10-K – 2026-02-12 – exc-20251231.htm

Information about our Executive Officers as of February 12, 2026
Exelon

Name Age Position Period
Butler Jr., Calvin G. 56 President and Chief Executive Officer, Exelon 2022 - Present
Chief Operating Officer, Exelon 2021 - 2022
Senior Executive Vice President, Exelon 2019 - 2022
Chief Executive Officer, Exelon Utilities 2019 - 2022

Honorable, Colette 55 Executive Vice President, Chief Legal Officer, Compliance and Corporate Secretary, Exelon 2026 - Present
Chief Legal Officer and Corporate Secretary 2024 - 2025
Executive Vice President, Public Policy 2023 - 2024
Chief External Affairs Officer 2023 - 2024
Partner, Reed Smith LLP 2017 - 2023

Innocenzo, Michael A. 60 Executive Vice President and Chief Operating Officer, Exelon 2024 - Present
President and Chief Executive Officer, PECO 2018 - 2024

Jones, Jeanne 46 Executive Vice President, Chief Finance Officer, Audit and Risk, Exelon 2026 - Present
Executive Vice President and Chief Financial Officer, Exelon 2022 - 2025
Senior Vice President, Corporate Finance, Exelon 2021 - 2022
Senior Vice President and Chief Financial Officer, ComEd 2018 - 2021

Kleczynski, Robert A. 57 Senior Vice President, Controller and Tax, Exelon 2023 - Present
Senior Vice President, Tax, Exelon 2020 - 2023

Peterson, Timothy 49 Executive Vice President, Chief Customer & Technology Officer, Exelon 2026 - Present
Senior Vice President, Chief Technology Officer, Xcel Energy 2019-2026

18

Table of Contents

ComEd

Name Age Position Period
Quiniones, Gil 59 President, ComEd 2024 - Present
Chief Executive Officer, ComEd 2021 - Present
President and Chief Executive Officer, New York Power Authority 2011 - 2021

Levin, Joshua 46 Senior Vice President, Chief Financial Officer & Treasurer, ComEd 2023 - Present
Vice President, Corporate Finance, Planning and Analysis 2021 - 2023
Director of Financial Planning and Analysis, ComEd 2019-2021

Perez, David R. 56 Executive Vice President and Chief Operating Officer, ComEd 2024 - Present
Senior Vice President, Distribution Operations, ComEd 2019 - 2023

Rippie, E. Glenn 65 Senior Vice President and General Counsel, ComEd 2022 - Present
Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon 2022 - Present
Partner, Jenner & Block LLP 2019 - 2022

Washington, Melissa 56 Senior Vice President, Governmental, Regulatory and External Affairs, ComEd 2025 - Present
Senior Vice President, Customer Operations, ComEd
2021 - 2025
Senior Vice President, Governmental and External Affairs, ComEd 2019 - 2021

PECO

Name Age Position Period
Vahos, David 53 President and Chief Executive Officer, PECO 2025 - Present
Senior Vice President, Chief Financial Officer, and Treasurer, PHI 2024 - 2025
Senior Vice President, Chief Financial Officer, and Treasurer, BGE 2016 - 2024

Gay, Anthony 60 Vice President and General Counsel, PECO 2019 - Present

Humphrey, Marissa 46 Senior Vice President, Chief Financial Officer and Treasurer, PECO 2022 - Present
Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE 2021 - 2022

Levine, Nicole 49 Senior Vice President and Chief Operations Officer, PECO 2022 - Present
Vice President, Electrical Operations, PECO 2018 - 2022

Oliver, Douglas 51 Senior Vice President, Governmental, Regulatory and External Affairs, PECO 2023 - Present
Vice President, Governmental and External Affairs, PECO 2019 - 2023

19

Table of Contents

BGE

Name Age Position Period
Olivier, Tamla 53 President and Chief Executive Officer, BGE 2025 - Present
Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE 2021 - 2025
Senior Vice President, Customer Operations, BGE 2020 - 2021

Cloyd, Michael 55 Senior Vice President, Chief Financial Officer, and Treasurer, BGE 2024 - Present
Vice President, Support Services, BGE 2021 - 2024

Dickens, Derrick 61 Senior Vice President and Chief Operating Officer, BGE 2021 - Present
Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE 2020 - 2021

Ralph, David 59 Vice President and General Counsel, BGE 2021 - Present
Associate General Counsel, BGE 2019 - 2021

PHI, Pepco, DPL, and ACE

Name Age Position Period
Anthony, J. Tyler 61 President and Chief Executive Officer, PHI, Pepco, DPL, and ACE 2021 - Present
Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE 2016 - 2021

Bancroft, Anne 59 Vice President and General Counsel, PHI, Pepco, DPL, and ACE 2021 - Present
Associate General Counsel, Exelon 2017 - 2021

Oddoye, Rodney 49 Senior Vice President and Chief Operating Officer 2025 - Present
Senior Vice President, Governmental, Regulatory and External Affairs, PHI, Pepco, DPL, and ACE 2021 - 2025

Cantler, Jaclyn 46 Senior Vice President, Governmental, Regulatory and External Affairs, PHI, DPL, and ACE 2025 - Present
Vice President, Pepco Electric Operations, PHI, Pepco 2024 - 2025
Vice President, Projects and Contracts, PHI, Pepco, DPL, and ACE 2021 - 2024

O'Donnell, Morgan 50 Senior Vice President, Chief Financial Officer, and Treasurer, PHI, Pepco, DPL, and ACE 2025 - Present
Vice President, Regulatory Policy and Strategy, PHI, Pepco and DPL 2021 - 2025

ITEM 1A. RISK FACTORS

Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. A number of these risks, any of which could negatively affect one or more of the Registrants’ future Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, and/or Consolidated Balance Sheets (consolidated financial statements), are captured below. Although the risks are generally organized by category and separately described, many of these risks are interrelated. Additionally, the risks should be considered holistically with other information included in this filing and future filings with the SEC. There may be further risks and uncertainties that are presently known or that are not currently believed to be material that could negatively affect the Registrants' future consolidated financial statements.
20

Table of Contents

Risks Related to Legislative, Regulatory, and Legal Factors
The Registrants' businesses are highly regulated and electric and gas revenue and earnings could be negatively affected by legislative and/or regulatory actions (All Registrants).
Substantial aspects of the Registrants' businesses are subject to comprehensive Federal or state legislation and/or regulation.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs associated with the retail purchase, transmission, and distribution of power and natural gas to their customers.
Fundamental changes in laws or regulations or adverse legislative or regulatory actions affecting the Registrants’ businesses would require changes in their business planning models and operations. Registrants cannot always predict when or whether legislative or regulatory action will occur and may not be able to influence the outcome of legislative or regulatory initiatives.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which leads to uncertainty as to the ultimate result, and which could result in uncertainties in rate case outcomes, and/or introduce time delays in effectuating rate changes (All Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services, adoption of new rate structures and constructs or establishment of new rate cases. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs once the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs, could be adjusted, subject to refund, or disallowed. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return.
In addition to potential timing delays, the Registrants also face other uncertainties in rate proceedings that could impact recovery, including not obtaining anticipated allowed rates of return, allowed capital structures, or allowed return on pension assets, and various other factors.
See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of NERC compliance requirements (All Registrants).
The Utility Registrants as users, owners, and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Utility Registrants were found in non-compliance with the Federal or state mandatory reliability standards,
21

