PORTLAND GENERAL ELECTRIC CO /OR/

Previous wording

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

Current wording

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

Previous wording

uncertainties associated with energy demand that differs from forecasts, including significant or accelerated load growth from new data centers and the concentration of data center load, and the ability to timely serve such growth due to regulatory, environmental, and other permitting requirements;

Current wording

uncertainties associated with energy demand that differs from forecasts, including significant or accelerated load growth from new data centers and the concentration of data center load, and the ability to timely serve such growth due to regulatory proceedings, legislative actions, environmental regulations, permitting requirements, contractual limitations, or cost-allocation mechanisms applicable to large-load customer and data centers;

Previous wording

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

Current wording

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

Previous wording

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

Current wording

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

Previous wording

the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 2, along with “Regulatory Assets and Liabilities”

Current wording

the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 2, along with “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” of this Quarterly Report on Form 10-Q;

Previous wording

ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (PSPS) and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems were involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through prices or insurance, resulting in impact to the financial condition or reputation of the Company;

Current wording

ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (PSPS) or de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems were involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through prices or insurance, resulting in impact to the financial condition or reputation of the Company;

Previous wording

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

Current wording

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

Previous wording

Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 213 thousand residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100% clean and renewable electricity by 2035 and 100% economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have similar goals and continue to consider similar goals for the future.

Current wording

Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 211 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.

Previous wording

These agreements represent the final procurement from the 2023 All-Source RFP. The 2023 RFP is a component of PGE’s multi-pronged procurement approach focused on customer affordability, system reliability, and decarbonization. Both the 2023 RFP reprice and the 2025 RFP disclosed below were designed to capture expiring tax credits to support customer affordability. Additional resources are anticipated to be procured through future acquisition processes, including, but not limited to, PPAs, including a bilateral all-call for PPAs, community-based renewable energy procurement, the ongoing 2025 RFP, and future RFPs.

Current wording

These agreements represent the final procurement from the 2023 All-Source RFP. The 2023 RFP is a component of PGE’s multi-pronged procurement approach focused on customer affordability, system reliability, and decarbonization. Both the 2023 RFP reprice and the 2025 RFP disclosed below were designed to capture expiring tax credits to support customer affordability.

Previous wording

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

Current wording

Together, these procurement activities reflect PGE's diversified approach to meeting growing customer demand, maintaining system reliability, advancing decarbonization objectives, and managing customer costs. The ultimate outcome of the RFP process, or any other additional resource procurement activities outside of the RFP, may involve the selection of multiple projects for both renewable and non-emitting dispatchable capacity resources, which PGE expects will be approximately 2,500 MWs in total.

Previous wording

On May 26, 2026 the OPUC acknowledged the 2025 RFP final shortlist. Additional details of the 2025 RFP (OPUC Docket UM 2371) are available on the OPUC website at www.oregon.gov/puc.

Current wording

Additional information regarding the 2025 All-Source RFP is available in OPUC Docket UM 2371 on the OPUC website at www.oregon.gov/puc.

Previous wording

Nottingham BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project has an estimated commercial operation date in 2028, pending OPUC approval of the requested waiver of the competitive bidding rules.

Current wording

Nottingham BESS—a 20-year storage capacity agreement for a 200 MW BESS located in Washington County, Oregon. This project has an estimated commercial operation date in 2028. OPUC approved PGE’s requested waiver of the competitive bidding rules on August 18, 2026.

Previous wording

Wildfire Mitigation—PGE has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC, as required by State law, to coordinate activities across the Company and with State-wide stakeholders. In December 2025, PGE filed its 2026-2028 Wildfire Mitigation Plan, which forecasts $47 to $50 million annually in operations and maintenance costs and an additional $70 to $84 million annually in capital investments, for the 2026-2028 period, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the six months ended June 30, 2026, PGE invested $38 million in capital projects related to wildfire mitigation and resiliency and utility asset management.

Current wording

Wildfire Mitigation—PGE has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC, as required by State law, to coordinate activities across the Company and with State-wide stakeholders. In December 2025, PGE filed its 2026-2028 Wildfire Mitigation Plan, which forecasts $47 to $50 million annually in operations and maintenance costs and an additional $70 to $84 million annually in capital investments, for the 2026-2028 period, to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the nine months ended September 30, 2026, PGE invested $59 million in capital projects related to wildfire mitigation and resiliency and utility asset management.

