EXC 10-K diff: FY 2024-12-31 → FY 2025-12-31
Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).
Item 1A · Risk Factors
+28 paragraphs −27 paragraphs ~27 changed
FY 2024-12-31 (earlier)
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.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 lead 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 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
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Table of ContentsThe 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, 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.
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 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.23
Table of ContentsThe 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 effects of ongoing business decisions. See Note 1 — Significant Accounting Policies and Note 13 — 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 18 — 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.The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators, and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement with the USAO for the Northern District of Illinois to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and no charges were brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period. That period expired, and the pending charge was dismissed, in July 2023. In October 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. On September 28, 2023, Exelon and ComEd reached a settlement with the SEC to fully resolve the matter.
The DPA and the settlement with the SEC could have a material adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers, and other stakeholders. Those impacts could affect, or make more difficult, their efforts to achieve actions or approvals associated with operations. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for more information regarding the DPA and SEC settlement.
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Table of ContentsRisks 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 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. 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.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.25
Table of ContentsThe 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, or other significant events also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the 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
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such climate changes result in more intense, frequent and extreme weather events, elevated or decreased levels of precipitation, sea level rise, increased surface water 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 lack of availability of labor, materials or parts, 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 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 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 artificial intelligence technologies. 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.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by 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
27Table of ContentsUtility 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 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).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
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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, 2024, 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 16 — 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 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.29
Table of ContentsThe 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.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 7 — Property, Plant, and Equipment, Note 11 — Asset Impairments, and Note 12 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
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Table of ContentsThe 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.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 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
FY 2025-12-31 (later)
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 ContentsRisks 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,
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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
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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.
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Table of ContentsA 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
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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
25Table of Contentsweather, 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 ContentsThe 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
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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 ContentsClimate 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 ContentsMarket 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 7 · Management's Discussion & Analysis
+707 paragraphs −716 paragraphs ~707 changed
FY 2024-12-31 (earlier)
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 OverviewExelon 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 5 — 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, 2023 compared to the year ended December 31, 2022, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2023 Form 10-K, which was filed with the SEC on February 21, 2024.Financial Results of OperationsGAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations by Registrant for the year ended December 31, 2024 compared to the same period in 2023. For additional information regarding the financial results for the years ended December 31, 2024 and 2023, see the discussions of Results of Operations by Registrant.
2024 2023 Favorable (Unfavorable) Variance
Exelon $ 2,460 $ 2,328 $ 132
ComEd 1,066 1,090 (24)
PECO 551 563 (12)
BGE 527 485 42
PHI 741 590 151
Pepco 390 306 84
DPL 209 177 32
ACE 155 120 35Other (a)(425) (400) (25)__________
(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.41Table of ContentsYear Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income attributable to common shareholders from continuing operations increased by $132 million and Diluted earnings per average common share from continuing operations increased to $2.45 in 2024 from $2.34 in 2023 primarily due to:
• Favorable impacts of rate increases at BGE and PHI;
• Less unfavorable weather at PECO;• Higher return on regulatory assets at ComEd;• Lower contracting costs at PHI;
• A tax repairs deduction at PECO;
• Favorable impacts of multi-year plans reconciliations at Pepco;
• Absence of realized losses from hedging activity at Exelon Corporate;
• Higher transmission peak load due to higher energy demand at ComEd; and
• Lower storm costs at PHI.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;• Lower impacts of multi-year plans reconciliations at BGE;
• Higher depreciation and amortization expense at PECO, BGE, and PHI;
• Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd;
• Higher credit loss expense at PECO and BGE;
• Lower carrying cost recovery related to the CMC regulatory asset at ComEd; and
• Higher storm costs at BGE.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.42Table of ContentsThe following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2024 compared to 2023:
2024 2023(In millions, except per share data) Earnings per Diluted Share Earnings per Diluted ShareNet income attributable to common shareholders from continuing operations $ 2,460 $ 2.45 $ 2,328 $ 2.34
Mark-to-market impact of economic hedging activities (net of taxes of $0 and $1, respectively)
— — (4) —
Environmental costs (net of taxes of $5 and $8, respectively)
(13) (0.01) 29 0.03
Asset retirement obligations (net of taxes of $3 and $1, respectively)
8 0.01 (1) —
SEC matter loss contingency (net of taxes of $0)
— — 46 0.05
Separation costs (net of taxes of $0 and $7, respectively) (a)
— — 22 0.02
Cost management charge (net of taxes of 4) (b)
13 0.01 — —
Change in FERC audit liability (net of taxes of $13 and $4, respectively)
42 0.04 11 0.01Income tax-related adjustments (entire amount represents tax expense) (c)(3) — (54) (0.05)
Adjusted (non-GAAP) operating earnings $ 2,507 $ 2.50 $ 2,377 $ 2.38__________
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 2024 and 2023 ranged from 24.0% to 29.0%.
(a) Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense and Other, net.
(b) Primarily represents severance and reorganization costs related to cost management.
(c) In 2023, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment. In 2024, reflects the adjustment to state deferred income taxes due to change in DPL's Delaware net operating loss valuation allowance.
Significant 2024 Transactions and DevelopmentsAt-the-Market ProgramIn the third quarter 2024, Exelon issued approximately 4 million shares of Common Stock at an average gross price of $37.60 per share. The net proceeds from the 2024 issuances were $148 million, which were used for general corporate purposes. See Note 19 — 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.43Table of ContentsThe following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2024. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.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, 2025PECO - Pennsylvania March 28, 2024 Electric $464 $ 354 N/A December 12, 2024 January 1, 2025
Natural Gas $111 $ 78BGE - 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, 2025Pepco - Maryland October 26, 2020 (amended March 31, 2021) Electric $ 104 $ 52 9.55% June 28, 2021 June 28, 2021
May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50% June 10, 2024 April 1, 2024DPL - 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, 2023ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92 $ 45 9.60% November 17, 2023 December 1, 202344Table of Contents
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval TimingDPL - Delaware September 20, 2024 Natural Gas $ 39 10.50% First quarter of 2026
ACE - New Jersey November 21, 2024 Electric $ 109 10.70% Fourth quarter of 2025Transmission Formula RatesThe following total increases/(decreases) were included in the Utility Registrants' 2024 annual electric transmission formula rate updates. All rates are effective June 1, 2024 to May 31, 2025, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Registrant Initial Revenue Requirement Increase Annual Reconciliation (Decrease) Increase Total Revenue Requirement Increase Allowed Return on Rate Base Allowed ROE
ComEd $ 32 $ (12) $ 20 8.14 % 11.50 %
PECO $ 2 $ 3 $ 5 7.45 % 10.35 %
BGE $ 42 $ 13 $ 53 7.47 % 10.50 %
Pepco $ 58 $ 15 $ 73 7.62 % 10.50 %
DPL $ 7 $ 17 $ 24 7.23 % 10.50 %
ACE $ 14 $ 18 $ 32 7.11 % 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 issued 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 August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
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 final settlement is subject to FERC approval. The existing loss estimate is 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.Other Key Business Drivers and Management Strategies
Utility Rates and Rate ProceedingsThe 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
45Table of Contentsresults of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.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 Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that is 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.
Management will continue to work collaboratively with the Registrants’ regulatory commissions to file PLR requests with the IRS confirming the treatment of NOLC for ratemaking purposes. The Registrants will record the impact, if any, upon receiving their own PLRs from the IRS.Legislative and Regulatory Developments
Infrastructure Investment and Jobs ActOn November 15, 2021, President Biden signed the $1.2 trillion IIJA 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.
In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of DERs and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The award negotiation process is complete and funding has been obligated.
In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The award negotiation process is complete and funding has been obligated.
The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further
46Table of Contentsnegotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.
In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for fiscal years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that link grid communications systems and operations to increase resilience and reduce power outages and threats, and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In March 2024, Exelon, BGE, PHI, Pepco, DPL, and ACE submitted five applications for Topic Area 2 (Smart Grid Grants). These applications focus on improving resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers across the Exelon footprint.
In October 2024, Exelon’s project, Renewable-Aware Distribution Operations: Pioneering a cleaner future for all our communities, and BGE’s project, Baltimore Interconnection Readiness & Deployment of Storage (BIRDS), were recommended by the GDO for negotiation of a final award up to $100 million and $50 million, respectively. The Exelon project will deploy advanced Distribution Energy Resource Management System (DERMS) capabilities and pilot technology to increase the flexibility, efficiency, reliability, and resilience of its distribution network. BGE’s project will facilitate a programmatic approach to a flexible and decentralized energy distribution grid while setting an automated and digitized framework for unlocking future clean energy investments. Both the Exelon and BGE projects have been issued conditional awards, subject to final negotiations.
The Trump Administration has issued numerous Executive Orders (EOs), including the Unleashing American Energy Order on January 20, 2025, which requires an immediate pause in the disbursement of funds appropriated through the IRA and IIJA during a 90-day review period. Exelon is currently evaluating this EO and others to determine what, if any, impact they might have on awards selected or received from the Department of Energy.