Table of Contents

they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The Registrants are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the way the Registrants conduct their operations and make capital expenditures, including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in several proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Matters and Regulation for additional information.
The Registrants could be negatively affected by federal and state RPS, energy conservation and GHG reduction legislation and regulation, and/or changing customer expectations, along with energy conservation by customers (All Registrants).
Risks include changes to energy systems due to new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state, or federal regulatory requirements intended to reduce GHG emissions and/or mandate implementation of energy conservation programs, including through limitation of the use of natural gas. Changes to current state legislation or the development of Federal legislation that requires the use of low-emission, renewable, and/or alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. In addition, where requirements and compliance mechanisms have previously been established, the withdrawal of such requirements can introduce costs and uncertainty.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart grid, DERs and energy efficiency programs, could increase capital expenditures and could significantly impact the Utility Registrants' consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies for PECO, could cause declines in customer energy consumption and lead to a decline in the Registrants' earnings, if timely recovery is not allowed.
The Registrants also periodically perform analyses of potential energy system transition pathways to reduce economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction legislation and/or regulation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements and such legislation and/or regulation could otherwise adversely affect the Registrants' businesses. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Renewable and Clean Energy Standards and "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" above for additional information.
The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments to estimate their obligations to taxing authorities, which includes general tax positions taken and associated reserves established. Tax obligations include, but are not limited to: income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. All tax estimates could be subject to challenge by the tax authorities. Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax
22

Table of Contents

effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material legal proceedings, claims, and litigation arising out of business operations are summarized in Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict or disrupt business activities.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity could render public service commissions and other regulatory and legislative authorities less likely to view energy companies generally, or the Registrants specifically, in a favorable light, and could cause the Registrants to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements.
Risks Related to Operational Factors
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (All Registrants).
Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt electric transmission and/or electric or natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can occur due to several factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
Regulated utilities, which are required to provide service to all customers within their respective service territories, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
Risks from cybersecurity and physical threats to energy infrastructures and personnel are increasing. Threat actors, including sophisticated nation-state actors and criminal groups, exploit potential vulnerabilities in the electric and natural gas utility industry, grid infrastructure, and other energy infrastructures. Attacks and disruptions, which could involve physical, cyber, and hybrid targeting of physical and cyber assets, are increasingly sophisticated and dynamic. Physical attacks targeting the Registrants' physical assets or personnel could cause injuries, damage, or operational disruptions. The increased implementation of, and reliance on, information technologies and networks to manage business operations, including the operation of technical systems, as well as the Registrants' use of numerous vendors and suppliers, create additional points of vulnerability that could be, and in certain instances have been, exploited by malicious threat actors. Several U.S. government agencies have warned that the energy sector and its supply chains are subject to increasing risks of physical attacks, ransomware attacks and cybersecurity threats, and that the risks may escalate during periods of heightened geopolitical tensions. In addition, the rapid evolution and increased adoption of artificial intelligence technologies may intensify the Registrants' cybersecurity risks.
23

Table of Contents

A security breach of the Registrants' physical assets or information systems or those of the Registrants' competitors, vendors, business partners and interconnected entities (including RTOs and ISOs) could materially impact Registrants by, among other things, impairing the availability of electricity and gas distributed by Registrants and/or the reliability of transmission and distribution systems, damaging grid infrastructure, interrupting critical business functions, impairing the availability of vendor services and materials that the Registrants rely on to maintain their operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, system data and architecture, sensitive customer, vendor, or employee data, or other confidential data. While Registrants and some of the Registrants' vendors have experienced cybersecurity incidents, such incidents have not, to Registrants' knowledge, resulted in material impact to any of the Registrants to date.
If a material physical or cybersecurity breach or disruption were to occur, the Registrants' reputation could be negatively affected, customer confidence in the Registrants could be diminished and the Registrants could be subject to legal claims, regulatory exposure, loss of revenues, and increased costs, including infrastructure repairs or operations shutdown, all of which could materially affect the Registrants' financial condition and materially damage their business reputation. Moreover, the amount and scope of insurance maintained against losses resulting from any such security breaches or disruptions may not be sufficient to cover losses or otherwise adequately compensate for any resulting business disruptions. The continued increase in Federal and state regulatory requirements related to cybersecurity and evolving threat actor-capabilities could require changes to measures currently undertaken by the Registrants or to their business operations and could adversely affect their consolidated financial statements.
The Registrants’ electricity and natural gas operations are inherently hazardous and involve significant risks to employees, contractors, customers, and the general public (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees, contractors, customers, and the general public may face, and in the past have experienced, serious injury, including loss of life, damage to or destruction of facilities and residences, business interruptions, and environmental pollution. These risks include, among others, gas explosions, uncontrolled release of natural gas and other environmental hazards, fires, pole strikes, and electric contact cases. Further, the location of natural gas pipelines and associated distribution facilities, or electric generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, increases the potential damages resulting from these risks.
Extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions, war, acts and threats of terrorism or sabotage, cyberattacks or compromises, equipment or process failures, public health crises, or other significant events could negatively impact the Registrants' results of operations, ability to raise capital and future growth (All Registrants).
The Utility Registrants' infrastructures and/or operations could be affected by extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions or equipment or process failures due to aging infrastructure or otherwise, each of which could result in increased costs, including supply chain costs and claims for third-party property damage. An extreme weather event, natural disaster, wildfire, or operational accident within the Utility Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
The Registrants face a risk that their operations would be direct targets or indirect casualties of attacks or sabotaged by nation-states or their agents, or by foreign or domestic terrorist groups. Responses to such attacks or sabotage, and any resulting retaliatory actions or sustained conflict could affect the Registrants’ operations and finances in unpredictable and material ways. Furthermore, such events could compromise the physical or cybersecurity of the Registrants' facilities, which could adversely affect the Registrants' ability to manage their businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, public health crises, epidemics, pandemics, credit crises, recession, sustained high inflation, or other significant events also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the
24

Table of Contents

implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by public health crises, including epidemics or pandemics. The Registrants have plans in place to respond to such events. However, depending on the severity and the resulting impacts to workforce and other resource availability, a public health crisis, epidemic, or pandemic could adversely affect our vendors, or customers and customer demand as well as the Registrants’ ability to operate their transmission and distribution assets.
In addition, Exelon, on behalf of the Registrants, maintains a level of insurance coverage consistent with industry practices against property, casualty, third party liability, and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, such losses may not be covered under applicable insurance policies, or the amount of insurance may be inadequate to cover all such losses.
The Registrants are subject to risks associated with climate change (All Registrants).
The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic of the United States, areas that historically have been prone to various types of severe weather events, and the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be at greater risk of damage as changes in the global climate affect temperature and weather patterns, including if such climate changes result in more intense, frequent and extreme weather events, elevated or decreased levels of precipitation, sea level rise, increased temperatures, wildfires and/or other effects.
In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations and business.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain, are subject to operational failure and could be impacted by disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs which could result in potential liability (All Registrants).
The Utility Registrants’ businesses are capital intensive and require significant investments in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Utility Registrants’ control, and could require significant expenditures to operate efficiently. Disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs, could materially impact the timing and execution of capital projects, and the timing of placing assets in service, as well as other aspects of the Registrants' businesses. In recent years, the energy industry has been experiencing shortages of, and long lead times for, critical equipment such as transformers and conductors. The Registrants' consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital, or if they are deemed liable for operational failure. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.
Lack of sufficient generation and energy storage to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties could interrupt transmission and distribution services, impair economic development, cause outages, and result in use limitations or affordability implications for customers. (All Registrants)
Exelon does not generate the electricity it delivers. The Utility Registrants purchase, transmit, and distribute electric power obtained from power generation facilities owned by third parties. This power is primarily procured through contracts as directed by the Utility Registrants’ respective state laws and regulatory commission actions from various approved bidders or from purchases on the PJM operated markets. Third-party power generation may be insufficient to meet our customers’ electricity demand in the short- and medium-term because of extreme
25