Previous wording

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

Current wording

Virtual Power Plant (VPP)—PGE’s VPP is comprised of Distributed Energy Resources and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) charging solutions support grid reliability and increase portfolio flexibility and resource diversity. When coordinated through the Company’s Distributed Energy Resources Management Systems, these resources can be forecasted, dispatched, and measured to support grid reliability and decarbonization goals, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. As PGE integrates technologies to increase orchestration of these resources, they continue to contribute to reliability and help reduce customer exposure to scarcity pricing in energy markets, benefiting participating and non-participating customers.

Previous wording

Grid Enhancing Technologies (GETs)—Limited network upgrades or non-wires solutions are important strategies that offer incremental improvements and can unlock capacity on existing transmission paths in the region. GETs include advanced conductors and coatings, topological optimization, and dynamic line ratings. PGE is actively incorporating GETs across its system to further increase the performance of new and existing transmission assets. These efforts, when deployed across a number of areas and assets, have the potential to add incremental capacity to the grid at lower costs.

Current wording

Grid Enhancing Technologies (GETs)—Network upgrades or non-wires solutions are important strategies that offer improvements and can unlock capacity on existing transmission paths in the region. GETs include advanced conductors and coatings, topological optimization, and dynamic line ratings. PGE is actively incorporating GETs across its system to further increase the performance of new and existing transmission assets. These efforts, when deployed across a number of areas and assets, have the potential to add incremental capacity to the grid at lower costs.

Previous wording

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

Current wording

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

Previous wording

Trade Tariffs—U.S. trade policy and tariff measures continue to evolve through a combination of existing and newly implemented tariff programs, ongoing litigation, and potential future trade actions. These evolving measures may increase the cost of raw materials and equipment, disrupt global supply chains, and contribute to volatility in commodity, capital, and credit markets. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase, which could affect materials and supplies balances and increase capital projects costs. Similarly, procurement costs may rise and lead times may lengthen for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. Although PGE does not expect a material impact on its Canadian natural gas imports from recent Canada-related actions, future trade actions involving Canada could affect commodity markets, supply chains, or procurement costs. Recent tariff actions affecting particular countries and product categories, as well as the possibility of additional trade measures, have increased uncertainty regarding future equipment costs and supply availability. The Company is unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, as those effects could include project delays and cost increases, and present obstacles to PGE’s strategic plan execution. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.

Current wording

Trade Tariffs—U.S. trade policy and tariff measures continue to evolve through a combination of existing and newly implemented tariff programs, ongoing litigation, and potential future trade actions. These evolving measures may increase the cost of raw materials and equipment, disrupt global supply chains, and contribute to volatility in commodity, capital, and credit markets. The cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase, which could affect materials and supplies balances and increase capital projects costs. Similarly, procurement costs may rise and lead times may lengthen for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. Although PGE does not expect a material impact on its Canadian natural gas imports from existing Canada-related policies and tariffs, future trade actions involving Canada could affect commodity markets, supply chains, or procurement costs. Evolving tariff policies affecting particular countries and product categories, as well as the possibility of additional trade measures, have increased uncertainty regarding future equipment costs and supply availability. The Company is unable to reasonably estimate the effects of the rapidly changing trade tariff landscape, as those effects could include project delays and cost increases, and present obstacles to PGE’s strategic plan execution, capital investments, and resource development initiatives. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.

Previous wording

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

Current wording

In October 2025, PGE received notice from the U.S. DOE of the termination of four federal grants that originally planned to provide $61 million in federal reimbursement over the life of the grants. PGE has incurred an immaterial amount of costs for projects associated with the terminated grants and does not expect the termination process to result in a material impact on the Company’s financial position and results of operations. The U.S. DOE has subsequently communicated the potential to reinstate financial assistance related to PGE’s Grid Edge Devices grant, which would provide approximately $45 million in total funding. PGE is evaluating the terms and considerations associated with reinstatement of the grant.

Previous wording

PGE has entered into agreements to transfer tax credits and transferred $12 million and $13 million, net of discounts, for cash proceeds in the first six months of 2026 and 2025, respectively. PGE transferred tax credits, net of discounts, of $179 million in 2025. For the remainder of 2026, the Company expects to generate and transfer approximately $25 million of additional tax credits, net of discounts.

Current wording

PGE has entered into agreements to transfer tax credits and transferred $23 million and $153 million, net of discounts, for cash proceeds in the first nine months of 2026 and 2025, respectively. PGE transferred tax credits, net of discounts, of $179 million in 2025. For the remainder of 2026, the Company expects to generate and transfer approximately $15 million of additional tax credits, net of discounts.

