricity.

The decline in revenues due to decreased customer demand for electricity may increase customer prices for remaining customers, as PGE’s revenue requirement is designed to cover its fixed utility operating expenses. Increased customer prices could further reduce customer demand for electricity and strain PGE’s ability to attract and retain customers. The loss of customers, the inability to replace those customers with new customers, and the decrease in demand for electricity could negatively impact PGE’s financial condition and results of operations.

Concerns about high prices for PGE’s customers could negatively impact PGE’s financial condition, results of operations, liquidity, and cash flows.

Prices paid by customers are impacted by commodity prices, operating costs and capital investments. PGE’s capital investment plan, increasing procurement of renewable power and energy storage, and the cumulative impact of other public policy requirements place continuing upward pressure on customers’ prices. Concerns about affordability could cause the regulators to approve lesser amounts in PGE’s ratemaking or cost recovery proceedings, as recently occurred in PGE’s 2025 General Rate Case (2025 GRC) proceeding at the OPUC. Regulators may authorize, and have in the past authorized, lower revenues than PGE requested, which could impact the Company’s ability to timely recover its operating costs. PGE’s level of authorized capital investment could decline as well, resulting in a slower growth in rate base and earnings.

Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan.

Access to capital and credit markets is important to PGE’s ability to operate. The Company expects to issue debt and equity securities, as necessary, to fund its future capital requirements. Volatility of interest rates could negatively impact PGE’s cost of debt and results of operations. In addition, contractual commitments and regulatory requirements may limit the Company’s ability to delay or terminate certain projects.

If the capital and credit market conditions in the United States and other parts of the world deteriorate, the Company’s future cost of debt and equity capital, as well as access to capital markets, could be adversely affected. In addition, sales or issuances of substantial amounts of PGE’s common stock in the public market could cause the market price of PGE’s common stock to decline. This could impair the Company’s ability to raise additional capital through the sale of equity securities. Future sales or issuances of common stock or other equity-related securities could be dilutive to holders of common stock and could adversely affect their voting and other rights and economic interests.

PGE expects to raise additional capital in the future. PGE may raise additional funds through public or private equity or debt offerings or other financings, as well as additional borrowings under existing credit facilities.

Any new debt financing entered into may involve covenants that restrict operations more than PGE’s current outstanding debt and credit facilities. These restrictive covenants could include limitations on additional borrowings, specific restrictions on the use of assets, and prohibitions or limitations on the Company’s ability to create liens, pay dividends, receive distributions from subsidiaries, redeem or repurchase stock or make investments. These factors could hinder the Company’s access to capital markets and limit or delay the ability to carry out the Company’s capital expenditure plan or pursue other opportunities beyond the current capital expenditure plan.

The declaration of future dividends is at the discretion of the Board of Directors and is not guaranteed and, in some circumstances, the payment of dividends may be limited by the terms of PGE’s debt instruments.

PGE has historically paid regular quarterly dividends on common stock. However, the declaration of dividends is at the discretion of PGE’s Board of Directors and is not guaranteed. The amount of common stock dividends, if any, will depend upon results of operations and financial condition, future capital expenditures and investments, the rights of holders of any outstanding shares of preferred stock, and other factors that the Board of Directors considers relevant.

In addition, the terms of the Company’s debt instruments may limit the payment of dividends. Under the Indenture of Mortgage and Deed of Trust, dated July 1, 1945, as amended and supplemented to date, between PGE and Wells Fargo Bank, National Association, so long as any of the First Mortgage Bonds (FMBs) are outstanding, the Company may not pay or declare dividends (other than stock dividends) on common stock or purchase or retire for a consideration (other than in exchange for other shares of PGE’s capital stock or the proceeds from the sale of other shares of capital stock) any shares of capital stock of any class, if the aggregate amount distributed or expended after December 31, 1944 would exceed the aggregate amount of PGE’s net income, as adjusted, available for dividends on common stock accumulated after December 31, 1944. At December 31, 2024, $402 million of accumulated net income, as defined in the Indenture, was available for payment of dividends under this provision.

Adverse changes in PGE’s credit ratings could negatively affect its access to the capital markets and its cost of borrowed funds.

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

In addition, if Moody’s Investors Service (Moody’s) and/or S&P Global Ratings (S&P) reduce their rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, which could have an adverse effect on the Company’s liquidity and ability to participate in the wholesale markets.