PJM Regional Transmission Expansion
At the February 4, 2025 Transmission Expansion Advisory Committee meeting, PJM disclosed PECO’s, BGE’s and Pepco’s revised total estimated costs for the planned retirement of the Brandon Shores Generating Station of approximately $154 million, $1.1 billion, and $241 million, respectively.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.Goodwill (Exelon, ComEd, and PHI)
As of December 31, 2024, 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 5 — 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 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.47
Table of ContentsEntities 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 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 2024 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 12 — 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 3 — Regulatory Matters and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.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 3 — 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.48
Table of ContentsChanges 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.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 non-callable (or callable with make whole provisions) 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.49Table 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 TotalChange in 2024 cost:Discount rate (a)5.19% 5.17% 0.5% $ (18) $ (2) $ (20)
5.19% 5.17% (0.5)% $ 20 $ 2 $ 22
EROA 7.00% 6.50% 0.5% $ (53) $ (6) $ (59)
7.00% 6.50% (0.5)% $ 53 $ 6 $ 59
Change in benefit obligation at December 31, 2024:Discount rate (a)5.68% 5.64% 0.5% $ (451) $ (83) $ (534)
5.68% 5.64% (0.5)% $ 517 $ 94 $ 611__________
(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 14 — 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.
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.
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, 2024:
(In millions) Exelon ComEd PECO BGE PHI Pepco DPL ACE
Gain (loss) $ 2,803 $ 4,897 $ (693) $ (347) $ (1,030) $ (276) $ 92 $ (447)
Charge against OCI (a)
(2,844) — — — — — — —
___________
(a) Exelon's charge against OCI (before taxes) consists of up to $2.2 billion, $363 million, $384 million, $253 million, $95 million, and $7 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $106 million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
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See Note 3 — 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.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 15 — 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 15 — 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 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.51
Table of ContentsInterest 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 17 — Fair Value of Financial Assets and Liabilities and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.
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 13 — Income Taxes 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 18 — 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 actuarial52
Table of Contentsassumptions 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.
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.
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.
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See Note 3 — Regulatory Matters 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 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.
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Table of ContentsComEd
Results of Operations by Registrant
Results of Operations—ComEd2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 8,219 $ 7,844 $ 375Operating expensesPurchased power 3,042 2,816 (226)
Operating and maintenance 1,703 1,450 (253)
Depreciation and amortization 1,514 1,403 (111)
Taxes other than income taxes 376 369 (7)
Total operating expenses 6,635 6,038 (597)
Gain on sales of assets 5 — 5
Operating income 1,589 1,806 (217)Other income and (deductions)Interest expense, net (501) (477) (24)
Other, net 94 75 19
Total other income and (deductions) (407) (402) (5)
Income before income taxes 1,182 1,404 (222)
Income taxes 116 314 198
Net income $ 1,066 $ 1,090 $ (24)
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 . Net income decreased by $24 million primarily due to a lower allowed distribution ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset. These were partially offset by higher distribution rate base, higher return on regulatory assets primarily due to an increase in asset balances, and higher transmission peak load.The changes in Operating revenues consisted of the following:2024 vs. 2023
Increase
Distribution $ 191
Transmission 78
Energy efficiency 59
Other 44
372
Regulatory required programs 3
Total increase $ 375Revenue 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. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. 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, 2024, compared to the same period in 2023, primarily due to higher fully
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ComEdrecoverable costs and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset.
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. T ransmission revenues increased during the year ended December 31, 2024, compared to the same period in 2023, primarily due to increased underlying costs, higher peak load, and increased capital investments.
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, 2024, compared to the same period in 2023, primarily due to increased regulatory asset amortization, which is fully recoverable, and the impacts of a higher rate base.
Other Revenue primarily includes assistance provided to other utili ties through mutual assistance programs. Other revenue increased for the year ended December 31, 2024, compared to the same period in 2023, which primarily reflects 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The $226 million increase in Purchased power expense for the year ended December 31, 2024 compared to the same period in 2023 is offset in Operating revenues as part of regulatory required programs.
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ComEd
The changes in Operating and maintenance expense consisted of the following:2024 vs. 2023
Increase (Decrease)
Labor, other benefits, contracting, and materials (a)
$ 112
BSC costs 66
Pension and non-pension postretirement benefits expense 24
Storm-related costs (4)
Other (b)
62
260
Regulatory required programs
(7)
Total increase $ 253__________(a) Primarily reflects an updated rate of capitalization of certain overhead costs.
(b) Primarily reflects the reclassification and increase of the FERC audit liability during the current year and an increase in credit loss expense. See Note 3 — Regulatory Matters for additional information regarding the FERC audit liability.The changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023
IncreaseDepreciation and amortization (a)$ 70Regulatory asset amortization (b)41
Total increase $ 111__________
(a) Reflects ongoing capital expenditures.
(b) Includes amortization of ComEd's energy efficiency formula rate regulatory asset.Interest expense, net increased $24 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to an increase in the principal balance and interest rates of debt issued in 2024.
Effective income tax rates were 9.8% and 22.4% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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PECO
Results of Operations—PECO2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 3,973 $ 3,894 $ 79Operating expensesPurchased power and fuel 1,477 1,544 67
Operating and maintenance 1,120 1,003 (117)
Depreciation and amortization 428 397 (31)
Taxes other than income taxes 218 202 (16)
Total operating expenses 3,243 3,146 (97)
Gain on sales of assets 4 — 4
Operating income 734 748 (14)Other income and (deductions)Interest expense, net (232) (201) (31)
Other, net 37 36 1
Total other income and (deductions) (195) (165) (30)
Income before income taxes 539 583 (44)
Income taxes (12) 20 32
Net income $ 551 $ 563 $ (12)
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income decreased by $12 million, primarily due to an increase in credit loss expense, interest expense, and depreciation expense, partially offset by a decrease in income tax expense due to a higher tax repairs deduction and an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.The changes in Operating revenues consisted of the following:2024 vs. 2023Increase (Decrease)
Electric Gas TotalWeather $ 62 $ 15 $ 77
Volume 9 1 10
Pricing 28 3 31
Transmission 10 — 10
Other 1 (2) (1)
110 17 127
Regulatory required programs 14 (62) (48)
Total increase (decrease) $ 124 $ (45) $ 79
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, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable 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 years ended December 31, 2024 compared to the same period in 2023 and normal weather consisted of the following:
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PECO
For the Years Ended December 31, % ChangePECO Service Territory 2024 2023 Normal 2024 vs. 2023 2024 vs. Normal
Heating Degree-Days 3,786 3,587 4,381 5.5 % (13.6) %
Cooling Degree-Days 1,652 1,345 1,462 22.8 % 13.0 %
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2024 compared to the same period in 2023, increased due to customer load growth. Natural gas volume for the year ended December 31, 2024 compared to the same period in 2023, remained relatively consistent.
Electric Retail Deliveries to Customers (in GWhs) 2024 2023 % Change Weather - Normal % Change (b)
Residential 13,963 13,262 5.3 % 0.2 %
Small commercial & industrial 7,683 7,367 4.3 % 1.3 %
Large commercial & industrial 13,889 13,638 1.8 % 0.6 %
Public authorities & electric railroads 613 606 1.2 % 1.2 %Total electric retail deliveries (a)36,148 34,873 3.7 % 0.6 %At December 31,Number of Electric Customers 2024 2023
Residential 1,533,443 1,535,927
Small commercial & industrial 155,164 156,248
Large commercial & industrial 3,150 3,127
Public authorities & electric railroads 10,708 10,417
Total 1,702,465 1,705,719__________
(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) 2024 2023 % Change Weather - Normal % Change (b)
Residential 38,328 35,842 6.9 % 0.7 %
Small commercial & industrial 21,906 21,182 3.4 % 0.1 %
Large commercial & industrial 17 51 (66.7) % (11.1) %
Transportation 23,357 23,741 (1.6) % (2.6) %Total natural gas deliveries (a)83,608 80,816 3.5 % (0.4) %At December 31,Number of Gas Customers 2024 2023
Residential 508,224 507,197
Small commercial & industrial 44,846 45,001
Large commercial & industrial 7 9
Transportation 644 627
Total 553,721 552,834__________(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing electricity 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, 2024 compared to the same period in 2023 increased primarily due to higher electric DSIC rates in PECO's service territories.
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PECOTransmission 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, 2024 compared to the same period in 2023 primarily due to increases in underlying costs and capital investments.
Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2024 compared to the same period in 2023, remained relatively consistent.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The decrease of $67 million for the year ended December 31, 2024, compared to the same period in 2023, 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:2024 vs. 2023Increase (Decrease)Credit loss expense $ 46
BSC costs 30
Labor, other benefits, contracting, and materials 11
Pension and non-pension postretirement benefits expense 7
Storm-related costs (6)
Other 6
94
Regulatory required programs 23
Total increase $ 117The changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023
IncreaseDepreciation and amortization (a)$ 31
Regulatory asset amortization —
Total increase $ 31__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.Taxes other than income taxes increased by $16 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to higher Pennsylvania gross receipts tax.