Previous wording

During the second quarter of 2026, the Company submitted its RPS report for 2025, which indicated that the Company met the threshold for 2025. The report remains subject to final review by the Oregon Department of Energy. PGE believes it is on track to meet the RPS threshold for 2026.

Current wording

During the second quarter of 2026, the Company submitted its RPS report for 2025, which indicated that the Company met the threshold for 2025. The OPUC found the Company in compliance for 2025 on September 15, 2026, through Order 26-345. PGE believes it is on track to meet the RPS threshold for 2026.

Previous wording

HB 3179—In response to increasing utility bills and concerns about affordability, the Oregon Legislature in 2025 passed HB 3179. Under the provisions of the legislation, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multi-year rate plan (MRP) on a regular interval that is no less than three and no more than seven years long. The OPUC issued Order 26-191 on May 26, 2026, that began formal rulemaking in docket AR 677. In the proposed rules identified in Order 26-191, the OPUC is seeking to establish an initial filing schedule for MRPs, which calls for PGE to file its first MRP no earlier than May 1, 2029 and no later than July 31, 2029. The OPUC has also opened a docket, AR 676, as a multi-phased rulemaking to establish the MRP framework with a target to complete the framework in early 2027.

Current wording

HB 3179—In response to increasing utility bills and concerns about affordability, the Oregon Legislature in 2025 passed HB 3179. Under the provisions of the legislation, the OPUC shall balance the interests of the utility investor and the consumer by considering the cumulative economic impact of the proposed price or schedule of prices on the electric or natural gas company’s residential customers. Electric or natural gas companies are required to file a multi-year rate plan (MRP) on a regular interval that is no less than three and no more than seven years long. The OPUC issued Order 26-191 on May 26, 2026, that began formal rulemaking in docket AR 677. In the proposed rules identified in Order 26-191, the OPUC is seeking to establish an initial filing schedule for MRPs, which calls for PGE to file its first MRP no earlier than

Previous wording

GHG regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA);

Current wording

GHG regulations under section 111 of the Clean Air Act (CAA) for new, modified, and reconstructed fossil fuel-fired combustion turbines and for existing fossil fuel-fired steam generating units, including coal-based units;

Previous wording

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

Current wording

Updated Mercury and Air Toxics Standards (MATS), pursuant to section 112 of the CAA, which established revised emission standards for filterable particulate matter at existing coal fired generating units.

Previous wording

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

Current wording

In April 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to CAA section 112(i)(4) from specified requirements of the 2024 MATS amendments. Colstrip subsequently received an exemption from the otherwise applicable July 8, 2027 compliance date through July 8, 2029, and environmental groups filed court challenges to the exemptions. In February 2026, the EPA finalized repeal of the relevant 2024 MATS amendments effective April 27, 2026. That repeal has subsequently been challenged in litigation. The practical significance of the Colstrip exemption and the related challenges depends on the outcome of both the litigation concerning the exemption and the litigation challenging EPA’s repeal of the 2024 MATS amendments.

Previous wording

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

Current wording

PGE continues to evaluate the 2024 MATS amendments, the Colstrip compliance exemption, EPA's repeal of the relevant MATS requirements, and the related litigation to assess the potential impact, which could be material, on the Company’s continuing investment in Colstrip. If EPA's repeal is vacated or otherwise reversed and the 2024 MATS amendments are reinstated, the applicability and timing of those requirements would depend in part on the outcome of the litigation concerning the Colstrip exemption. Reinstatement of the 2024 requirements could require material upgrades at Colstrip on a schedule that may not be achievable or could require the use of technology not yet demonstrated at Colstrip, resulting in significant costs related to the facility.

Previous wording

In addition to the EPA’s proposed rulemakings, several legal challenges have been filed regarding these rules and the revocation of the endangerment finding. In challenges to all three rules, at the EPA’s request, the courts have granted stays to allow new EPA leadership to reevaluate the rule. The endangerment finding revocation has not been stayed, and went into effect April 20, 2026, while the legal challenges are pending. These challenges, or attempts by the federal government to withdraw or modify the regulations, if successful, could affect the applicability to PGE and Colstrip, specifically. Given the uncertainty surrounding applicability of these laws and regulations, PGE cannot reasonably estimate the impact to its results of operations, financial position, and cash flows, however, if the MATS Rule and GHG Rule are ultimately enforced, it could require material additional compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.