Under certain circumstances, banks participating in PGE’s syndicated unsecured revolving credit facility could decline to fund advances requested by the Company or could withdraw from participation in the credit facility, which could adversely affect PGE’s liquidity.

PGE currently has a syndicated unsecured revolving credit facility with several banks for an aggregate amount of $750 million. The revolving credit facility provides a primary source of liquidity and may be used to supplement operating cash flow and as backup for commercial paper borrowings. The revolving credit facility represents commitments by the participating banks to make loans and, in certain cases, to issue letters of credit. The Company is required to make certain representations to the banks each time it requests an advance under the credit facility. However, in the event of a material adverse change in the business, financial condition, or results of operations of PGE, the Company may not be able to make such representations, in which case the banks would not be required to lend. PGE is also subject to the risk that one or more of the participating banks may default on their obligation to make loans under the credit facility.

Adverse capital market performance could result in reductions in the fair value of benefit plan assets and increase the Company’s liabilities related to such plans. Sustained declines in the fair value of the plans’ assets could result in significant increases in funding requirements, which could adversely affect PGE’s liquidity and results of operations.

Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under PGE’s defined benefit pension and other postretirement plans. Sustained adverse market performance could result in lower rates of return for these assets than projected by the Company and could increase PGE’s funding requirements related to the plans. Additionally, changes in interest rates affect PGE’s liabilities under the plans. As interest rates decrease, the Company’s liabilities increase, potentially requiring additional funding.

Performance of the capital markets also affects the fair value of assets that are held in trust to satisfy future obligations under the Company’s non-qualified employee benefit plans, which include deferred compensation plans. As changes in the fair value of these assets are recorded in current earnings, decreases can adversely affect the Company’s operating results. In addition, such decreases can require that PGE make additional payments to satisfy its obligations under these plans.

The volatility of market prices for power and natural gas could adversely affect PGE’s costs and ability to manage its energy supply, which could negatively impact the Company’s liquidity and results of operations.

As part of its normal business operations, PGE purchases and sells power and natural gas in the open market under short- and long-term contracts, which may specify variable prices or volumes. Market prices for power and natural gas are influenced primarily by factors related to supply and demand. These factors generally include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric and wind generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, and changes in technology.

Volatility in these markets can affect the availability, price, and demand for power and natural gas. Disruption in power and natural gas markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect regulatory and legislative processes in unpredictable ways, affect wholesale power prices, and impair PGE’s ability to manage its energy portfolio. Changes in power and natural gas prices can also affect the fair value of derivative instruments and cash requirements to purchase power and natural gas. If power and natural gas prices decrease from those contained in the Company’s existing purchased power and natural gas agreements, PGE may be required to provide increased collateral, which could adversely affect the Company’s liquidity. Conversely, if power and natural gas prices rise, especially during periods when the Company requires greater-than-expected volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated. PGE’s contract positions may not be fully hedged against commodity prices, and hedges or other risk mitigations may not protect against significant losses.

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

PGE has put in place risk management policies, procedures, and controls to identify, quantify, and manage risk, however, these systems, processes, tools, and controls may not prevent material losses. Risk management procedures may not always be followed as intended, may not operate as designed, or may not identify all potential risks, including, without limitation, severe weather or employee misconduct. There is no assurance that PGE’s risk management procedures will be effective in preventing or mitigating losses, and could have a material adverse effect on the Company’s results of operation and financial condition.

Reduced river flows, unfavorable wind conditions, reduced capacity or degradation of solar panels, and forced outages at generating and battery storage facilities can increase the cost of power required to serve customers. The Company could be required to replace energy expected from these sources with higher cost power from other facilities or with wholesale market purchases, which could have an adverse effect on results of operations.

PGE derives a significant portion of its power supply from its own hydroelectric facilities and long-term purchase contracts with certain public utility districts in the state of Washington. Regional rainfall and snowpack levels affect river flows and the resulting amount of energy generated by these facilities. Shortfalls in energy expected from lower cost hydroelectric generating resources would require increased energy from the Company’s other generating resources and/or power purchases in the wholesale market, which could have an adverse effect on results of operations.

PGE also derives a portion of its power supply from wind generating resources, for which the output is dependent upon wind conditions. Unfavorable wind conditions could require increased reliance on power from the Company’s thermal generating resources or power purchases in the wholesale market, both of which could have an adverse effect on results of operations.