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PECOInterest expense, net increased $31 million for the year ended December 31, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in 2024.
Effective income tax rates were (2.2)% and 3.4% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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BGE
Results of Operations—BGE2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 4,426 $ 4,027 $ 399Operating expensesPurchased power and fuel 1,651 1,531 (120)
Operating and maintenance 1,036 741 (295)
Depreciation and amortization 638 654 16
Taxes other than income taxes 345 319 (26)
Total operating expenses 3,670 3,245 (425)
Operating income 756 782 (26)Other income and (deductions)Interest expense, net (216) (182) (34)
Other, net 36 18 18
Total other income and (deductions) (180) (164) (16)
Income before income taxes 576 618 (42)
Income taxes 49 133 84
Net income $ 527 $ 485 $ 42
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased $42 million primarily due to favorable distribution rates, partially offset by lower impacts of multi-year plans reconciliations, an increase in interest expense, storm costs, credit loss expense and various operating expenses. See Note 3 — Regulatory Matters for additional information on multi-year plan order.The changes in Operating revenues consisted of the following:2024 vs. 2023
Increase (Decrease)Electric Gas TotalDistribution $ 94 $ 128 $ 222
Transmission 25 — 25
Other 2 (2) —
121 126 247
Regulatory required programs 207 (55) 152
Total increase $ 328 $ 71 $ 399
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BGERevenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not intended to be 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 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for BGE.At December 31,Number of Electric Customers 2024 2023
Residential 1,216,614 1,211,889
Small commercial & industrial 115,010 115,787
Large commercial & industrial 13,266 13,072
Public authorities & electric railroads 260 261
Total 1,345,150 1,341,009At December 31,Number of Gas Customers 2024 2023
Residential 658,776 657,823
Small commercial & industrial 37,874 37,993
Large commercial & industrial 6,369 6,309
Total 703,019 702,125
Distribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023, 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, 2024 compared to the same period in 2023 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 remained relatively consistent for the year ended December 31, 2024 compared to the same period in 2023.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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $120 million for the year ended December 31, 2024 compared to the same period in 2023 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
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BGE
The changes in Operating and maintenance expense consisted of the following:2024 vs. 2023
Increase
BSC costs $ 25
Storm-related costs 8
Labor, other benefits, contracting, and materials 24
Credit loss expense 8
Multi-year plans reconciliations (a)
77Other (b)33
175Regulatory required programs (c)120
Total increase $ 295__________(a) See Note 3 — Regulatory Matters for additional information on multi-year plans reconciliations.
(b) Primarily related to capital write-offs.
(c) Increase due to the cost recovery associated with EmPOWER Maryland. See Note 3 — Regulatory Matters for additional informationThe changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023
(Decrease) Increase
Depreciation and amortization $ (7)Regulatory required programs (a)(64)
Regulatory asset amortization 55
Total decrease $ (16)__________(a) Decrease due to the cost recovery associated with EmPOWER Maryland. See Note 3 — Regulatory Matters for additional information.
Taxes other than income taxes increased by $26 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increased property taxes.
Interest expense, net increased $34 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2024 and 2023 .
Other, net increased by $18 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increased interest income and higher AFUDC equity.
Effective income tax rates were 8.5% and 21.5% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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PHI
Results of Operations—PHIPHI’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, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.
2024 2023 Favorable Variance
PHI $ 741 $ 590 $ 151
Pepco 390 306 84
DPL 209 177 32
ACE 155 120 35Other (a)(13) (13) —__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $151 million primarily due to higher electric distribution rates, lower contracting costs due to the absence of the ACE employee strike, higher transmission rates, decrease in environmental costs at Pepco, favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, and a decrease in storm costs, partially offset by increases in depreciation expense and interest expense.
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Pepco
Results of Operations—Pepco2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 3,039 $ 2,824 $ 215Operating expensesPurchased power 1,055 974 (81)Operating and maintenance534 572 38Depreciation and amortization407 441 34Taxes other than income taxes424 390 (34)
Total operating expenses 2,420 2,377 (43)
(Loss) gain on sales of assets (1) 9 (10)
Operating income 618 456 162Other income and (deductions)
Interest expense, net(192) (165) (27)Other, net54 66 (12)Total other income and (deductions)(138) (99) (39)
Income before income taxes 480 357 123
Income taxes 90 51 (39)
Net income $ 390 $ 306 $ 84
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $84 million primarily due to decreases in environmental costs, higher transmission rates, favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, customer growth, and a decrease in storm costs partially offset by an increase in depreciation expense and interest expense.The changes in Operating revenues consisted of the following:2024 vs. 2023Increase (Decrease)Distribution $ 62
Transmission 61
Other (2)
121
Regulatory required programs 94
Total increase $ 215
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 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 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of Columbia.
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Pepco
At December 31,Number of Electric Customers 2024 2023
Residential 877,916 866,018
Small commercial & industrial 54,036 54,142
Large commercial & industrial 23,068 22,941
Public authorities & electric railroads 207 208
Total 955,227 943,309
Distribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023, primarily due to higher rates due to the favorable impacts of the Maryland multi-year plans and 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 increased for the year ended December 31, 2024 compared to the same period in 2023 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $81 million for the year ended December 31, 2024 compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
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Pepco
The changes in Operating and maintenance expense consisted of the following:2024 vs. 2023
(Decrease) Increase
Labor, other benefits, contracting, and materials (a)
$ (56)
BSC and PHISCO costs 13
Pension and non-pension postretirement benefits expense (2)
Credit loss expense (4)
Storm-related costs (4)
Pepco Maryland multi-year plan reconciliations (b)
(23)
Other (6)
(82)
Regulatory required programs (c)
44
Total decrease $ (38)__________(a) Primarily reflects the decreases in environmental costs for the year ended December 31, 2024.
(b) See Note 3 — Regulatory Matters for additional information on multi-year plan reconciliations.
(c) Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.The changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023Increase (Decrease)
Depreciation and amortization (a)$ 25
Regulatory asset amortization (1)Regulatory required programs (b)(58)
Total decrease $ (34)__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.(b) Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.
Taxes other than income taxes increased $34 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.
Interest expense, net increased $27 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
(Loss) gain on sales of assets for the year ended December 31, 2024 compared to the same period in 2023 decreased $10 million due to the absence of the gain on sale of land in the fourth quarter of 2023.
Other , net decreased $12 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to lower AFUDC equity.
Effective income tax rates were 18.8% and 14.3% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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DPL
Results of Operations—DPL2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 1,787 $ 1,688 $ 99Operating expensesPurchased power and fuel 760 737 (23)Operating and maintenance377 364 (13)Depreciation and amortization245 244 (1)Taxes other than income taxes79 75 (4)
Total operating expenses 1,461 1,420 (41)
Operating income 326 268 58Other income and (deductions)
Interest expense, net(93) (74) (19)Other, net25 18 7Total other income and (deductions)(68) (56) (12)
Income before income taxes 258 212 46
Income taxes 49 35 (14)
Net income $ 209 $ 177 $ 32
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. Net income increased by $32 million primarily due to higher Delaware electric distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by an increase in interest expense.The changes in Operating revenues consisted of the following:2024 vs. 2023
IncreaseElectric Gas TotalWeather $ 5 $ 3 $ 8
Volume 8 1 9
Distribution 44 5 49
Transmission 10 — 10
Other 5 — 5
72 9 81
Regulatory required programs 52 (34) 18
Total increase $ 124 $ (25) $ 99
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 3 — 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, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.
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DPLHeating 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, 2024 compared to same period in 2023 and normal weather consisted of the following:For the Years Ended December 31, % ChangeDelaware Electric Service Territory 2024 2023 Normal 2024 vs. 2023 2024 vs. Normal
Heating Degree-Days 4,100 3,845 4,517 6.6 % (9.2) %
Cooling Degree-Days 1,277 1,275 1,290 0.2 % (1.0) %For the Years Ended December 31, % ChangeDelaware Natural Gas Service Territory 2024 2023 Normal 2024 vs. 2023 2024 vs. Normal
Heating Degree-Days 4,100 3,845 4,631 6.6 % (11.5) %
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in customer usage and customer growth.
Electric Retail Deliveries to Delaware Customers (in GWhs) 2024 2023 % Change Weather - Normal % Change (b)
Residential 3,227 3,065 5.3 % 3.1 %
Small commercial & industrial 1,445 1,399 3.3 % 2.2 %
Large commercial & industrial 3,019 3,071 (1.7) % (1.9) %
Public authorities & electric railroads 32 33 (3.0) % (2.9) %Total electric retail deliveries (a)7,723 7,568 2.0 % 0.9 %At December 31,Number of Total Electric Customers (Maryland and Delaware) 2024 2023
Residential 490,626 485,713
Small commercial & industrial 64,813 64,220
Large commercial & industrial 1,255 1,260
Public authorities & electric railroads 606 593
Total 557,300 551,786__________
(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) 2024 2023 % Change Weather - Normal % Change (b)
Residential 7,810 7,326 6.6 % 0.9 %
Small commercial & industrial 3,801 3,660 3.9 % (1.9) %
Large commercial & industrial 1,674 1,588 5.4 % 5.4 %
Transportation 6,206 6,004 3.4 % 1.6 %Total natural gas deliveries (a)19,491 18,578 4.9 % 0.9 %
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DPL
At December 31,Number of Delaware Natural Gas Customers 2024 2023
Residential 131,392 129,903
Small commercial & industrial 10,218 10,133Large commercial & industrial 14 14Transportation 162 163
Total 141,786 140,213__________
(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, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.