Table of Contents

weather, fuel security, market procurement, regulatory requirements, operational issues, maintenance outages, inflexibility of demand, or financial uncertainty impacting existing or prospective generation facilities. Faster energy demand growth, acceleration of generator retirements, or the limited entry of new generating resources in any of the Utility Registrants’ respective service territories may result in a longer-term power generation capacity shortfall. Exelon has forecast substantial increases in load, driven largely by the increasing use of data processing facilities dedicated to cloud services, artificial intelligence technologies, and other applications. If third-party power generation capacity is insufficient to meet any Utility Registrant’s customers’ electricity demand or customers’ electricity demand across PJM over any period, transmission and distribution services may be diminished or interrupted, and results of operations, financial condition, and cash flows could be adversely affected.
In the event generation capacity is insufficient to meet demand, the Utility Registrants’ customers may experience greater price volatility, power service outages during peak demand periods or during generation contingencies (e.g., severe storms), and electricity use limits to maintain system balance. Furthermore, the Utility Registrants may be unable to support new economic development should generation constraints last for extended periods.
Energy storage systems provide additional resources for enhancing grid reliability and stability by providing rapid response capabilities, allowing the injection and absorption of power during electric supply and demand imbalances. As forecasted load increases, the lack of sufficient energy storage growth may also lead to greater price volatility and challenges in power services for customers.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by the insufficiency of generation or energy storage resources to meet demand, transmission congestion, and failures of neighboring transmission systems (All Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As is the case for electric utilities generally, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures. Delays in siting, permitting, and interconnection could defer the introduction of new generation or energy storage resources that could address resource adequacy concerns.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas. Additionally, efforts to artificially manipulate power demand on the grid, or even accidental activity that results in sharp fluctuations of demand, could disrupt grid operations.
The Registrants' performance could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).
Certain factors, such as employee strikes, work stoppages, loss of employees, loss of contract resources due to a major event, inability to negotiate future collective bargaining agreements on commercially reasonable terms, an aging workforce, mismatching of skill sets for current and future needs, and failing to appropriately anticipate future workforce needs, could lead to operating challenges and increased costs for the Registrants. Such challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. Such events and other factors could result in increased costs, including costs of replacing lost labor through contractors or new hires, training costs, and costs of lost productivity. Such events also could increase operational risks. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees needed to conduct Registrants' transmission and distribution operations as well as areas where new technologies are pertinent.
The Registrants’ performance could be negatively affected by poor performance of third-party contractors that perform periodic or ongoing work (All Registrants).
26

Table of Contents

The Registrants rely on third-party contractors to perform operations, maintenance, and construction work. Performance standards typically are included in all contractual obligations, but poor performance may impact capital execution plans or operations, or have adverse financial, regulatory, or reputational consequences.
The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).
The Utility Registrants face risks associated with regulator-mandated or other new business initiatives, such as smart grids and broader beneficial electrification. Such risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful, and failures could result in adverse financial or reputational consequences.
Risks Related to Market and Financial Factors
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).
Advancements in power generation technology, including commercial and residential solar generation installations and commercial micro turbine installations, are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Changes in power generation, storage, and use technologies could have significant effects on customer behaviors and their energy consumption.
These developments could affect levels of customer-owned generation, customer expectations, and current business models and make portions of the Utility Registrants' transmission and/or distribution facilities uneconomic prior to the end of their useful lives. Increasing pressure from both the private and public sectors to take actions to mitigate climate change could also push the speed and nature of this transition. These factors could affect the Registrants’ consolidated financial statements through, among other things, increased Operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation over shortened remaining asset useful lives.
The Registrants could be negatively affected by unstable capital and credit markets (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets because of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, or require a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2025, approximately 17%, 11%, and 17% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. Additionally, higher interest rates may put pressure on the Registrants’ overall liquidity profile, financial health and impact financial results. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant
27

Table of Contents

amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants).
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters and Cash Requirements — Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers and the related regulatory limitations on residential service terminations for the Utility Registrants, could result in an increase in the number of uncollectible customer balances and related expense. Further, increases in customer rates, including those related to increases in Purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the Registrants’ credit risk.
The Registrants could be negatively affected by the impacts of weather (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting operating revenues at PECO and DPL Delaware. Due to revenue decoupling, operating revenues from electric distribution at ComEd, BGE, Pepco, DPL Maryland, and ACE and gas distribution at BGE are not intended to be affected by abnormal weather.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each Utility Registrant's ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
28

Table of Contents

Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where the Utility Registrants have transmission and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.
ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 6 — Property, Plant, and Equipment, Note N/A — Asset Impairments, and Note 10 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance (All Registrants).
The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation assets to one or more third parties and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Constellation, Constellation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation assets. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation assets that have been assumed by Constellation as part of the restructuring. If Constellation or a transferee of one of the Utility Registrant’s generation assets experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation assets.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Utility Registrants in connection with Constellation's absorption of their former generating assets. The Registrants could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform if the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
29

Table of Contents

Market performance and other factors could decrease the value of employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Exelon’s employee benefit plan trusts. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below Exelon's projected return rates. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

ITEM 1B. UNRESOLVED STAFF COMMENTS

All Registrants
None.

ITEM 1C. CYBERSECURITY

Risk management and strategy
Cybersecurity risk for all Registrants is managed at the enterprise-level. Management of material risks from cybersecurity threats is integrated into the Registrants' overall risk management processes and is monitored as an enterprise risk. Exelon's Chief Information Security Officer (CISO) and cybersecurity management team regularly hold meetings with senior management of each Registrant, facilitated by Exelon’s enterprise risk management team, to discuss issues pertaining to cybersecurity risk management, including changes in the nature and origin of threats, threat actor and risk mitigation activities, and regulatory developments. Exelon legal and compliance professionals engage with the CISO and cybersecurity management team to address tactical and strategic cybersecurity risks. Exelon monitors cybersecurity risks through key risk indicators to identify potential changes in risk exposure and provide the Board of Directors with information about the monitoring of key risks in connection with its oversight of the Registrants' enterprise risk management system.
The CISO, through Exelon’s Cyber Information and Security Services (CISS), reviews external and internal sources to obtain cyber threat intelligence to develop strategic and tactical threat assessments that inform the enterprise-wide cyber risk mitigation programs and actions. Exelon uses a wide range of tools, including endpoint, anomaly and network detection, logging and monitoring of security events, network segmentation, firewalls, hardening and securing devices, cyber vulnerability detection and patch management, cyber threat hunting, malware forensic analysis, industry-specific reports, and tabletop exercises to inform the cybersecurity management team. Exelon protects assets critical to grid reliability and national security through the implementation of the North American Electric Reliability Corporation’s Critical Infrastructure Protection requirements, and gas pipeline security under the U.S. Department of Homeland Security’s Transportation Safety Administration’s Security Directives. Exelon maintains security relationships with law enforcement and U.S. intelligence agencies, coordinates with the Electricity Information Sharing and Analysis Center (E-ISAC) and participates in the Department of Energy’s Cybersecurity Risk Information Sharing Program (CRISP) to strengthen the security of the energy grid, share information, design and participate in drills and exercises such as the bi-annual Grid Security Exercises and facilitate cross-sector coordination. Exelon applies stringent employee and contractor screening, and advances security awareness through training and monitoring programs that address both cyber and physical threats. Exelon employees are subject to annual mandatory training addressing security awareness, including cybersecurity and phishing. Exelon maintains cyber insurance coverage at limits consistent with the utility industry and reviews policy coverage and limits on an annual basis.
30