Forced outages at generating facilities and battery storage facilities, both PGE-owned or under purchased power agreements, could result in power costs greater than those included in customer prices, in addition to increased repair and maintenance costs.

Although the application of the PCAM or specific contract terms could help mitigate adverse financial effects from any decrease in power supply, full recovery of any increase in power costs is not assured. Inability to fully recover such costs in future prices could have a negative impact on the Company’s results of operations, as well as a reduction in renewable energy credits (RECs) and loss of PTCs related to wind generating resources.

The capacity provided by the Company’s generating resources and third-party purchased power may not be sufficient to meet its customers’ energy demand requirements and may result in increased GHG emissions.

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

Advances in energy technology could make PGE’s business less competitive.

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

The electricity industry is undergoing significant change, including increased deployment of distributed energy resources, technological advancements as described above, and political and regulatory developments. Electric utilities are experiencing increasing deployment of distributed energy resources, such as solar generation, energy storage, electric vehicles and demand response technologies. The deployment of these technologies supports PGE’s decarbonization goals. The growth of new technologies will require modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. A higher penetration of distributed energy resources may result in decreased customer demand, or may have impacts on grid reliability. PGE may be unable to effectively adapt to evolving technologies, may invest in technologies that ultimately prove ineffective, and employees and customers may be unable to adapt to technologies needed to advance decarbonization goals, such as demand response programs at scale. Increased distributed energy resources and renewable energy resources will require new and sustained investments in grid modernization and transmission, and may require the use of traditional generation to provide additional capacity at peak times. If all such costs are not recoverable in prices, PGE could experience material increases in its commodity costs, which could impact PGE’s results of operations, financial condition, or cash flows.

It is also possible that alternative generation or storage resources are mandated, subsidized, or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply. Competitors may not be subject to the same operating, regulatory and financial requirements that the Company is, potentially causing a substantial competitive disadvantage for PGE. Changes in public policy, such as new tax incentives that PGE cannot take advantage of or efforts to deregulate the utility industry, could provide an advantage to competitors. Such alternative resources and regulatory or legislative actions could displace higher marginal cost generating units or make PGE less competitive in constructing, owning, and operating such facilities. Such a development could limit the Company’s future growth opportunities and limit growth in demand for PGE’s electric service.

Changes in market conditions and environmental laws and regulations could negatively impact PGE’s non-utility real estate investments.

PGE owns, through a wholly owned subsidiary, its corporate headquarters building located in Portland, Oregon. A significant change in real estate values could adversely affect PGE’s results of operations.

PGE also owns unregulated properties that are currently or previously leased to third parties and located adjacent to PGE’s T.W. Sullivan hydro generating facility. PGE has recorded a non-utility asset retirement obligation (ARO) for this site related to assets that are no longer in service. Significant changes in estimates for this non-utility ARO due to changes in environmental laws or regulations could adversely affect PGE’s results of operations.

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

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

PGE is committed to the success of its ESG programs; however, if the Company fails to adapt or execute on its ESG strategies, or is perceived to have failed in addressing stakeholder ESG expectations or standards, which continue to evolve, PGE may suffer reputational damage, which could have a material adverse effect on its business, results of operations, and financial condition. If efforts around diversity, equity and inclusion are perceived to be insufficient or overdone, PGE may not be able to attract or retain talent, and may be subject to investigations, litigation, and other proceedings. Additionally, the cost of implementing and complying with such ESG programs could be material.

Actions of activist shareholders could have a negative impact on PGE’s business.

Actions of activist shareholders, which can take many forms and arise in a variety of situations, could include engaging in proxy solicitations, advancing shareholder proposals, or otherwise attempting to effect changes and assert influence on the Company’s Board of Directors and management. Dealing with such actions could result in disruption to company operations, and divert management’s and the Company’s board’s attention and resources from PGE’s business and execution of its strategy.

Such shareholder activism could give rise to perceived uncertainties regarding PGE’s future, adversely affecting PGE’s business opportunities, ability to access capital markets, relationships with its customers and employees, and make it more difficult to attract and retain a qualified workforce. Any such actions could have a material adverse effect on the Company’s financial condition and results of operations and could cause fluctuations in the trading prices of its common stock based on market perceptions or other factors.

PGE’s business activities are concentrated in one region and future performance may be affected by events and factors unique to Oregon or the region.