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, 2024 compared to the same period in 2023 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $23 million for the year ended December 31, 2024 compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs .
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DPL
The changes in Operating and maintenance expense consisted of the following:2024 vs. 2023Increase (Decrease)BSC and PHISCO costs $ 11
Pension and non-pension postretirement benefits expense (2)Labor, other benefits, contracting, and materials (2)Storm-related costs (4)
Other (2)
$ 1Regulatory required programs (a)12
Total increase $ 13__________(a) Increase is primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.The changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023Increase (Decrease)
Depreciation and amortization (a)$ 9
Regulatory asset amortization 1
Regulatory required programs (b)
(9)
Total increase $ 1__________
(a) Depreciation and amortization increased primarily due to ongoing expenditures.(b) Decrease is primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to Note 3 — Regulatory Matters additional information.
Taxes other than income taxes increased by $4 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to an increase in property taxes.
Interest expense, net increased $19 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Other, net increased $7 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to higher interest income.
Effective income tax rates were 19.0% and 16.5% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
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ACE
Results of Operations—ACE2024 2023 Favorable (Unfavorable) Variance
Operating revenues $ 1,628 $ 1,522 $ 106Operating expensesPurchased power 698 637 (61)Operating and maintenance368 386 18Depreciation and amortization278 283 5Taxes other than income taxes9 8 (1)
Total operating expenses 1,353 1,314 (39)
Operating income 275 208 67Other income and (deductions)
Interest expense, net(79) (72) (7)Other, net14 20 (6)
Total other income and (deductions) (65) (52) (13)
Income before income taxes 210 156 54
Income taxes 55 36 (19)
Net income $ 155 $ 120 $ 35
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 . Net income increased by $35 million primarily due to higher distribution rates and lower contracting costs due to the absence of the ACE employee strike, partially offset by increases in depreciation expense and interest expense.The changes in Operating revenues consisted of the following:2024 vs. 2023
Increase (Decrease)
Distribution $ 54
Transmission (1)
53
Regulatory required programs 53
Total increase $ 106
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 became effective, prospectively, in the third quarter of 2021. The CIP 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 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.
At December 31,
Number of Electric Customers 2024 2023
Residential 507,483 504,919
Small commercial & industrial 62,739 62,646
Large commercial & industrial 2,843 2,909
Public authorities & electric railroads 714 727
Total 573,779 571,201
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ACEDistribution Revenue increased for the year ended December 31, 2024 compared to the same period in 2023 primarily due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.
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, 2024 compared to the same period in 2023.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.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 5 – Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $61 million for the year ended December 31, 2024 compared to same period in 2023, 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:2024 vs. 2023Increase (Decrease)BSC and PHISCO costs 10
Pension and non-pension postretirement benefits expense (1)
Storm-related costs (1)Labor, other benefits, contracting and materials (a)(42)
Other (3)
(37)
Regulatory required programs 19
Total decrease $ (18)__________(a) Reflects a decrease in contracting costs for the year ended December 31, 2024, primarily due to the absence of the ACE employee strike that occurred in 2023.
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ACE
The changes in Depreciation and amortization expense consisted of the following:2024 vs. 2023Increase (Decrease)
Depreciation and amortization (a)$ 15
Regulatory asset amortization 5Regulatory required programs (b)(25)
Total decrease $ (5)__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.(b) Regulatory required programs decreased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.
Interest expense, net increased $7 million for the year ended December 31, 2024 compared to the same period in 2023 primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.
Other, net decreased $6 million for the year ended December 31, 2024 compared to the same period in 2023, primarily due to lower AFUDC equity.
Effective income tax rates were 26.2% and 23.1% for the years ended December 31, 2024 and 2023, respectively. See Note 13 — 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 expenditures 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 $4.0 billion, as of December 31, 2024. 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 16 — 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 ActivitiesThe 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 will be recovered through a new 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
75Table of Contentsreceived 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 asset.
See Note 3 — Regulatory Matters and Note 18 — 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, 2024 and 2023 by Registrant:Increase (decrease) in cash flows from operating activities Exelon ComEd PECO BGE PHI Pepco DPL ACENet income (loss) $ 132 $ (24) $ (12) $ 42 $ 151 $ 84 $ 32 $ 35Adjustments to reconcile net income to cash:Non-cash operating activities 802 659 53 (38) 89 (5) 40 77
Collateral received (paid), net 179 (39) — 21 196 25 123 50
Income taxes (52) (220) (162) (91) (98) (90) (50) (5)
Pension and non-pension postretirement benefit contributions (51) 16 (3) (18) (62) 3 1 (6)
Regulatory assets and liabilities, net 389 306 58 208 (162) (40) (76) (41)
Changes in working capital and other noncurrent assets and liabilities (533) 167 (199) (180) (8) 8 (35) 16
Increase (decrease) in cash flows from operating activities $ 866 $ 865 $ (265) $ (56) $ 106 $ (15) $ 35 $ 126
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, 2024 and 2023 were as follows:
• See Note 22 —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 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
• See Note 13 — 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, 2024. 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 differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $435 million and $416 million for the years ended December 31, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $127 million, $52 million, $21 million, and $37 million for the year ended December 31, 2024, respectively, and $132 million, $70 million, $25 million, and $20 million for the year ended December 31, 2023, respectively. PECO had no energy efficiency
76Table of Contentsand demand response programs spend recorded to a regulatory asset for the years ended December 31, 2024 and 2023. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
• Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(223) million and $(533) million. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. For the year ended December 31, 2024, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts payable and accrued expense.Cash Flows from Investing ActivitiesThe following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2024 and 2023 by Registrant:
Increase (decrease) in cash flows from investing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures $ 311 $ 381 $ (127) $ (53) $ 125 $ 28 $ 6 $ 87
Proceeds from sales of assets and businesses 13 — — — (10) (10) — —
Other investing activities 9 (1) 4 5 (8) (8) — —
Increase (decrease) in cash flows from investing activities $ 333 $ 380 $ (123) $ (48) $ 107 $ 10 $ 6 $ 87
Significant investing cash flow impacts for the Registrants for 2024 and 2023 were as follows:
• Variances in Capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.Cash Flows from Financing ActivitiesThe following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2024 and 2023 by Registrant:
(Decrease) increase in cash flows from financing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net $ (601) $ (591) $ 101 $ (89) $ 156 $ 235 $ 133 $ (212)
Long-term debt, net (695) (425) 50 400 (58) (75) (8) 25
Changes in intercompany money pool — — — — (23) — — —
Issuance of common stock 8 — — — — — — —
Dividends paid on common stock (91) (30) 5 (52) — (107) (87) (1)
Distributions to member — — — — (193) — — —
Contributions from parent/member — (428) 247 (148) 30 (48) 61 20
Other financing activities 7 — (1) (2) 3 6 3 (1)
(Decrease) increase in cash flows from financing activities $ (1,372) $ (1,474) $ 402 $ 109 $ (85) $ 11 $ 102 $ (169)
Significant financing cash flow impacts for the Registrants for 2024 and 2023 were as follows:
• Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on Short-term borrowings for the Registrants.
• Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants.
77Table of Contents• Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.• Issuance of common stock relates to the third quarter 2024 issuance of Exelon common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
• Exelon’s ability to pay dividends on its Common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting Retained earnings. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.
• Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.
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Debt Issuances and RedemptionsSee Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2024 and 2023 by Registrant was as follows:During 2024, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of ProceedsExelon Notes 5.15% March 15, 2029 $650 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
Exelon Notes 5.45% March 15, 2034 650 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
Exelon Notes 5.60% March 15, 2053 400 Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
ComEd First Mortgage Bonds 5.30% June 1, 2034 400 Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
ComEd First Mortgage Bonds 5.65% June 1, 2054 400 Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
PECO First Mortgage Bonds 5.25% September 15, 2054 575 Refinance outstanding commercial paper and for general corporate purposes
BGE Notes 5.30% June 1, 2034 400 Repay outstanding commercial paper obligations and for general corporate purposes
BGE Notes 5.65% June 1, 2054 400 Repay outstanding commercial paper obligations and for general corporate purposes
Pepco First Mortgage Bonds 5.20% March 15, 2034 375 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
Pepco First Mortgage Bonds 5.50% March 15, 2054 300 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
DPL First Mortgage Bonds 5.24% March 20, 2034 100 Repay existing indebtedness and for general corporate purposes.DPL First Mortgage Bonds 5.55% March 20, 2054 75 Repay existing indebtedness and for general corporate purposes.ACE First Mortgage Bonds 5.55% March 20, 2054 75 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.29% August 28, 2034 75 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.49% August 28, 2039 100 Repay existing indebtedness and for general corporate purposes.