Table of Contents

In assessing the effectiveness of its cybersecurity risk management program, the CISO makes use of external perspectives from regulatory compliance audits and inspections, external audits of the Registrants' financial systems, and third-party incident response and detection analytics. Cybersecurity risks associated with the Registrants’ use of certain third-party service providers are evaluated and managed through CISS' Third Party Security team that leverages security risk assessments, contractual terms and conditions, and security awareness training for such providers. Additionally, those providers are required to report cybersecurity incidents, including the unauthorized use or disclosure of Registrants’ confidential information to Exelon’s security operations center. Third Party Security investigates certain third-party cybersecurity events as part of Exelon’s incident response program.
Governance
The Operations, Safety and Customer Experience Committee (OSCC) and Exelon Board of Directors are responsible for oversight of risks from cybersecurity threats. As documented in the Cybersecurity Oversight Policy, the Board of Directors oversees Exelon's cybersecurity program and Exelon’s enterprise-wide risk related to cybersecurity, including management’s identification, assessment, and mitigation of cybersecurity risks. At each regular quarterly meeting, the OSCC engages with the CISO and a cross-functional management team regarding the risks from cybersecurity threats, and the Board of Directors receives reports on cybersecurity risks at least annually. The CISO and professionals from the legal and compliance departments brief the OSCC on relevant topics, including information security and operational security, legislative and regulatory developments, and notable external cyber events relevant to Exelon and the industry more broadly. Management engages with the OSCC and the Board of Directors on risks from cybersecurity threats as appropriate outside of the quarterly meetings.
The CISO manages Exelon's enterprise-wide cybersecurity programs and reports to Exelon’s Chief Information Officer. The CISO has been responsible for assessing and managing material risks from cybersecurity threats at Exelon since 2018 and was named to the current role in 2022. The CISO has 26 years of information technology and cybersecurity experience in the critical infrastructure sector, of which 24 years have been in the utility industry. The CISO leads CISS, which manages centralized information technology and operational technology security programs for the Registrants. The programs are aligned to the National Institute of Standards and Technology Cyber Security Framework (NIST CSF) and integrate cyber asset identification; threat assessment; risk assessment; risk management; and risk monitoring. CISS operates a security operations center for monitoring, identifying, and mitigating potential cybersecurity events or incidents.
Exelon maintains a single, centralized cybersecurity incident response program and plan that aligns with NIST CSF by integrating the identify, determine/classify, escalate and respond functions (which track the lifecycle of an event or incident). Security threats and incidents are identified and assessed to determine potential impact and escalated to senior cybersecurity management and the CISO. The CISO directs the security incident response team to contain, eradicate, and recover from an active threat. Exelon leverages the expertise of dedicated incident response vendors that can provide timely and specialized support to respond and recover from an event. The CISO and a cross-functional team convene as needed to evaluate cybersecurity events, including third-party events. The legal and compliance departments provide incident response support to the CISO, manage cybersecurity-related legal and compliance issues, and direct materiality evaluations using both qualitative and quantitative factors for each Registrant.
Although the Registrants have not experienced any material cybersecurity events to date, cybersecurity threats could materially affect each Registrant’s business strategy, results of operations, or financial condition, as further discussed in the risk factor entitled “The Registrants are subject to physical and cybersecurity risks" in ITEM 1A. of this report.
31

Table of Contents

ITEM 2. PROPERTIES

The Utility Registrants
The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
The Utility Registrants’ high voltage electric transmission lines owned and in service as of December 31, 2025 were as follows:

Voltage Circuit Miles
(Volts) ComEd PECO BGE Pepco DPL ACE
765,000 90 — — — — —
500,000 (a)
— 191 216 109 16 —
345,000 2,678 — — — — —
230,000 — 550 352 794 472 259
138,000 2,268 135 55 61 587 215
115,000 — — 700 26 — —
69,000 — 178 — — 570 675

___________
(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 7 — Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information.
The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines as of December 31, 2025:

Circuit Miles ComEd PECO BGE Pepco DPL ACE
Overhead 35,349 12,972 9,101 4,172 6,014 7,349
Underground 33,180 9,898 18,262 7,412 6,715 3,149

Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles as of December 31, 2025.

PECO BGE DPL
Transmission (a)
6 146 8
Distribution 7,349 7,651 2,183
Service piping 6,590 6,556 1,502
Total 13,945 14,353 3,693

___________
(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware, which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.

32

Table of Contents

The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities as of December 31, 2025.

Registrant Facility Location Storage Capacity
(mmcf) Send-out or Peaking Capacity
(mmcf/day)
PECO LNG Facility West Conshohocken, PA 1,200 195
PECO Propane Air Plant Chester, PA 105 25
BGE LNG Facility Baltimore, MD 1,056 332
BGE Propane Air Plant Baltimore, MD 550 85
DPL LNG Facility Wilmington, DE 250 60

PECO, BGE, and DPL also own 30, 27, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, Pepco, DPL, and ACE are subject to the lien of their respective mortgages under which their respective First Mortgage Bonds are issued. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.

ITEM 3. LEGAL PROCEEDINGS

All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 2 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable
33

Table of Contents

PART II
(Dollars in millions, except per share data, unless otherwise noted)

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Exelon
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2026, there were 1,022,892,585 shares of Common stock outstanding and approximately 68,884 record holders of Common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon Common stock, compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2021 through 2025. Cumulative total returns account for the separation of Constellation, as the spin-off dividend was assumed to have been reinvested upon receipt.
This performance chart assumes:
• $100 invested on December 31, 2020 in Exelon Common stock, the S&P 500 Stock Index, and the S&P Utility Index; and
• All dividends are reinvested.

34

Table of Contents

Value of Investment at December 31,
2020 2021 2022 2023 2024 2025
Exelon Corporation $100.00 $141.41 $153.19 $131.78 $143.93 $172.79
S&P 500 $100.00 $128.71 $105.40 $133.10 $166.40 $196.16
S&P Utilities $100.00 $117.67 $119.51 $111.05 $137.07 $159.06

ComEd
As of January 31, 2026, there were 127,021,422 outstanding shares of Common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. As of January 31, 2026, in addition to Exelon, there were 277 record holders of ComEd Common stock. There is no established market for shares of the Common stock of ComEd.
PECO
As of January 31, 2026, there were 170,478,507 outstanding shares of Common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2026, there were 1,000 outstanding shares of Common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2026, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2026, there were 100 outstanding shares of Common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2026, there were 1,000 outstanding shares of Common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2026, there were 8,546,017 outstanding shares of Common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed, or current earnings. A significant loss recorded at ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these Registrants can distribute to Exelon.
ComEd has agreed, in connection with a financing arranged through ComEd Financing III, that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
35

Table of Contents

PECO has agreed, in connection with financings arranged through PEC L.P. and PECO Trust IV, that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved by the MDPSC and DCPSC that prohibit Pepco from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as calculated pursuant to the MDPSC's and DCPSC's ratemaking precedents, or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved by the DEPSC and MDPSC that prohibit DPL from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as calculated pursuant to the DEPSC's and MDPSC's ratemaking precedents, or (b) DPL’s corporate issuer or senior unsecured credit rating, or its equivalent, is rated by any of the three major credit rating agencies below the generally accepted definition of investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved by the NJBPU that prohibit ACE from paying a dividend on its common shares if (a) after the dividend payment, ACE's common equity ratio would be below 48% as calculated pursuant to the NJBPU's ratemaking precedents, or (b) ACE's senior corporate issuer or senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to notify and obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such event has occurred.
Exelon’s Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.
As of December 31, 2025, Exelon had Retained earnings of $7,577 million, ComEd had Retained earnings of $2,998 million, PECO had Retained earnings of $2,438 million, BGE had Retained earnings of $2,588 million, and PHI had Undistributed losses of $151 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2025 and 2024:

2025 2024
(per share) Fourth
Quarter Third
Quarter Second
Quarter First
Quarter Fourth
Quarter Third
Quarter Second
Quarter First
Quarter

Exelon $ 0.4000  $ 0.4000  $ 0.4000  $ 0.4000  $ 0.3800  $ 0.3800  $ 0.3800  $ 0.3800 

36

Table of Contents

The following table sets forth PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:

2025 2024
(in millions) 4th
Quarter 3rd
Quarter 2nd
Quarter 1st
Quarter 4th
Quarter 3rd
Quarter 2nd
Quarter 1st
Quarter
ComEd $ 203  $ 203  $ 204  $ 203  $ 194  $ 194  $ 194  $ 194 
PECO 136  137  136  137  100  100  100  100 
BGE 99  98  98  98  92  92  92  92 
PHI 162  256  160  132  157  267  164  118 
Pepco 60  109  92  66  73  133  102  51 
DPL 53  59  44  46  58  78  39  45 
ACE 51  88  24  20  27  56  22  22 

First Quarter 2026 Dividend
On February 12, 2026, Exelon's Board of Directors declared a regular quarterly dividend of $0.42 per share on Exelon’s Common stock for the first quarter of 2026. The dividend is payable on Friday, March 13, 2026, to shareholders of record of Exelon as of the close of business on Monday, March 2, 2026.
37

Table of Contents

ITEM 6. [RESERVED]

38

Table of Contents

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

(Dollars in millions except per share data, unless otherwise noted)

Exelon

Executive Overview
Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the Utility Registrants' year ended December 31, 2024 compared to the year ended December 31, 2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K, which was filed with the SEC on February 12, 2025.

Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the year ended December 31, 2025 compared to the same period in 2024. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations by Registrant.

2025 2024 Favorable (Unfavorable) Variance
Exelon $ 2,768  $ 2,460  $ 308 
ComEd 1,147  1,066  81 
PECO 814  551  263 
BGE 578  527  51 
PHI 799  741  58 
Pepco 401  390  11 
DPL 224  209  15 
ACE 188  155  33 
Other (a)
(570) (425) (145)

__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income attributable to common shareholders increased by $308 million and Diluted earnings per average common share increased to $2.73 in 2025 from $2.45 in 2024 primarily due to:
39

Table of Contents

• Favorable impacts of rate increases at ComEd, PECO, BGE, and PHI;
• Favorable weather at PECO;
• Higher return on regulatory assets at ComEd;
• Higher AFUDC at ComEd;
• Lower income tax expense at PECO;
• Lower storm costs at BGE; and
• Impacts of the multi-year plan reconciliation at BGE.
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:
• Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
• Higher depreciation expense at PECO and PHI;
• Higher contracting costs at PECO and PHI;
• Lower transmission peak load due to lower energy demand at ComEd;
• Absence of the Maryland multi-year plan reconciliations at PHI;
• Charitable contributions at Exelon Corporate;
• Lower AFUDC at PHI; and
• Higher income tax expense at Exelon Corporate.
Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items not considered by management to be directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
40

Table of Contents

The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2025 compared to 2024: 

2025 2024
(In millions, except per share data) Earnings per
Diluted Share Earnings per
Diluted Share
Net income attributable to common shareholders $ 2,768   $ 2.73   $ 2,460   $ 2.45  

Asset retirement obligations (net of taxes of $0 and $3, respectively)
(1) —  8  0.01 
Change in FERC audit liability (net of taxes of $1 and $13, respectively)
2  —  42  0.04 
Cost management charge (net of taxes of $0 and $4, respectively) (a)
(1) —  13  0.01 
Environmental costs (net of taxes of $5)
—  —  (13) (0.01)
Regulatory matters (net of taxes of $10) (b)
30  0.03  —  — 
Income tax-related adjustments (entire amount represents tax expense) (c)
1  —  (3) — 

Adjusted (non-GAAP) operating earnings $ 2,801   $ 2.77   $ 2,507   $ 2.50  

__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.

(a) Primarily represents severance and reorganization costs related to cost management.
(b) Represents the disallowance of certain capitalized costs.
(c) In 2024, reflects the adjustment to state deferred income taxes due to change in DPL's Delaware net operating loss valuation allowance. In 2025, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

Significant 2025 Transactions and Developments
At-the-Market Program
During 2025, Exelon issued approximately 16 million shares of Common Stock at a net weighted-average price of $43.24 per share. The net proceeds from the 2025 issuances were $691 million, which were used for general corporate purposes. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
41

Table of Contents

Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois January 17, 2023 Electric $ 1,487  $ 1,045  8.905% December 19, 2024 January 1, 2024
April 26, 2024 (amended on September 11, 2024) Electric $ 624  $ 623  9.89% October 31, 2024 January 1, 2025

PECO - Pennsylvania March 28, 2024 Electric $ 464  $ 354  N/A December 12, 2024 January 1, 2025
Natural Gas $ 111  $ 78 
BGE - Maryland February 17, 2023 Electric $ 313  $ 179  9.50% December 14, 2023 January 1, 2024
Natural Gas $ 289  $ 229  9.45%
Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $ 186  $ 123  9.50% November 26, 2024 January 1, 2025
Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111  $ 45  9.50% June 10, 2024 April 1, 2024
DPL - Maryland May 19, 2022 Electric $ 38  $ 29  9.60% December 14, 2022 January 1, 2023
DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $ 39  $ 28  9.60% April 18, 2024 July 15, 2023
September 20, 2024 (amended September 5, 2025) Natural Gas $ 37  $ 22  9.60% December 17, 2025 January 1, 2026
ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92  $ 45  9.60% November 17, 2023 December 1, 2023
November 21, 2024 Electric $ 109  $ 54  9.60% November 21, 2025 December 1, 2025

42

Table of Contents

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing
Pepco - Maryland October 14, 2025 Electric $ 133  10.50% Third quarter of 2026
DPL - Delaware December 9, 2025 Electric $ 45  10.50% Third quarter of 2027

Transmission Formula Rates
The following total increases/(decreases) were included in the Utility Registrants' 2025 annual electric transmission formula rate updates. All rates are effective June 1, 2025 to May 31, 2026, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Registrant Initial Revenue Requirement Increase (Decrease) Annual Reconciliation Increase (Decrease) Total Revenue Requirement Increase (Decrease) Allowed Return on Rate Base Allowed ROE
ComEd $ 78  $ 49  $ 127  8.13  % 11.50  %
PECO $ 9  $ 13  $ 22  7.54  % 10.35  %
BGE $ 21  $ 21  $ 35  7.53  % 10.50  %
Pepco $ 35  $ 16  $ 51  7.71  % 10.50  %
DPL $ 32  $ (9) $ 23  7.48  % 10.50  %
ACE $ (11) $ (46) $ (57) 7.16  % 10.50  %

ComEd's FERC Audit
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.

Other Key Business Drivers and Management Strategies

Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
43

Table of Contents

Allocation of Income Taxes to Regulated Utilities (All Registrants)
In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.
Legislative and Regulatory Developments
Infrastructure Investment and Jobs Act
On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. In the fourth quarter of 2025, Exelon, ComEd, and BGE elected to decline the previously awarded Middle Mile Grant (MMG) and Exelon and PECO elected to decline the previously awarded Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE) grant. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, PECO, and BGE will continue to evaluate whether to move forward with these projects.
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that are no longer eligible to be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations ineligible to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).
As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately
44

Table of Contents

$49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter of 2025. Additional disbursements from the state of Maryland were received by BGE, Pepco, and DPL on February 3, 2026 for approximately $49 million, $21 million, and $8 million, respectively. These amounts will also be used to reduce residential customer receivables in the first quarter of 2026.
In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to Regulatory assets. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs. As of December 31, 2025, the Regulatory asset has a remaining balance of $10 million.
Residential Universal Bill Credit (Exelon and ACE).
In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the Residential Universal Bill Credit (RUBC), which will be funded by the NJBPU. The program provided a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued all bill credits to residential customers in September and October. As of December 31, 2025, there is no Regulatory liability remaining.
One Big Beautiful Bill Act (All Registrants).
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.

Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Regulatory Accounting (All Registrants)
For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.
45

Table of Contents

The following table illustrates gains (losses) to be included in net income that could result from the elimination of regulatory assets and liabilities and charges against OCI related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as Regulatory assets in Exelon's Consolidated Balance Sheets (before taxes) at December 31, 2025:

(In millions) Exelon ComEd PECO BGE PHI Pepco DPL ACE
Gain (loss) $ 4,482  $ 6,727  $ (758) $ (353) $ (1,083) $ (306) $ 72  $ (467)
Charge against OCI (a)
(2,911) —  —  —  —  —  —  — 

___________
(a) Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $346 million, $298 million, $214 million, and $75 million, related to ComEd's, BGE's, PHI's, Pepco's, and DPL's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability (before taxes) of $86 million and $6 million related to PECO's and ACE's portions of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities of the Registrants.
For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.
Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution MRP and formula rate mechanisms for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.
Revenues (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, and Alternative Revenue Program accounting guidance to recognize revenues as discussed in more detail below.
Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.
The determination of the Registrants' power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
46

Table of Contents

Alternative Revenue Program Accounting. Certain of the Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, the Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its distribution multi-year rate plan, distribution revenue decoupling mechanisms, and formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Income Taxes (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Allowance for Credit Losses on Customer Receivables (All Registrants)
The Registrants allowance for credit losses on customer receivables is estimated based on historical experience, current conditions, and forward-looking risk factors. Historical experience considered include
47

Table of Contents

collection activities and payment history utilized for risk segmentation; current conditions include changes in economic conditions, aging of receivable balances, payment options and programs available to customers, and industry trends for each company; and forward-looking risk factors include assumptions related to the level of write-offs and recoveries. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. The Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations.
Depreciable Lives of Property, Plant, and Equipment (All Registrants)
The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or regulatory action, or changes in retirement patterns indicate an update is necessary.
Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
Changes in estimated useful lives of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.
Goodwill (Exelon, ComEd, and PHI)
As of December 31, 2025, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital
48

Table of Contents

cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.
While the 2025 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.
See Note 1 — Significant Accounting Policies and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Liabilities (Exelon and PHI)
Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through Purchased power and fuel expense. See Note 2 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of the financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements.
49

Table of Contents

Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.
Pension and OPEB plan assets include cash and cash equivalents, equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as private equity, real estate, private credit, and hedge funds.
Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates.
50

Table of Contents

Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant:

Actual Assumption (Decrease) Increase
Actuarial Assumption Pension OPEB Change in
Assumption Pension OPEB Total
Change in 2025 cost:
Discount rate (a)
5.68% 5.64% 0.5% $ (16) $ (2) $ (18)
5.68% 5.64% (0.5)% $ 18  $ 2  $ 20 
EROA 7.00% 6.50% 0.5% $ (51) $ (6) $ (57)
7.00% 6.50% (0.5)% $ 51  $ 6  $ 57 
Change in benefit obligation at December 31, 2025:
Discount rate (a)
5.42% 5.34% 0.5% $ (485) $ (79) $ (564)
5.42% 5.34% (0.5)% $ 552  $ 89  $ 641 

__________
(a) In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.
See Note 1 — Significant Accounting Policies and Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.
Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities.
All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For derivatives that qualify and are designated as cash flow hedges, changes in fair value each period are initially recorded in AOCI and recognized in earnings when the hedged transaction affects earnings. For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings on the Consolidated Statement of Operations and Comprehensive Income or are recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements.
NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for all contracts that are accounted for under NPNS.
Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The
51

Table of Contents

Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts can be traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. For derivatives that trade in liquid markets, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in the assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the Registrants’ financial statements.
Interest Rate Derivative Instruments. Exelon Corporate utilizes interest rate swaps to manage interest rate risk on existing and planned future debt issuances. The fair value of the swaps is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate derivatives are primarily categorized in Level 2 in the fair value hierarchy.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Fair Value of Financial Assets and Liabilities and Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

52

Table of Contents
ComEd

Results of Operations by Registrant
Results of Operations—ComEd

2025 2024 (Unfavorable) Favorable Variance
Operating revenues $ 7,267  $ 8,219  $ (952)

Operating expenses
Purchased power 1,782  3,042  1,260 
Operating and maintenance 1,710  1,703  (7)
Depreciation and amortization 1,560  1,514  (46)
Taxes other than income taxes 409  376  (33)
Total operating expenses 5,461  6,635  1,174 
Gain on sales of assets —  5  (5)
Operating income 1,806  1,589  217 
Other income and (deductions)
Interest expense, net (530) (501) (29)
Other, net 132  94  38 
Total other income and (deductions) (398) (407) 9 
Income before income taxes 1,408  1,182  226 
Income taxes 261  116  (145)
Net income $ 1,147  $ 1,066  $ 81 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 . Net income increased by $81 million primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, and higher AFUDC, partially offset by lower transmission peak load.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase (Decrease)
Distribution $ 297 
Transmission — 
Energy efficiency 32 
Other (47)
282 
Regulatory required programs (1,234)
Total decrease $ (952)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not intended to be impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets.
53

Table of Contents
ComEd

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recov ered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2025, compared to the same period in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.
Other Revenue primarily includes assistance provided to other utili ties through mutual assistance programs. Other revenue decreased for the year ended December 31, 2025, compared to the same period in 2024, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The $1,260 million decrease in Purchased power expense for the year ended December 31, 2025 compared to the same period in 2024, which includes the impacts of CMC nuclear production tax credits, is offset in Operating revenues as part of regulatory required programs. See Note 2 — Regulatory Matters for additional information.
54

Table of Contents
ComEd

The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
(Decrease) Increase
Labor, other benefits, contracting, and materials $ (9)
BSC costs (14)
Pension and non-pension postretirement benefits expense 5 
Storm-related costs 2 

(15)
Regulatory required programs (a)
22 
Total increase $ 7 

__________
(a) ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization (a)
$ 56 
Regulatory asset amortization (b)
(10)

Total increase $ 46 

__________
(a) Reflects ongoing capital expenditures.
(b) Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Interest expense, net increased $29 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.
Other , net increased $38 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher AFUDC equity.
Effective income tax rates were 18.5% and 9.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
55

Table of Contents
PECO

Results of Operations—PECO

2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 4,684  $ 3,973  $ 711 
Operating expenses
Purchased power and fuel 1,733  1,477  (256)
Operating and maintenance 1,195  1,120  (75)
Depreciation and amortization 454  428  (26)
Taxes other than income taxes 240  218  (22)
Total operating expenses 3,622  3,243  (379)
Gain on sales of assets —  4  (4)
Operating income 1,062  734  328 
Other income and (deductions)
Interest expense, net (260) (232) (28)
Other, net 41  37  4 
Total other income and (deductions) (219) (195) (24)
Income before income taxes 843  539  304 
Income taxes 29  (12) (41)

Net income $ 814  $ 551  $ 263 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $263 million due to an increase in revenue as a result of electric and gas distribution rates, favorable weather relative to the same period last year, and tax repairs related to storms, partially offset by an increase in contracting, depreciation and interest expense.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase (Decrease)
Electric Gas Total
Weather $ 27  $ 32  $ 59 
Volume (27) 2  (25)
Pricing 321  91  412 
Transmission 4  —  4 
Other 10  2  12 
335  127  462 
Regulatory required programs 168  81  249 
Total increase $ 503  $ 208  $ 711 

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2025, compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2025, compared to the same period in 2024, and normal weather consisted of the following:
56

Table of Contents
PECO

  For the Years Ended December 31,   % Change
PECO Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 4,274  3,786  4,348  12.9  % (1.7) %
Cooling Degree-Days 1,547  1,652  1,455  (6.4) % 6.3  %

Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2025, compared to the same period in 2024, decreased due to customer load. Natural gas volume for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs) 2025 2024 % Change Weather - Normal % Change (b)

Residential 14,078  13,963  0.8  % (1.5) %
Small commercial & industrial 7,537  7,683  (1.9) % (3.0) %
Large commercial & industrial 13,683  13,889  (1.5) % (2.2) %
Public authorities & electric railroads 678  613  10.6  % 11.0  %
Total electric retail deliveries (a)
35,976  36,148  (0.5) % (1.9) %

  At December 31,
Number of Electric Customers 2025 2024
Residential 1,541,970  1,533,443 
Small commercial & industrial 154,841  155,164 
Large commercial & industrial 3,158  3,150 
Public authorities & electric railroads 10,248  10,708 
Total 1,710,217  1,702,465 

__________
(a) Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Natural Gas Deliveries to Customers (in mmcf) 2025 2024 % Change Weather - Normal % Change (b)