Current wording

Legal challenges have been filed concerning the 2024 rules, the subsequent repeal actions, the MATS exemptions, and the rescission of the endangerment finding. Courts previously denied requests to stay the 2024 GHG and MATS rules. Any later orders holding merits proceedings in abeyance while the EPA reconsidered those rules should not be characterized as stays of the rules themselves. The rescission of the endangerment finding took effect April 20, 2026, and the partial repeal of the 2024 power-plant GHG rule is scheduled to take effect November 16, 2026, while related legal challenges are pending. These challenges, and further federal action to withdraw, modify, or reinstate requirements, could affect the applicability to PGE and Colstrip. Given the uncertainty surrounding these laws and regulations, PGE cannot reasonably estimate the impact on its results of operations, financial position, and cash flows. If prior requirements are reinstated, remaining GHG standards apply, or other requirements impose comparable obligations, PGE could incur material additional compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.

Previous wording

Corporate structure—In July 2025, the Company submitted an application to the OPUC seeking approval of a holding company reorganization. PGE believes it to be in the best interests of its customers and shareholders to update its corporate structure into a holding company structure. The structure currently contemplated involves placing a non-operating corporate entity over the Company’s existing structure. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure and to support reliability planning and economic development.

Current wording

Corporate structure—In July 2025, the Company submitted an application to the OPUC seeking approval of a holding company reorganization. PGE believes it to be in the best interests of its customers and shareholders to update its corporate structure into a holding company structure. The structure contemplated involves placing a non-operating corporate entity over the Company’s existing structure. The intent of the reorganization is to take advantage of the financial flexibility provided by a holding company structure and to support reliability planning and economic development.

Previous wording

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

Current wording

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

Previous wording

General Rate Case - In early August 2026, PGE intends to file with the OPUC a general rate case based on a fiscal July 2026 through June 2027 test year (2027 GRC). The Company's filing will request a $179 million increase in the annual revenue requirement related primarily to deployment of capital since PGE’s last rate case (UE 435) to strengthen and safeguard the grid to meet growing customer demand and bolster reliability. The 2027 GRC, as requested, would result in an approximate 4.8% overall increase relative to currently approved prices. This increase excludes the effects of lower net variable power costs expected in 2027 as reflected in the Annual Power Cost Update Tariff, filed separately, with the OPUC in February 2026 (OPUC Docket UE 465). Based on a recently filed forecast of net variable power costs, customer prices would be expected to fall 2.4% on January 1, 2027, partially offsetting the proposed GRC increase.

Current wording

General Rate Case - On August 4, 2026, PGE filed with the OPUC a general rate case (UE 473) based on a fiscal July 2027 through June 2028 test year (2027 GRC). The Company's requested $179 million increase in the annual revenue requirement related primarily to deployment of capital since PGE’s last rate case (UE 435) to strengthen and safeguard the grid to meet growing customer demand and bolster reliability. The 2027 GRC, as requested, would result in an approximate 4.8% overall increase relative to currently approved prices. This increase excludes the effects of lower net variable power costs expected in 2027 as reflected in the Annual Power Cost Update Tariff, filed separately, with the OPUC in February 2026 (OPUC Docket UE 465). Based on a recently filed forecast of net variable power costs, customer prices would be expected to fall 2.4% on January 1, 2027, partially offsetting the proposed GRC increase.

Previous wording

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

Current wording

In January 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allowed PGE to seek recovery of incremental storm expenses through the previously authorized emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC under Docket UM 2190 for emergency restoration costs related to the January storm. On March 18, 2026, PGE received the OPUC's final order for the storm recovery docket, which included a disallowance for some operating and maintenance costs of $1 million and application of an earnings test. The OPUC ordered the application of an earnings test at 20 basis points below the Company's 2024 allowed return on equity of 9.5% on the deferred storm costs. The application of the earnings test resulted in an additional $3 million reduction of the previously deferred amounts. After application of adjustments per the final order, PGE’s deferred balance as of March 31, 2026 was $44 million, including interest, which began amortizing on April 1, 2026 over a two year period. The deferred balance as of September 30, 2026 was $36 million.

Previous wording

After application of adjustments per the final order, PGE’s deferred balance as of March 31, 2026, related to RCEs was $80 million, which included $78 million related to RCEs deferred in 2024 and $2 million related to RCEs deferred in 2025. The 2024 deferred balance began amortizing into customer prices on April 1, 2026 and is to be collected over a two-year period. On July 1, 2026, under the Company's PCAM, Advice 26-26 was submitted to the OPUC seeking recovery to begin on April 1, 2027 of $2 million in costs deferred during RCEs in 2025. PGE believes the deferred amounts as of June 30, 2026 are probable of recovery.