79Table of ContentsDuring 2023, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Notes 5.15% March 15, 2028 $1,000 Repay existing indebtedness and for general corporate purposes.
Exelon Notes 5.30% March 15, 2033 850 Repay existing indebtedness and for general corporate purposes.
Exelon Notes 5.60% March 15, 2053 650 Repay existing indebtedness and for general corporate purposes.
ComEd First Mortgage Bonds, Series 134 4.90% February 1, 2033 400 Repay outstanding commercial paper obligations and to fund other general corporate purposes.
ComEd First Mortgage Bonds Series 135 5.30% February 1, 2053 575 Repay outstanding commercial paper obligations and to fund other general corporate purposes.
PECO First and Refunding Mortgage Bonds 4.90% June 15, 2033 575 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
BGE Notes 5.40% June 1, 2053 700 Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.
Pepco First Mortgage Bonds 5.35% September 13, 2033 100 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.30% March 15, 2033 85 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.40% March 15, 2038 40 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.57% March 15, 2053 125 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.30% March 15, 2033 60 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.57% March 15, 2053 65 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.45% November 8, 2033 340 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.55% November 8, 2038 75 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.72% November 8, 2053 110 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.57% March 15, 2053 75 Repay existing indebtedness and for general corporate purposes.During 2024, the following long-term debt was retired and/or redeemed:Company (b)Type Interest Rate Maturity Amount
Exelon SMBC Term Loan Agreement SOFR plus 0.85% April 8, 2024 $ 500
Exelon Software Licensing Agreement 3.62% December 1, 2025 1
Exelon Software Licensing Agreement 3.95% May 1, 2024 2
Exelon Software Licensing Agreement 2.30% December 1, 2025 4
ComEd First Mortgage Bonds 3.10% November 1, 2024 250
Pepco First Mortgage Bonds 3.60% March 15, 2024 400DPL (a)Unsecured tax-exempt bonds 4.32% July 1, 2024 33
ACE First Mortgage Bonds 3.38% September 1, 2024 150(a) Variable interest on the DPL unsecured tax-exempt bonds reset on a weekly basis.
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(b) Exelon repurchased a portion of its Senior unsecured notes during 2024. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
During 2023, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount
Exelon SMBC Term Loan Agreement SOFR plus 0.65% July 21, 2023 $ 300
Exelon US Bank Term Loan Agreement SOFR plus 0.65% July 21, 2023 300
Exelon PNC Term Loan Agreement SOFR plus 0.65% July 24, 2023 250
Exelon Long-Term Software License Agreement 3.70% August 9, 2025 6
Exelon Long-Term Software License Agreement 3.95% May 1, 2024 2
Exelon Long-Term Software License Agreement 3.70% August 9, 2025 1
Exelon Long-Term Software License Agreement 2.30% December 1, 2025 4
PECO Loan Agreement 2.00% June 20, 2023 50
BGE Notes 3.35% July 1, 2023 300
DPL First Mortgage Bonds 3.50% November 15, 2023 500
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.DividendsQuarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2024 and for the first quarter of 2025 were as follows:Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)First Quarter 2024 February 21, 2024 March 4, 2024 March 15, 2024 $ 0.3800
Second Quarter 2024 April 30, 2024 May 13, 2024 June 14, 2024 $ 0.3800
Third Quarter 2024 July 30, 2024 August 12, 2024 September 13, 2024 $ 0.3800
Fourth Quarter 2024 October 29, 2024 November 11, 2024 December 13, 2024 $ 0.3800
First Quarter 2025 February 12, 2025 February 24, 2025 March 14, 2025 $ 0.4000___________(a) Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.Credit Matters and Cash RequirementsThe Registrants fund liquidity needs for capital expenditures, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $2.6 billion was available to support additional commercial paper as of December 31, 2024, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2024 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2024 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.
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Table of ContentsThe Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering (the “Offering”) of 11.3 million shares (the “Shares”) of its Common stock, no par value (“Common Stock”). The Shares were sold to the underwriters at a price per share of $43.32. Exelon also granted the underwriters an option to purchase an additional 1.695 million shares of Common stock also at the price per share of $43.32. On August 5, 2022, the underwriters exercised the option in full. The net proceeds from the Offering and the exercise of the underwriters’ option were $563 million before expenses paid by Exelon. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 16 — Debt and Credit Agreements for additional information on Exelon’s term loan within our 2022 10-K.
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. In the fourth quarter 2023, Exelon issued approximately 3.6 million shares of Common stock at an average gross price of $39.58 per share. In the third quarter 2024, Exelon issued approximately 4 million shares of Common Stock at an average gross price of $37.60 per share. The net proceeds from the 2023 and 2024 issuances were $140 million and $148 million, which were used for general corporate purposes. As of December 31, 2024, $708 million of Common stock remained available for sale pursuant to the ATM program.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2024 and available credit facility capacity prior to any incremental collateral at December 31, 2024:PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental CollateralComEd $ 4 $ — $ 949
PECO — 51 404
BGE — 91 400
Pepco — — 98
DPL — 10 156
ACE — — 114__________
(a) Represents incremental collateral related to natural gas procurement contracts.Capital Expenditures
82Table of ContentsAs of December 31, 2024, estimates of capital expenditures for plant additions and improvements are as follows:(in millions) (a)2025 Transmission
2025 Distribution
2025 Gas
Total 2025
Beyond 2025 (b)
Exelon N/A N/A N/A $ 9,075 $ 28,925
ComEd 975 2,225 N/A 3,200 10,650
PECO 200 1,300 375 1,875 5,900
BGE 700 625 525 1,850 5,950
PHI 675 1,400 75 2,150 6,400
Pepco 275 775 N/A 1,050 3,000
DPL 175 325 75 575 1,900
ACE 225 275 N/A 500 1,475___________
(a) Numbers rounded to the nearest $25M and may not sum due to rounding.(b) Includes estimated capital expenditures for the Utility Registrants from 2026 to 2028.Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.
Retirement BenefitsManagement considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given they are not subject to statutory minimum contribution requirements.While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.83Table of ContentsThe following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2025:Qualified Pension Plans Non-Qualified Pension Plans OPEBExelon $ 275 $ 16 $ 45
ComEd 187 2 21
PECO 9 1 1
BGE 26 1 14
PHI 36 8 7
Pepco 1 1 6
DPL 1 — 1
ACE 4 — 1To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.Cash Requirements for Other Financial CommitmentsThe following tables summarize the Registrants' future estimated cash payments as of December 31, 2024 under existing financial commitments:Exelon2025 Beyond 2025 Total Time PeriodLong-term debt and finance leases (a)$ 1,453 $ 43,215 $ 44,668 2025 - 2054Interest payments on long-term debt (b)1,922 29,825 31,747 2025 - 2054
Operating leases 49 265 314 2025 - 2099Fuel purchase agreements (c)293 1,613 1,906 2025 - 2039
Electric supply procurement 3,716 2,217 5,933 2025 - 2028
Long-term renewable energy and REC commitments 422 2,541 2,963 2025 - 2044
Other purchase obligations (d)
5,532 5,431 10,963 2025 - 2034
ZEC commitments 140 292 432 2025 - 2027
Pension contributions (e)
275 1,375 1,650 2025 - 2030
Total cash requirements $ 13,802 $ 86,774 $ 100,576__________
(a) Includes amounts from ComEd and PECO financing trusts.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2024. Includes estimated interest payments due to ComEd and PECO financing trusts.(c) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(d) Represents the future estimated value at December 31, 2024 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants or subsidiary and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
(e) These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2030 are not included.
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ComEd2025 Beyond 2025 Total Time PeriodLong-term debt (a)$ — $ 12,368 $ 12,368 2026 - 2054Interest payments on long-term debt (b)507 8,601 9,108 2025 - 2054
Operating leases — — — 2025 - 2026
Electric supply procurement 365 174 539 2025 - 2027
Long-term renewable energy and REC commitments 401 2,416 2,817 2025 - 2044Other purchase obligations (c)1,712 883 2,595 2025 - 2034
ZEC commitments 140 292 432 2025 - 2027
Total cash requirements $ 3,125 $ 24,734 $ 27,859__________
(a) Includes amounts from ComEd financing trust.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.