Residential 43,189  38,328  12.7  % 1.6  %
Small commercial & industrial 23,709  21,906  8.2  % 0.6  %
Large commercial & industrial 15  17  (11.8) % (2.2) %
Transportation 24,204  23,357  3.6  % 0.7  %
Total natural gas deliveries (a)
91,117  83,608  9.0  % 1.1  %

  At December 31,
Number of Natural Gas Customers 2025 2024
Residential 510,959  508,224 
Small commercial & industrial 44,698  44,846 
Large commercial & industrial 7  7 
Transportation 617  644 
Total 556,281  553,721 

__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to electric and gas distribution rates charged to customers.
57

Table of Contents
PECO

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the year ended December 31, 2025, compared to the same period in 2024, remained relatively consistent.
Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2025, compared to the same period in 2024, increased primarily due to revenue related to late payment charges.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $256 million for the year ended December 31, 2025, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Labor, other benefits, contracting, and materials $ 51 
Credit loss expense 8 
Pension and non-pension postretirement benefits expense 4 
Storm-related costs 3 
BSC costs 2 
Other 22 
90 
Regulatory required programs (15)
Total increase $ 75 

The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization (a)
$ 37 
Regulatory asset amortization (11)
Total increase $ 26 

__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased by $22 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.
58

Table of Contents
PECO

Interest expense, net increased $28 million for the year ended December 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in 2025.
Effective income tax rates were 3.4% and (2.2)% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
59

Table of Contents
BGE

Results of Operations—BGE

2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 5,222  $ 4,426  $ 796 
Operating expenses
Purchased power and fuel 2,221  1,651  (570)
Operating and maintenance 1,066  1036  (30)
Depreciation and amortization 632  638  6 
Taxes other than income taxes 370  345  (25)
Total operating expenses 4,289  3,670  (619)

Operating income 933  756  177 
Other income and (deductions)
Interest expense, net (247) (216) (31)
Other, net 51  36  15 
Total other income and (deductions) (196) (180) (16)
Income before income taxes 737  576  161 
Income taxes 159  49  (110)
Net income $ 578  $ 527  $ 51 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased $51 million primarily due to distribution rates, favorable impacts of the multi-year plan reconciliation and a decrease in storm costs, partially offset by an increase in interest expense and the derecognition of regulatory assets and liabilities for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information on the multi-year plan reconciliation and the Next Generation Energy Act.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase
Electric Gas Total
Distribution $ 82  $ 62  $ 144 
Transmission 6  —  6 
Other 11  —  11 
99  62  161 
Regulatory required programs 471  164  635 
Total increase $ 570  $ 226  $ 796 

60

Table of Contents
BGE

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling.

At December 31,
Number of Electric Customers 2025 2024
Residential 1,222,397  1,216,614 
Small commercial & industrial 115,197  115,010 
Large commercial & industrial 13,445  13,266 
Public authorities & electric railroads 252  260 
Total 1,351,291  1,345,150 

At December 31,
Number of Natural Gas Customers 2025 2024
Residential 660,986  658,776 
Small commercial & industrial 37,759  37,874 
Large commercial & industrial 6,417  6,369 
Total 705,162  703,019 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, due to favorable impacts of the multi-year plans.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily driven by an increase in service application fees.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $570 million for the year ended December 31, 2025 compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
61

Table of Contents
BGE

The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
BSC costs $ 5 
Credit loss expense 1 
Labor, other benefits, contracting, and materials 1 
Multi-year plan reconciliation (a)
(9)
Storm-related costs (13)
Other (b)
5 
(10)
Regulatory required programs (c)
40 
Total increase $ 30 

__________
(a) See Note 2 — Regulatory Matters for additional information on the multi-year plan reconciliation.
(b) Reflects the derecognition of regulatory assets for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act, partially offset by the absence of capital write-offs included in 2024. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.
(c) Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.

The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization $ 13 
Regulatory required programs (a)
21 
Regulatory asset amortization (40)
Total decrease $ (6)

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. See Note 2 — Regulatory Matters for additional information.
Taxes other than income taxes increased by $25 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased property taxes.
Interest expense, net increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.
Other, net increased by $15 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased interest income and higher AFUDC equity.
Effective income tax rates were 21.6% and 8.5% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
62

Table of Contents
PHI

Results of Operations—PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the year ended December 31, 2025 compared to the same period in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.

2025 2024 Favorable Variance
PHI $ 799  $ 741  $ 58 
Pepco 401  390  11 
DPL 224  209  15 
ACE 188  155  33 
Other (a)
(14) (14) — 

__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $58 million primarily due to electric distribution rates, favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023, DPL Delaware electric DSIC rates and natural gas rates, and transmission rates, partially offset by the absence of the Pepco Maryland multi-year plans reconciliations, lower AFUDC income, and increases in interest expense, depreciation expense and contracting costs.
63

Table of Contents
Pepco

Results of Operations—Pepco

2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 3,454  $ 3,039  $ 415 
Operating expenses
    Purchased power 1,262  1,055  (207)
Operating and maintenance
625  534  (91)
Depreciation and amortization
433  407  (26)
Taxes other than income taxes
455  424  (31)
Total operating expenses 2,775  2,420  (355)
(Loss) gain on sales of assets 1  (1) 2 
Operating income 680  618  62 
Other income and (deductions)
Interest expense, net
(214) (192) (22)
Other, net
41  54  (13)
Total other income and (deductions)
(173) (138) (35)
Income before income taxes 507  480  27 
Income taxes 106  90  (16)
Net income $ 401  $ 390  $ 11 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $11 million primarily due to distribution and transmission rates, partially offset by the absence of the Maryland multi-year plans reconciliations, lower AFUDC income, and increases in interest expense and depreciation expense.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase (Decrease)
Distribution $ 135 
Transmission 27 
Other (9)
153 
Regulatory required programs 262 
Total increase $ 415 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer class in the District of Columbia and per customer by customer class in Maryland. Therefore, changes in the number of customers only impacts Operating revenues in Maryland. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling Pepco Maryland.
64

Table of Contents
Pepco

At December 31,
Number of Electric Customers in Maryland 2025 2024
Residential 560,304  556,239 
Small commercial & industrial 30,548  30,571 
Large commercial & industrial 19,078  18,989 
Public authorities & electric railroads 179  179 
Total 610,109  605,978 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024, primarily due to the favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $207 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

65

Table of Contents
Pepco

The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Labor, other benefits, contracting, and materials $ 26 
Maryland multi-year plan reconciliations (a)
23 
Credit loss expense 2 
Pension and non-pension postretirement benefits expense 1 
Storm-related costs 1 
BSC and PHISCO costs (5)
Other 7 
55 
Regulatory required programs (b)
36 
Total increase $ 91 

__________
(a) See Note 2 — Regulatory Matters for additional information on multi-year plan reconciliations.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.
The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization (a)
$ 24 
Regulatory asset amortization 6 
Regulatory required programs (b)
(4)
Total increase $ 26 

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters for additional information.
Taxes other than income taxes increased $31 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Interest expense, net increased $22 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.
Other , net decreased $13 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity.
Effective income tax rates were 20.9% and 18.8% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

66

Table of Contents
DPL

Results of Operations—DPL

2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 1,971  $ 1,787  $ 184 
Operating expenses
Purchased power and fuel 861  760  (101)
Operating and maintenance
391  377  (14)
Depreciation and amortization
252  245  (7)
Taxes other than income taxes
88  79  (9)
Total operating expenses 1,592  1,461  (131)

Operating income 379  326  53 
Other income and (deductions)
Interest expense, net
(102) (93) (9)
Other, net
16  25  (9)
Total other income and (deductions)
(86) (68) (18)
Income before income taxes 293  258  35 
Income taxes 69  49  (20)
Net income $ 224  $ 209  $ 15 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $15 million primarily due to Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, and transmission rates, partially offset by increases in interest and depreciation expense.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase (Decrease)
Electric Gas Total
Weather $ 8  $ 3  $ 11 
Volume (4) 7  3 
Distribution 20  14  34 
Transmission 19  —  19 
Other (1) —  (1)
42  24  66 
Regulatory required programs 90  28  118 
Total increase $ 132  $ 52  $ 184 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2025 compared to the same period in 2024, Operating revenues
67

Table of Contents
DPL

related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the year ended December 31, 2025 compared to same period in 2024 and normal weather consisted of the following:

For the Years Ended December 31, % Change
Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 4,500  4,100  4,477  9.8  % 0.5  %
Cooling Degree-Days 1,309  1,277  1,302  2.5  % 0.5  %

For the Years Ended December 31, % Change
Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal
Heating Degree-Days 4,500  4,100  4,605  9.8  % (2.3) %

Volume, exclusive of the effects of weather, increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in customer growth.