Current wording

After application of adjustments per the final order, PGE’s deferred balance as of September 30, 2026, related to RCEs was $65 million, which included $63 million related to RCEs deferred in 2024 and $2 million related to RCEs deferred in 2025. The 2024 deferred balance began amortizing into customer prices on April 1, 2026 and is being collected over a two-year period. On July 1, 2026, under the Company's PCAM, Advice 26-26 was submitted to the OPUC seeking recovery to begin on April 1, 2027 of $2 million in costs deferred during RCEs in 2025. PGE believes the deferred amounts as of September 30, 2026 are probable of recovery.

Previous wording

Order 25-075 also adopted conditions to be applied to the AUT and clarification of the applicability of those conditions was subsequently provided by the OPUC in Order 25-223, which granted certain of PGE’s requests and denied others. PGE and NewSun Energy LLC, as an intervenor, both have Petitions for Judicial Review of Order 25-075 pending at the Oregon Court of Appeals. For the period of January 1, 2025 through December 31, 2025, PGE deferred an additional net $13 million regulatory liability, which was approved for recovery and began amortizing on April 1, 2026 over a twelve-month period. As of June 30, 2026, there was $9 million deferred as a regulatory liability in the balancing account.

Current wording

Order 25-075 also adopted conditions to be applied to the AUT and clarification of the applicability of those conditions was subsequently provided by the OPUC in Order 25-223, which granted certain of PGE’s requests and denied others. PGE and NewSun Energy LLC, as an intervenor, both have Petitions for Judicial Review of Order 25-075 pending at the Oregon Court of Appeals. For the period of January 1, 2025 through December 31, 2025, PGE deferred an additional net $13 million regulatory liability, which was approved for recovery and began amortizing on April 1, 2026 over a twelve month period. As of September 30, 2026, there was $6 million deferred as a regulatory liability in the balancing account.

Previous wording

In October 2025, the OPUC issued an Order (Order 25-417) that was supported by a memorandum of understanding (MOU) entered into between PGE and key regulatory stakeholders. One key item in the Order was the adoption of an earnings test for the twelve-month period ended October 31, 2026 at PGE’s authorized return on equity (ROE), implemented via a deferral to track Seaside revenues and refund excess earnings, if applicable. The Company has contested the applicability of an earnings test and in addition has not accrued any refunds, as it currently does not forecast to over earn for the period covered by the test.

Current wording

In October 2025, the OPUC issued an Order (Order 25-417) that was supported by a memorandum of understanding (MOU) entered into between PGE and key regulatory stakeholders. One key item in the Order was the adoption of an earnings test for the twelve-month period ended October 31, 2026 at PGE’s authorized return on equity (ROE), implemented via a deferral to track Seaside revenues and refund excess earnings, if applicable. The Company has contested the applicability of an earnings test and in addition has not accrued any refunds, as it currently does not forecast to over earn for the period covered by the test. Such refunds would be recognized as a charge to earnings.

Previous wording

Of the $15 million of revenue requirement adjustments, approximately 87% were temporary in nature, allowing PGE to seek recovery of associated investments as applicable in its next GRC. These adjustments were driven primarily by non-distribution investments and were not attributable to specific assets. Per the previously noted MOU reached with stakeholders, the earliest possible rate effective date of PGE's next GRC would be May 1, 2027.

Current wording

Of the $15 million of revenue requirement adjustments, approximately 87% were temporary in nature, allowing PGE to seek recovery of associated investments as applicable in its next GRC. These adjustments were driven primarily by non-distribution investments and were not attributable to specific assets. On August 4, 2026, PGE filed the 2027 GRC with a requested rate effective date of July 1, 2027.

Previous wording

The OPUC's final order in Docket UE 459, issued on March 11, 2026, approved the terms of the stipulation, which were reflected in customer prices effective April 1, 2026. The Company has contested the applicability of an earnings test and, in addition, has not accrued any probable and reasonably estimable refunds.

Current wording

The OPUC's final order in Docket UE 459, issued on March 11, 2026, approved the terms of the stipulation, which were reflected in customer prices effective April 1, 2026 and ordered the adoption of an earnings test for the twelve-month period ended March 31, 2027 at PGE’s authorized return on equity (ROE). The Company has contested the applicability of an earnings test and, in addition, has not accrued any probable and reasonably estimable refunds. Any such refunds would be recognized as a charge to earnings.