(c) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.PECO2025 Beyond 2025 Total Time PeriodLong-term debt (a)$ 350 $ 5,609 $ 5,959 2025 - 2054Interest payments on long-term debt (b)250 4,752 5,002 2025 - 2054
Operating leases — — — 2025 - 2034Fuel purchase agreements (c)135 534 669 2025 - 2039
Electric supply procurement 698 188 886 2025 - 2026Other purchase obligations (d)1,059 610 1,669 2025 - 2031
Total cash requirements $ 2,492 $ 11,693 $ 14,185__________
(a) Includes amounts from PECO financing trusts.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.(c) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(d) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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BGE2025 Beyond 2025 Total Time Period
Long-term debt $ — $ 5,450 $ 5,450 2026 - 2054Interest payments on long-term debt (a)228 4,418 4,646 2025 - 2054
Operating leases 4 33 37 2025 - 2099Fuel purchase agreements (b)125 882 1,007 2025 - 2038
Electric supply procurement 1,197 800 1,997 2025 - 2027Other purchase obligations (c)1,197 1,693 2,890 2025 - 2034
Total cash requirements $ 2,751 $ 13,276 $ 16,027__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.PHI2025 Beyond 2025 Total Time Period
Long-term debt and finance leases $ 290 $ 8,502 $ 8,792 2025 - 2054Interest payments on long-term debt (a)394 5,802 6,196 2025 - 2054
Operating leases 36 132 168 2025 - 2032Fuel purchase agreements (b)33 197 230 2025 - 2030
Electric supply procurement 1,456 1,055 2,511 2025 - 2028
Long-term renewable energy commitments 21 125 146 2025 - 2033Other purchase obligations (c)1,093 1,339 2,432 2025 - 2033
Total cash requirements $ 3,323 $ 17,152 $ 20,475__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2024.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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Pepco2025 Beyond 2025 Total Time Period
Long-term debt and finance leases $ 6 $ 4,421 $ 4,427 2025 - 2054Interest payments on long-term debt (a)210 3,265 3,475 2025 - 2054
Operating leases 6 29 35 2025 - 2032
Electric supply procurement 613 520 1,133 2025 - 2028Other purchase obligations (b)571 632 1,203 2025 - 2033
Total cash requirements $ 1,406 $ 8,867 $ 10,273__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.DPL2025 Beyond 2025 Total Time Period
Long-term debt and finance leases $ 130 $ 2,106 $ 2,236 2025 - 2054Interest payments on long-term debt (a)96 1,620 1,716 2025 - 2054
Operating leases 8 40 48 2025 - 2032Fuel purchase agreements (b)33 197 230 2025 - 2030
Electric supply procurement 471 285 756 2025 - 2027
Long-term renewable energy commitments 21 125 146 2025 - 2033Other purchase obligations (c)270 231 501 2025 - 2031
Total cash requirements $ 1,029 $ 4,604 $ 5,633__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2024.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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ACE2025 Beyond 2025 Total Time Period
Long-term debt and finance leases $ 154 $ 1,789 $ 1,943 2025 - 2054Interest payments on long-term debt (a)74 825 899 2025 - 2054
Operating leases 3 6 9 2025 - 2032
Electric supply procurement 372 250 622 2025 - 2027Other purchase obligations (b)223 432 655 2025 - 2029
Total cash requirements $ 826 $ 3,302 $ 4,128__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2024 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b) Represents the future estimated value, as of December 31, 2024, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
See Note 18 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements:Item Location within Notes to the Consolidated Financial StatementsLong-term debt Note 16 — Debt and Credit Agreements
Interest payments on long-term debt Note 16 — Debt and Credit Agreements
Finance leases Note 10 — Leases
Operating leases Note 10 — Leases
Long-term renewable energy and REC commitments Note 3 — Regulatory Matters
ZEC commitments Note 3 — Regulatory Matters
DC PLUG obligation Note 3 — Regulatory Matters
Pension contributions Note 14 — Retirement BenefitsCredit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. P HI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
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Capital StructureAs of December 31, 2024, the capital structures of the Registrants consisted of the following:Exelon ComEd PECO BGE PHI Pepco DPL ACELong-term debt 60 % 44 % 44 % 47 % 42 % 49 % 48 % 48 %Long-term debt to affiliates (a)1 % 1 % 1 % — % — % — % — % — %
Common equity 37 % 55 % 53 % 51 % — % 49 % 49 % 47 %Member’s equity — % — % — % — % 56 % — % — % — %Commercial paper and notes payable 2 % — % 2 % 2 % 2 % 2 % 3 % 5 %__________
(a) Includes approximately $390 million, $206 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Registrants did not change for the year ended December 31, 2024. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.
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Intercompany Money PoolTo provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2024, are presented in the following tables.
For the Year Ended December 31, 2024 As of December 31, 2024Exelon Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed)Exelon Corporate $ 626 $ — $ 217
PECO 241 (255) —
BSC — (420) (213)
PHI Corporate — (86) (63)
PCI 59 — 59
For the Year Ended December 31, 2024 As of December 31, 2024PHI Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed)Pepco $ 171 $ (48) $ —
DPL 130 (33) —
ACE — (197) —Shelf Registration StatementsAs of January 1st, 2024 Exelon and the Utility Registrants had an effective combined shelf registration statement, unlimited in amount (“Legacy Registration Statement”). On February 20, 2024, Exelon Corporation filed with the SEC Post-Effective Amendment 1 to its Legacy Registration Statement to remove and withdraw registration of all registered securities of ACE, DPL, PECO and BGE.
On February 21, 2024, Exelon Corporation, together with Pepco and ComEd as co-registrants, filed with the SEC Post-Effective Amendment 2 to its Legacy Registration Statement. Post-Effective Amendment 2 amends the Legacy Registration Statement to include an authorized limit of $7,200 million, which can be used to issue Exelon Corporation debt securities and equity securities, as well as Pepco and ComEd debt securities, through the expiration date of August 3, 2025. The amended Legacy Registration Statement was declared effective by the SEC on April 30, 2024. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon Corporation, ComEd, Pepco, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
As a result of Post-Effect Amendment 1, DPL and ACE filed to deregister all securities that remain unsold. DPL and ACE periodically issue securities through the private placement markets. DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.
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Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:At December 31, 2024Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date AmountComEd FERC December 31, 2025 $ 2,500 ICC January 1, 2027 & May 1, 2027 $ 2,318
PECO (b)
FERC December 31, 2025 1,500 PAPUC December 31, 2024 —
BGE FERC December 31, 2025 700 MDPSC N/A 300
Pepco (a)
FERC December 31, 2025 500 MDPSC / DCPSC December 31, 2025 375
DPL (a)
FERC December 31, 2025 500 MDPSC / DEPSC December 31, 2025 375
ACE (c)
NJBPU December 31, 2025 350 NJBPU December 31, 2024 375__________(a) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.
(b) On December 19, 2024, PECO received approval from the PAPUC for $3.5 billion in new long-term financing authority. The financing authority has an effective date of January 1, 2025, and extends through December 31, 2027.
(c) On December 18, 2024, ACE received approval from the NJBPU for $875 million for renewal of their long-term financing authority. The financing authority has an effective date of January 1, 2025, and extends through December 31, 2026.
FY 2025-12-31 (later)
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 OverviewExelon 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 OperationsGAAP 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 33Other (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:
39Table 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.40Table of ContentsThe 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 ShareNet 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 DevelopmentsAt-the-Market ProgramDuring 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.
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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, 2025PECO - Pennsylvania March 28, 2024 Electric $ 464 $ 354 N/A December 12, 2024 January 1, 2025
Natural Gas $ 111 $ 78BGE - 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, 2025Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50% June 10, 2024 April 1, 2024DPL - 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, 2023September 20, 2024 (amended September 5, 2025) Natural Gas $ 37 $ 22 9.60% December 17, 2025 January 1, 2026ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92 $ 45 9.60% November 17, 2023 December 1, 2023November 21, 2024 Electric $ 109 $ 54 9.60% November 21, 2025 December 1, 2025
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Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval TimingPepco - Maryland October 14, 2025 Electric $ 133 10.50% Third quarter of 2026
DPL - Delaware December 9, 2025 Electric $ 45 10.50% Third quarter of 2027Transmission Formula RatesThe 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 ProceedingsThe 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.
43Table of ContentsAllocation 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 ActOn 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
44Table 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.
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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.
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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 include47
Table of Contentscollection 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 capital48
Table of Contentscash 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.
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Table of ContentsRetirement 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.50Table 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 TotalChange 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. The51
Table of ContentsRegistrants 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 ContentsComEd
Results of Operations by Registrant
Results of Operations—ComEd2025 2024 (Unfavorable) Favorable Variance
Operating revenues $ 7,267 $ 8,219 $ (952)Operating expensesPurchased 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 217Other 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.
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ComEdTransmission 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.
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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)$ 56Regulatory 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.
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PECO
Results of Operations—PECO2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 4,684 $ 3,973 $ 711Operating expensesPurchased 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 328Other 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. 2024Increase (Decrease)
Electric Gas TotalWeather $ 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:
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PECO
For the Years Ended December 31, % ChangePECO 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.
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PECOTransmission 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. 2024Increase (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 $ 75The 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.
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PECOInterest 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.
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BGE
Results of Operations—BGE2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 5,222 $ 4,426 $ 796Operating expensesPurchased 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 177Other 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
IncreaseElectric Gas TotalDistribution $ 82 $ 62 $ 144
Transmission 6 — 6
Other 11 — 11
99 62 161
Regulatory required programs 471 164 635
Total increase $ 570 $ 226 $ 796
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BGERevenue 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 1,345,150At 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.