Electric Retail Deliveries to Delaware Customers (in GWhs) 2025 2024 % Change Weather - Normal % Change (b)

Residential 3,288  3,227  1.9  % (1.4) %
Small commercial & industrial 1,459  1,445  1.0  % 0.2  %
Large commercial & industrial 3,049  3,019  1.0  % 0.6  %
Public authorities & electric railroads 31  32  (3.1) % (3.5) %
Total electric retail deliveries (a)
7,827  7,723  1.3  % (0.3) %

At December 31,
Number of Total Electric Customers (Maryland and Delaware) 2025 2024
Residential 495,254  490,626 
Small commercial & industrial 65,500  64,813 
Large commercial & industrial 1,273  1,255 
Public authorities & electric railroads 634  606 
Total 562,661  557,300 

__________
(a) Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Natural Gas Retail Deliveries to Delaware Customers (in mmcf) 2025 2024 % Change Weather - Normal % Change (b)

Residential 9,052  7,810  15.9  % 7.5  %
Small commercial & industrial 4,339  3,801  14.2  % 5.5  %
Large commercial & industrial 1,680  1,674  0.4  % 0.4  %
Transportation 6,355  6,206  2.4  % (0.3) %
Total natural gas deliveries (a)
21,426  19,491  9.9  % 4.1  %

68

Table of Contents
DPL

At December 31,
Number of Delaware Natural Gas Customers 2025 2024
Residential 132,148  131,392 
Small commercial & industrial 10,255  10,218 
Large commercial & industrial 14  14 
Transportation 160  162 
Total 142,577  141,786 

__________
(a) Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to increases in underlying costs and capital investment.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $101 million for the year ended December 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs .
69

Table of Contents
DPL

The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Credit loss expense $ 3 
Pension and non-pension postretirement benefits expense 1 
Labor, other benefits, contracting, and materials (2)
BSC and PHISCO costs (5)
Storm-related costs (5)
Other 3 
$ (5)
Regulatory required programs (a)
19 
Total increase $ 14 

__________
(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization (a)
$ 8 
Regulatory asset amortization (1)

Total increase $ 7 

__________
(a) Depreciation and amortization increased primarily due to ongoing expenditures.
Taxes other than income taxes increased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to an increase in property taxes.
Interest expense, net increased $9 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.
Other, net decreased by $9 million for the year ended December 31, 2025 compared to the same period in 2024, primarily due to lower AFUDC equity and a decrease in interest income.
Effective income tax rates were 23.5% and 19.0% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
70

Table of Contents
ACE

Results of Operations—ACE

2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 1,718  $ 1,628  $ 90 
Operating expenses
Purchased power 808  698  (110)
Operating and maintenance
328  368  40 
Depreciation and amortization
248  278  30 
Taxes other than income taxes
9  9  — 
Total operating expenses 1,393  1,353  (40)
Gain on sale of assets 2  —  2 
Operating income 327  275  52 
Other income and (deductions)
Interest expense, net
(82) (79) (3)
Other, net
10  14  (4)
Total other income and (deductions) (72) (65) (7)
Income before income taxes 255  210  45 
Income taxes 67  55  (12)
Net income $ 188  $ 155  $ 33 

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. Net income increased by $33 million primarily due to favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023, a decrease in various operating expenses, distribution rates and an increase in customer growth, offset by an increase in interest and depreciation expense.
The changes in Operating revenues consisted of the following:

2025 vs. 2024
Increase

Distribution $ 6 

Other 3 
9 
Regulatory required programs 81 
Total increase $ 90 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

71

Table of Contents
ACE

At December 31,
Number of Electric Customers 2025 2024
Residential 510,005  507,483 
Small commercial & industrial 63,154  62,739 
Large commercial & industrial 2,682  2,843 
Public authorities & electric railroads 754  714 
Total 576,595  573,779 

Distribution Revenue increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to distribution rates and an increase in customer growth.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the year ended December 31, 2025 compared to the same period in 2024.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 4 – Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $110 million for the year ended December 31, 2025 compared to same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs .
The changes in Operating and maintenance expense consisted of the following:

2025 vs. 2024
Increase (Decrease)

Storm-related costs $ 3 

BSC and PHISCO costs (10)

Labor, other benefits, contracting and materials (a)
(33)
Other (1)
(41)
Regulatory required programs 1 
Total decrease $ (40)

__________
(a) Reflects a decrease in contracting costs for the year ended December 31, 2025, resulting from the favorable impacts of the ACE Electric Distribution Base Rate Case, including the recognition of the regulatory asset and corresponding decrease in O&M associated with work stoppage costs that were incurred by ACE in 2023. See Note 2 — Regulatory Matters for additional information.

72

Table of Contents
ACE

The changes in Depreciation and amortization expense consisted of the following:

2025 vs. 2024
Increase (Decrease)
Depreciation and amortization (a)
$ 12 
Regulatory asset amortization (11)
Regulatory required programs (b)
(31)

Total decrease $ (30)

__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b) Regulatory required programs decreased primarily due to the absence of the regulatory asset amortization of the PPA termination obligation, which was fully amortized in 2024.
Interest expense, net increased $3 million for the year ended December 31, 2025 compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2025.
Effective income tax rates were 26.3% and 26.2% for the years ended December 31, 2025 and 2024, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4 billion, as of December 31, 2025. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so is recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory liability.
73

Table of Contents

See Note 2 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2025 and 2024 by Registrant:

Increase (decrease) in cash flows from operating activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Net income (loss) $ 308  $ 81  $ 263  $ 51  $ 58  $ 11  $ 15  $ 33 
Adjustments to reconcile net income to cash:
Non-cash operating activities 1,058  617  43  207  98  131  40  (56)

Collateral (paid) received, net (43) (66) 6  5  17  12  —  5 
Income taxes 125  113  359  223  26  (3) 40  14 
Pension and non-pension postretirement benefit contributions (162) (184) (9) (7) 36  —  2  5 
Regulatory assets and liabilities, net 206  260  (60) (13) 31  (8) 16  26 
Changes in working capital and other noncurrent assets and liabilities (807) (869) 47  (132) (78) (102) (35) 74 
Increase (decrease) in cash flows from operating activities $ 685  $ (48) $ 649  $ 334  $ 188  $ 41  $ 78  $ 101 

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the years ended December 31, 2025 and 2024 were as follows:
• See Note 20 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities .
• Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position and whether collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Utility Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent due to stable energy prices. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
• See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
• Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's increased contributions to the Qualified Plans during the year ended December 31, 2025. See Note 14 — Retirement Benefits
• Changes in Regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. ComEd recognized changes of $849 million and $493 million related to carbon mitigation credits for the years ended December 31, 2025 and 2024, respectively. Included within the change in 2025 is an $804 million adjustment for CMC nuclear production tax credits, which is offset by an increase in Accounts receivable. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. ComEd's energy efficiency program recognized changes of $447 million and $435 million for the years ended December 31, 2025 and 2024, respectively. Additionally, ComEd recognized changes in the distributed generation rebates program of $83 million and $74 million for the years ended December 31, 2025 and 2024, respectively. Also included within the changes is
74

Table of Contents