Previous wording

Portland Harbor Environmental Remediation Account (PHERA) mechanism—PGE has been identified by the EPA as a Potentially Responsible Party (PRP) for the Portland Harbor Superfund Site, however, significant uncertainties remain regarding the scope of remediation, cost allocation among PRPs, and PGE’s potential share of costs. The impact of such costs on the Company's results of operations is mitigated by the OPUC-approved PHERA mechanism, which allows for recovery of eligible costs through third-party proceeds and customer prices, subject to prudency reviews and earnings-test limitations. For further information regarding the PHERA mechanism as well as PGEs current estimated range of potential liability, see "Regulatory Assets and Liabilities" in Note 3, Balance Sheet Components, and “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Current wording

Portland Harbor Environmental Remediation Account (PHERA) mechanism—PGE has been identified by the EPA as a Potentially Responsible Party (PRP) for the Portland Harbor Superfund Site, however, significant uncertainties remain regarding the scope of remediation, cost allocation among PRPs, and PGE’s ultimate share of costs. The impact of such costs on the Company's results of operations is mitigated by the OPUC-approved PHERA mechanism, which allows for recovery of eligible costs through third-party proceeds and customer prices, subject to prudency reviews and earnings-test limitations. For further information regarding the PHERA mechanism as well as PGEs current estimated range of potential liability, see "Regulatory Assets and Liabilities" in Note 3, Balance Sheet Components, and “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Previous wording

The Company signed an implementation agreement and filed tariff changes with the FERC to join the CAISO’s Extended Day-Ahead Market (EDAM), which is expected to build on the success of the western EIM and help provide PGE and its customers additional access to affordable, reliable, and clean energy. In August 2025, the FERC approved PGE’s revisions to its Open Access Transmission Tariff for EDAM participation. In September 2025, the California Legislature approved Assembly Bill 825 (the Pathways Bill), authorizing the CAISO to transition market governance, including the EDAM, to an independent regional organization.

Current wording

The Company signed an implementation agreement and filed tariff changes with the FERC to join the CAISO’s Extended Day-Ahead Market (EDAM), which is expected to build on the success of the western EIM and help provide PGE and its customers additional access to affordable, reliable, and clean energy.

Previous wording

The EDAM, which began operation in May 2026, allows market participants to submit bids for their forecasted energy demand and available generation resources a day ahead of expected use. The EDAM optimizes transmission and resource use across all market participants, enabling access to the lowest-cost resources to meet regional needs. PGE plans to begin participation on October 1, 2026, to leverage existing technology and systems and utilize the Company’s transmission system to connect regional resources, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert Southwest, across a unified market platform.

Current wording

The EDAM, which began operation in May 2026, allows market participants to submit bids for their forecasted energy demand and available generation resources a day ahead of expected use. The EDAM optimizes transmission and resource use across all market participants, enabling access to the lowest-cost resources to meet regional needs. PGE began participation on October 1, 2026, to leverage existing technology and systems and utilize the Company’s transmission system to connect regional resources, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert Southwest, across a unified market platform.

Previous wording

Total retail energy deliveries for the six months ended June 30, 2026 were up 1.8% compared to the six months ended June 30, 2025. While industrial deliveries increased, declines occurred in both the residential and commercial categories.

Current wording

Total retail energy deliveries for the nine months ended September 30, 2026 were up 0.1% compared to the nine months ended September 30, 2025. While industrial deliveries increased, declines occurred in both the residential and commercial categories.

Previous wording

Residential weather-adjusted deliveries decreased 3.3% in the aggregate, driven primarily by a decrease in average usage per customer of 4.2% during the first six months of 2026 compared with 2025, partially offset by an increase in the average number of residential customers of 1%. PGE has observed seasonal shifts in use per customer, such as higher air conditioning penetration in the summer in response to higher cooling degree days, as well as an increased number of rooftop solar installations within its service territory, and continued energy efficiency programs.

Current wording

Residential weather-adjusted deliveries decreased 2.4% in the aggregate, driven primarily by a decrease in average usage per customer of 3.4% during the nine months of 2026 compared with 2025, partially offset by an increase in the average number of residential customers of 1%. PGE has observed seasonal shifts in use per customer, such as higher air conditioning penetration in the summer in response to higher cooling degree days, as well as an increased number of rooftop solar installations within its service territory, and continued energy efficiency programs.