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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 $ 13Regulatory 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.
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PHI
Results of Operations—PHIPHI’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 33Other (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.
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Pepco
Results of Operations—Pepco2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 3,454 $ 3,039 $ 415Operating expensesPurchased power 1,262 1,055 (207)Operating and maintenance625 534 (91)Depreciation and amortization433 407 (26)Taxes other than income taxes455 424 (31)
Total operating expenses 2,775 2,420 (355)
(Loss) gain on sales of assets 1 (1) 2
Operating income 680 618 62Other income and (deductions)
Interest expense, net(214) (192) (22)Other, net41 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. 2024Increase (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.
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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.
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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. 2024Increase (Decrease)
Depreciation and amortization (a)$ 24
Regulatory asset amortization 6Regulatory 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.
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DPL
Results of Operations—DPL2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 1,971 $ 1,787 $ 184Operating expensesPurchased power and fuel 861 760 (101)Operating and maintenance391 377 (14)Depreciation and amortization252 245 (7)Taxes other than income taxes88 79 (9)
Total operating expenses 1,592 1,461 (131)
Operating income 379 326 53Other income and (deductions)
Interest expense, net(102) (93) (9)Other, net16 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 TotalWeather $ 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
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DPLrelated 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, % ChangeDelaware 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, % ChangeDelaware 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 %
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DPL
At December 31,Number of Delaware Natural Gas Customers 2025 2024
Residential 132,148 131,392
Small commercial & industrial 10,255 10,218Large commercial & industrial 14 14Transportation 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 .
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DPL
The changes in Operating and maintenance expense consisted of the following:2025 vs. 2024Increase (Decrease)Credit loss expense $ 3
Pension and non-pension postretirement benefits expense 1Labor, 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. 2024Increase (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.
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ACE
Results of Operations—ACE2025 2024 Favorable (Unfavorable) Variance
Operating revenues $ 1,718 $ 1,628 $ 90Operating expensesPurchased power 808 698 (110)Operating and maintenance328 368 40Depreciation and amortization248 278 30Taxes other than income taxes9 9 —
Total operating expenses 1,393 1,353 (40)
Gain on sale of assets 2 — 2
Operating income 327 275 52Other income and (deductions)
Interest expense, net(82) (79) (3)Other, net10 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.
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ACEAt 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. 2024Increase (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.
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ACE
The changes in Depreciation and amortization expense consisted of the following:2025 vs. 2024Increase (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 ActivitiesThe 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.
73Table of ContentsSee 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 ACENet income (loss) $ 308 $ 81 $ 263 $ 51 $ 58 $ 11 $ 15 $ 33Adjustments 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
74Table of Contentsenergy efficiency and demand response programs spend for BGE, Pepco, DPL, and ACE of $85 million, $41 million, $16 million, and $55 million for the year ended December 31, 2025, respectively, and $127 million, $52 million, $21 million, and $37 million for the year ended December 31, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to a regulatory asset for the years ended December 31, 2025 and 2024.
• Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $(1,017) million and $(807) million. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities owe money to ComEd as a result of the established pricing for CMCs. For the year ended December 31, 2025, the established pricing resulted in nuclear-powered generating facilities owing payments to ComEd primarily due to $804 million of nuclear production tax credits, which is reported within the cash flows from operations as a change in Accounts receivable. This change is offset by an increase in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.Cash Flows from Investing ActivitiesThe following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2025 and 2024 by Registrant:
(Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures $ (1,432) $ (704) $ (314) $ (237) $ (193) $ (28) $ 22 $ (17)
Proceeds from sales of assets (34) — — — 4 2 — 2
Other investing activities (17) (1) (3) (3) — — — —
(Decrease) increase in cash flows from investing activities $ (1,483) $ (705) $ (317) $ (240) $ (189) $ (26) $ 22 $ (15)
Significant investing cash flow impacts for the Registrants for 2025 and 2024 were as follows:
• Variances in Capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Registrants.Cash Flows from Financing ActivitiesThe following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2025 and 2024 by Registrant:
Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net $ (583) $ 530 $ (219) $ (14) $ (54) $ 35 $ (64) $ (25)
Long-term debt, net 1,347 175 125 (150) (17) — (17) —
Changes in intercompany money pool — — — — 19 — — —
Issuance of common stock 543 — — — — — — —
Dividends paid on common stock (93) (37) (146) (25) — 32 18 (56)
Distributions to member — — — — (4) — — —
Contributions from parent/member — 164 (18) 294 63 (67) (53) 13
Other financing activities 8 6 (3) 1 13 10 (2) (1)
Increase (decrease) in cash flows from financing activities $ 1,222 $ 838 $ (261) $ 106 $ 20 $ 10 $ (118) $ (69)
Significant financing cash flow impacts for the Registrants for 2025 and 2024 were as follows:
• Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to
75Table of ContentsConsolidated Financial Statements for additional information on Short-term borrowings for the Registrants.
• Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to the debt issuances and redemptions tables below for additional information for the Registrants.• Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.• Issuance of common stock is driven by the issuance of Exelon common stock under the ATM program in 2025 compared to 2024. See Note 17 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
• Exelon’s ability to pay dividends on its Common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting Retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.
• Other financing activities primarily consists of debt issuance costs. See the debt issuances table below for additional information on the Registrants’ debt issuances.
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Debt Issuances and RedemptionsSee Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. The Registrants' debt activities for 2025 and 2024 was as follows:
During 2025, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Junior Subordinated Notes (a)
6.50% March 15, 2055 $1,000 Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon Notes 5.125% March 15, 2031 500 Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon Notes 5.875% March 15, 2055 500 Repay outstanding commercial paper obligations and for general corporate purposes.
Exelon Convertible Senior Notes 3.25% March 15, 2029 1,000 Repay or refinance debt and for general corporate purposes.
ComEd First Mortgage Bonds 5.95% June 1, 2055 725 Repay outstanding commercial paper obligations and for general corporate purposes.
PECO First Mortgage Bonds 4.875% September 15, 2035 525 Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
PECO First Mortgage Bonds 5.65% September 15, 2055 525 Repay existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
BGE Notes 5.45% June 1, 2035 650 Repay outstanding commercial paper obligations and for general corporate purposes.
Pepco First Mortgage Bonds 5.78% September 17, 2055 75 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.48% March 26, 2040 200 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.28% March 26, 2035 125 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.28% March 26, 2035 100 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.54% November 19, 2040 75 Repay existing indebtedness and for general corporate purposes.
ACE First Mortgage Bonds 5.81% November 19, 2055 75 Repay existing indebtedness and for general corporate purposes.
__________
(a) The Junior Subordinated Notes bear interest at 6.50% per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975%.
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Table of ContentsDuring 2024, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of ProceedsExelon Notes 5.15% March 15, 2029 $650 Repay existing indebtedness and for general corporate purposes.
Exelon Notes 5.45% March 15, 2034 650 Repay existing indebtedness and for general corporate purposes.
Exelon Notes 5.60% March 15, 2053 400 Repay existing indebtedness and for general corporate purposes.
ComEd First Mortgage Bonds 5.30% June 1, 2034 400 Repay outstanding commercial paper obligations and to fund other general corporate purposes.
ComEd First Mortgage Bonds 5.65% June 1, 2054 400 Repay outstanding commercial paper obligations and to fund other general corporate purposes.
PECO First Mortgage Bonds 5.25% September 15, 2054 575 Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
BGE Notes 5.30% June 1, 2034 400 Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.
BGE Notes 5.65% June 1, 2054 400 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.20% March 15, 2034 375 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.50% March 15, 2054 300 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 5.24% March 20, 2034 100 Repay existing indebtedness and for general corporate purposes.DPL First Mortgage Bonds 5.55% March 20, 2054 75 Repay existing indebtedness and for general corporate purposes.DPL First Mortgage Bonds 5.55% March 20, 2054 75 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.29% August 28, 2034 75 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 5.49% August 28, 2039 100 Repay existing indebtedness and for general corporate purposes.
During 2025, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount
Exelon Senior Notes 3.95% June 15, 2025 $ 807
Exelon Software Licensing Agreement 2.30% December 1, 2025 4
PECO First Mortgage Bonds 3.15% October 15, 2025 350
ACE Senior Notes 3.50% December 1, 2025 150
78Table of ContentsDuring 2024, the following long-term debt was retired and/or redeemed:Company (a)Type Interest Rate Maturity Amount
Exelon SMBC Term Loan Agreement SOFR plus 0.85% April 8, 2024 $ 500
Exelon Software Licensing Agreement 3.62% December 1, 2025 1
Exelon Software Licensing Agreement 3.95% May 1, 2024 2
Exelon Software Licensing Agreement 2.30% December 1, 2025 4
ComEd First Mortgage Bonds 3.10% November 1, 2024 250
Pepco First Mortgage Bonds 3.60% March 15, 2024 400DPL (b)Unsecured tax-exempt bonds 4.32% July 1, 2024 33
ACE First Mortgage Bonds 3.38% September 1, 2024 150(a) Exelon repurchased a portion of its Senior unsecured notes during 2024. Refer to Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Variable interest on the DPL unsecured tax-exempt bonds reset on a weekly basis.