The Company’s industry and geographic concentrations may increase exposure to risks arising from regional regulation or legislation, such as legislative action related to carbon emissions. These concentrations may also increase exposure to credit and operational risks due to counterparties, suppliers, and customers being similarly affected by changing conditions.

PGE considers cybersecurity to be a top enterprise risk in PGE’s enterprise risk management program, and manages the risk by adhering to established security policies and governance, identifying risk through risk assessments, utilizing technology to provide a layered security approach, controlling access, robust security awareness training and conducting resiliency exercises. As a utility with critical infrastructure, both cyber and physical security will continue to be an important consideration for the Company’s future strategy and operations. The Company maintains a cybersecurity program, overseen by a cross-functional executive committee, that uses a risk-based methodology to support the security of its systems. Additional information about cybersecurity risks and the potential impact to the Company can be found in Item 1A.—“Risk Factors.” The Company has not experienced a material cybersecurity incident.

PGE utilizes the cybersecurity framework established by the National Institute of Standard and Technology (NIST) to manage cybersecurity risk. The NIST Cybersecurity Framework provides the foundation for a comprehensive view of the lifecycle for managing cybersecurity risk.

An enterprise-wide management group operates to evaluate the cybersecurity program’s effectiveness. The Company has an employee who functions as a Chief Security Officer, whose responsibilities include cybersecurity and who has a reporting relationship to senior management. This employee has had a twenty-five year career with the Federal Bureau of Investigation (FBI) prior to joining the Company. She served as the Confidential Advisor to the Director of the FBI, providing strategic advice across all threats allowing her to develop unique and key insights into the global cyber threat landscape, FBI cyber strategy, and cyber operations. Prior to joining the Company, she served as the Special Agent in Charge of the FBI Jacksonville Division where she led all FBI cyber investigations and operations for nation state and criminal actors.

PGE has a management-level committee, the Integrated Security Executive Committee (ISEC), specifically dedicated to cybersecurity and risk issues. The ISEC meets twice each quarter and reviews risks, processes, and strategies related to cybersecurity. Members of the ISEC include the Chief Information Officer, the Chief Operating Officer, the Chief Executive Officer, and the Chief Legal and Compliance Officer. In addition, as a top enterprise risk, cybersecurity is also reviewed by the Company’s management-level Executive Risk Committee on an annual basis, or more frequently if circumstances warrant. This broader review allows the cybersecurity risk and mitigations to be aligned with other enterprise risks, including identifying areas of overlap. Members of the Executive Risk Committee include: the Chief Executive Officer, the Chief Legal and Compliance Officer, the Chief Financial Officer, the Chief Operating Officer, the Chief Information Officer, the Senior Vice President of Strategy and Advanced Energy Delivery, and the Vice President of Energy Supply and Regulatory Affairs.

The Audit and Risk Committee of the Board of Directors has oversight of cybersecurity risk and receives briefings on a quarterly basis. The briefings are provided either by the cybersecurity team, together with a senior member of management, or are presented as part of the Audit and Risk Committee’s regular review of top enterprise risks, in which cybersecurity risk is reviewed annually or more frequently if circumstances warrant. The Audit and Risk Committee briefs the full Board of Directors at each meeting. In addition, the full Board of Directors has participated in cybersecurity exercises. The Audit and Risk Committee is also provided with information about external assessment results and action plans. There is a process in place to notify the Audit and Risk Committee promptly in the event of a material cybersecurity incident.

PGE has a threat intelligence and insider risk program to stay abreast of emerging cybersecurity threats. The Company’s threat identification process begins with the development of an inventory of critical enterprise processes and critical assets, which allows the Company to prioritize focus in the event of a threat. PGE’s Security Operations Center detects unauthorized entities and actions on the networks and in the physical environment, including personnel activity. Processes are tested regularly, through reviews, audits, and assessments. In addition, cyber security resiliency is enhanced through regular functional and tabletop exercises.

PGE manages third party cybersecurity risk by conducting due diligence to identify risks from third parties; requiring review and approval before onboarding a third party. Any third party that fails to meet the Company’s security requirements is subjected to additional risk screenings. PGE may decide not to move forward with a vendor that does not meet security requirements. The Company also has procured cybersecurity insurance.

All employees are required to take annual cybersecurity awareness training. The Company conducts monthly phishing campaigns in which employees are expected to report suspicious emails. If employees click on the training phishing email, they are provided immediate feedback on how to avoid phishing, in addition to being required to complete additional training. Quarterly security awareness is provided to all employees and focuses on cyber and physical security best practices.

PGE engages a third party to attempt to penetrate its systems periodically. These assessments support a continuous improvement initiative, ensuring ongoing enhancements to security posture. As a NERC registered entity, PGE is audited triennially by WECC on cybersecurity practices. The most recent audit concluded in 2023.

PGE’s principal property, plant, and equipment are generally located on land owned by the Company or land under the control of the Company pursuant to existing leases, federal or state licenses, easements, or other agreements. In some cases, meters and transformers are located on customer property. The Indenture securing the Company’s FMBs constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.

Generating Facilities

The following are generating facilities owned by PGE as of December 31, 2024 (in MW):

(1) Represents net capacity of generating unit as demonstrated by actual operating or test experience, net of electricity used in the operation of a given facility.

(2) Represents nameplate ratings. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer.

(3) Represents most favorable operating conditions which refers to the set of optimal circumstances under which a power plant or energy generation system can achieve its maximum output capacity efficiently and reliably.

(4) Represents PGE’s ownership share.

(5) PGE has a 20% ownership interest in the facility, which is operated by Talen Montana, LLC.

(6) PGE has a 50.01% ownership interest in the Pelton/Round Butte hydroelectric project.

PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the FPA. The licenses for the hydroelectric projects on the three different rivers expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055.

Energy Storage Facilities

The following are energy storage facilities owned by PGE as of December 31, 2024 (in MW):

Transmission and Distribution

PGE owns or has contractual rights associated with transmission lines that deliver electricity from its generation facilities to its distribution system in its service territory and also to the Western Interconnection. As of December 31, 2024, PGE-owned electric transmission system consisted of 1,269 circuit miles as follows: 287 circuit miles of 500 kV line; 418 circuit miles of 230 kV line; and 564 miles of 115 kV line. The Company also has 29,398 circuit miles of distribution lines that deliver electricity to its customers. PGE also has an ownership interest in, and capacity on, the following:

• 14% of the 2,260 MW transmission facilities between the Colstrip switchyard to the Broadview switchyard, near Billings, Montana, and 16% of the 1,930 MW transmission facilities between the Broadview switchyard and the interconnection point with BPA’s transmission system near Townsend, Montana; and
• 20% of the Northwest AC Intertie, a 4,800 MW transmission facility between the John Day Substation near the Columbia River in northern Oregon, and Malin, Oregon, near the California border. The Northwest AC Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.

In addition, the Company has contractual rights to a total of 4,150 MW of BPA’s transmission systems, and 300 MW of Northwestern Energy’s transmission systems.

Non-utility Real Estate

PGE owns, through a wholly owned subsidiary, its corporate headquarters building located in Portland, Oregon. As of December 31, 2024, the non-utility property, plant, and equipment balance, net of accumulated depreciation was $73 million, recorded in Other noncurrent assets on the Company’s consolidated balance sheets in Item 8.— “Financial Statements and Supplementary Data.”

PGE also owns unregulated properties that are currently or previously leased to third parties and located adjacent to PGE’s T.W. Sullivan hydro generating facility. PGE has recorded a non-utility ARO related to this site. For more information regarding the Company’s AROs, see “Asset Retirement Obligations” within the “Critical Accounting Policies and Estimates” section of Item 7.— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data.”

See Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data,” for information regarding legal proceedings.

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

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

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,

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.

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

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.

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.

2023 RFP Final Shortlist

(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.

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 (http://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:

• *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.

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.

***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.

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.

***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;
• 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 (http://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

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.

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 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

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

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 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.”

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.

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 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.

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.

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

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.

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.

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 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

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 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 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.

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.”

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations, or cash flows, as discussed below.

Energy Risk Management

PGE has an Executive Risk Committee (ERC) whose primary purpose is to oversee, guide, and support the prudent management of the Company’s risks, as well as review and recommend energy portfolio risk limits that are subject to approval by the Audit and Risk Committee of the PGE Board of Directors. The ERC’s responsibilities include risk reporting to provide visibility into portfolio risk and manage alignment with the Company’s risk strategy and tolerances, providing oversight of the adequacy and effectiveness of corporate policies, guidelines, and procedures for market, liquidity, and credit risk management related to the Company’s energy portfolio management activities. The ERC consists of officers and Company representatives with responsibility for risk management, finance and accounting, information technology, utility operations, legal, and rates and regulatory affairs.

Commodity Price Risk

PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company engages in price risk management activities to manage exposure to volatility in net power costs for its retail customers. The Company uses power purchase and sale contracts to supplement its own generation and to respond to fluctuations in the demand for electricity and variability in generating plant operations. The Company also enters into contracts for the purchase of fuel for the Company’s natural gas- and coal-fired generating plants, and the sale of natural gas in excess of amounts needed for the Company’s natural gas-fired generating plants. These contracts for the purchase of power and fuel expose the Company to market risk. The Company uses instruments such as: i) forward contracts, which may involve physical delivery of an energy commodity; ii) financial swap and futures agreements, which may require payments to, or receipt of payments from, counterparties based on the differential between a fixed and variable price for the commodity; and iii) option contracts to mitigate risk that arises from market fluctuations of commodity prices. The Company does not intend to engage in trading activities for non-retail purposes.

Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized losses recorded as of December 31, 2024 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

PGE reports energy commodity derivative fair values as a net asset or liability, which combines purchases and sales expected to settle in the years noted above. Energy commodity fair values exposed to commodity price risk are primarily related to purchase contracts, which are slightly offset by sales.

PGE’s energy portfolio activities are subject to regulation, with related costs included in retail prices approved by the OPUC. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and liabilities to reflect the effects of regulation, significantly mitigating commodity price risk for the Company. As contracts are settled, these deferrals reverse and are recognized as Purchased power and fuel or Revenues, net in the statements of income and expected to be included in the PCAM. PGE remains subject to cash flow risk in the form of collateral requirements based on the value of open positions and regulatory risk if recovery is disallowed by the OPUC. PGE attempts to mitigate both types of risk through prudent energy procurement practices.

Foreign Currency Exchange Rate Risk

PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE employs a hedging strategy to mitigate its exposure to fluctuations in the Canadian exchange rate.

As of December 31, 2024, a 10% change in the value of the Canadian dollar would result in an immaterial change in exposure for transactions that will settle over the next twelve months.

Interest Rate Risk

To meet short-term cash requirements, PGE has the ability to issue commercial paper for terms of up to 270 days and has a revolving credit facility that permits same day borrowings. Although any borrowings under the commercial paper program or the revolving credit facility carry a fixed rate during their respective terms, the short-term nature of such borrowings subjects the Company to fluctuations in interest rates that result from changes in market conditions. As of December 31, 2024, PGE had no borrowings outstanding under its revolving credit facility and no commercial paper outstanding.

PGE currently has no financial instruments to mitigate risk related to changes in short-term interest rates, including those on commercial paper; however, it may consider such instruments in the future as deemed necessary.

As of December 31, 2024, the total fair value and carrying amounts, excluding unamortized debt expense, by maturity date of PGE’s long-term debt are as follows (in millions):

As of December 31, 2024, PGE had no long-term debt instruments subject to interest rate risk exposure, with the exception of the Unsecured Term Bank Loan which 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 basis points.

Credit Risk

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. The Company manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. PGE also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded as needed to reflect credit risk related to wholesale accounts receivable.

The large number and diversified base of residential, commercial, and industrial customers, combined with the Company’s ability to discontinue service, within certain limits, contribute to reduce credit risk with respect to trade accounts receivable from retail sales. Estimates are used to provide an allowance for uncollectible accounts receivable related to retail sales to address such risk.

As of December 31, 2024, PGE’s credit risk exposure was $16 million for commodity activities, of which $14 million is with externally-rated investment grade counterparties. The underlying transactions that make up the exposure will mature in 2025. The exposure is included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities.

Investment grade counterparties include those with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody’s) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit, and may represent prepayment or credit exposure assurance.

Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington. These contracts currently provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2052. For additional information, see “Public utility districts” in Note 16, Commitments and Guarantees in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Management believes that circumstances that could result in the nonperformance by these counterparties are remote.

(a) Disclosure Controls and Procedures

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are effective.

(b) Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of the end of the period covered by this report pursuant to Rule 13a-15(c) under the Exchange Act. Management’s assessment was based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management has concluded that, as of December 31, 2024, the Company’s internal control over financial reporting is effective.

The Company’s internal control over financial reporting, as of December 31, 2024, has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audits the Company’s consolidated financial statements, as stated in their report included in Item 8.—“Financial Statements and Supplementary Data,” which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2024.

(c) Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.