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective Balance sheets.DividendsQuarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2025 and for the first quarter of 2026 were as follows:Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a)First Quarter 2025 February 12, 2025 February 24. 2025 March 14, 2025 $ 0.4000
Second Quarter 2025 April 29, 2025 May 12, 2025 June 13, 2025 $ 0.4000
Third Quarter 2025 July 29, 2025 August 11, 2025 September 15, 2025 $ 0.4000
Fourth Quarter 2025 October 29, 2025 November 10, 2025 December 15, 2025 $ 0.4000
First Quarter 2026 February 12, 2026 March 2, 2026 March 13, 2026 $ 0.4200___________(a) Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.Credit Matters and Cash RequirementsThe Registrants fund liquidity needs for capital expenditures, working capital, energy hedging, and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets, and large diversified credit facilities. The credit facilities include $4 billion in aggregate total commitments of which $3.3 billion was available to support additional commercial paper as of December 31, 2025, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. During 2025, the Registrants had access to the commercial paper markets and availability under their revolving credit facilities to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.79
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On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. Exelon issued a total of 23.6 million shares of common stock with net proceeds of $979 million under these agreements in the years ended December 31, 2023 through December 31, 2025.
In addition, during the twelve months ended December 31, 2025, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.
No amounts have been or will be recorded on Exelon's Balance sheets with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the twelve months ended December 31, 2025, approximately 15.4 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.
Inclusive of the impact of the forward sale agreements, $1.5 billion of Common stock remained available for sale pursuant to the ATM program as of December 31, 2025.
See Note 17 — Shareholders' Equity of the Combined Notes to the Consolidated Financial Statements for additional information regarding ATM program terms, forward sale agreements, and share-level activity.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2025 and available credit facility capacity prior to any incremental collateral at December 31, 2025:PJM Credit Policy Collateral Other Incremental Collateral Required (a)
Available Credit Facility Capacity Prior to Any Incremental CollateralComEd $ 27 $ — $ 985
PECO — 58 595
BGE — 43 575
Pepco 4 — 55
DPL 1 14 139
ACE — — 92__________
(a) Represents incremental collateral related to natural gas procurement contracts.80Table of ContentsCapital Expenditures
As of December 31, 2025, estimates of future capital expenditures for plant additions and improvements were as follows:(in millions) (a)2026 Transmission
2026 Distribution
2026 Gas
Total 2026
Beyond 2026 (b)
Exelon N/A N/A N/A $ 9,950 $ 31,300
ComEd 1,100 2,425 N/A 3,500 11,450
PECO 450 1,375 400 2,225 7,075
BGE 1,075 575 525 2,175 6,100
PHI 725 1,250 50 2,050 6,650
Pepco 325 650 N/A 975 2,925
DPL 225 325 50 625 2,175
ACE 175 275 N/A 450 1,550___________
(a) Numbers rounded to the nearest $25M and may not sum due to rounding.(b) Includes estimated capital expenditures for the Utility Registrants from 2027 to 2029.Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.
Retirement BenefitsManagement considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.81Table of ContentsThe following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2026:Qualified Pension Plans Non-Qualified Pension Plans OPEBExelon $ 325 $ 19 $ 48
ComEd 217 3 22
PECO 9 1 4
BGE 32 2 14
PHI 48 7 6
Pepco 1 — 6
DPL 1 — —
ACE 14 — —To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.Cash Requirements for Other Financial CommitmentsThe following tables summarize the Registrants' future estimated cash payments as of December 31, 2025 under existing financial commitments:Exelon2026 Beyond 2026 Total Time PeriodLong-term debt and finance leases (a)$ 1,665 $ 47,763 $ 49,428 2026 - 2055Interest payments on long-term debt (b)1,932 31,796 33,728 2026 - 2055
Operating leases 26 187 213 2026 - 2099Fuel purchase agreements (c)321 1,293 1,614 2026 - 2039
Electric supply procurement 4,259 2,733 6,992 2026 - 2029
Long-term renewable energy and REC commitments 290 7,716 8,006 2026 - 2044
ZEC commitments 156 62 218 2026 - 2027
Pension contributions (d)
325 1,625 1,950 2026 - 2031
Other purchase obligations (e)
9,526 5,303 14,829 2026 - 2035
Total cash requirements $ 18,500 $ 98,478 $ 116,978__________
(a) Includes amounts from ComEd and PECO financing trusts.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025. Includes estimated interest payments due to ComEd and PECO financing trusts.(c) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(d) These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2031 are not included.
(e) Represents the future estimated value at December 31, 2025 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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ComEd2026 Beyond 2026 Total Time PeriodLong-term debt (a)$ 500 $ 12,592 $ 13,092 2026 - 2055Interest payments on long-term debt (b)507 9,880 10,387 2026 - 2055
Electric supply procurement 286 273 559 2026 - 2028
Long-term renewable energy and REC commitments 268 7,606 7,874 2026 - 2044
ZEC commitments 156 62 218 2026 - 2027Other purchase obligations (c)2,093 1,076 3,169 2026 - 2034
Total cash requirements $ 3,810 $ 31,489 $ 35,299__________
(a) Includes amounts from ComEd financing trust.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.
(c) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.PECO2026 Beyond 2026 Total Time PeriodLong-term debt (a)$ — $ 6,659 $ 6,659 2026 - 2055Interest payments on long-term debt (b)266 5,895 6,161 2026 - 2055
Operating leases 1 — 1 2026 - 2035Fuel purchase agreements (c)156 578 734 2026 - 2039
Electric supply procurement 767 177 944 2026 - 2027Other purchase obligations (d)1,774 632 2,406 2026 - 2035
Total cash requirements $ 2,964 $ 13,941 $ 16,905__________
(a) Includes amounts from PECO financing trusts.(b) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.(c) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(d) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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BGE2026 Beyond 2026 Total Time Period
Long-term debt $ 350 $ 5,750 $ 6,100 2026 - 2054Interest payments on long-term debt (a)241 4,749 4,990 2026 - 2054
Operating leases 4 29 33 2026 - 2099Fuel purchase agreements (b)130 506 636 2026 - 2039
Electric supply procurement 1,396 961 2,357 2026 - 2028Other purchase obligations (c)2,363 945 3,308 2026 - 2033
Total cash requirements $ 4,484 $ 12,940 $ 17,424__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.PHI2026 Beyond 2026 Total Time Period
Long-term debt and finance leases $ 64 $ 9,225 $ 9,289 2026 - 2055Interest payments on long-term debt (a)389 6,408 6,797 2026 - 2055
Operating leases 13 66 79 2026 - 2032Fuel purchase agreements (b)35 209 244 2026 - 2031
Electric supply procurement 1,810 1,322 3,132 2026 - 2029
Long-term renewable energy commitments 22 110 132 2026 - 2033Other purchase obligations (c)1,749 1,534 3,283 2026 - 2033
Total cash requirements $ 4,082 $ 18,874 $ 22,956__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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Pepco2026 Beyond 2026 Total Time Period
Long-term debt and finance leases $ 6 $ 4,694 $ 4,700 2026 - 2055Interest payments on long-term debt (a)205 3,553 3,758 2026 - 2055
Operating leases 5 25 30 2026 - 2032
Electric supply procurement 936 711 1,647 2026 - 2029Other purchase obligations (b)1,032 836 1,868 2026 - 2033
Total cash requirements $ 2,184 $ 9,819 $ 12,003__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.DPL2026 Beyond 2026 Total Time Period
Long-term debt and finance leases $ 53 $ 2,308 $ 2,361 2026 - 2054Interest payments on long-term debt (a)100 1,695 1,795 2026 - 2054
Operating leases 6 37 43 2025 - 2031Fuel purchase agreements (b)35 209 244 2026 - 2031
Electric supply procurement 474 307 781 2026 - 2028
Long-term renewable energy commitments 22 110 132 2026 - 2033Other purchase obligations (c)401 231 632 2026 - 2031
Total cash requirements $ 1,091 $ 4,897 $ 5,988__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.(c) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
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ACE2026 Beyond 2026 Total Time Period
Long-term debt and finance leases $ 5 $ 2,038 $ 2,043 2026 - 2055Interest payments on long-term debt (a)70 1,068 1,138 2026 - 2055
Operating leases 2 5 7 2026 - 2030
Electric supply procurement 400 304 704 2026 - 2028Other purchase obligations (b)255 428 683 2026 - 2030
Total cash requirements $ 732 $ 3,843 $ 4,575__________(a) Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b) Represents the future estimated value, as of December 31, 2025, of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business, and not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
See Note 16 — Commitments and Contingencies and Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the tables above in the Combined Notes to the Consolidated Financial Statements:Item Location within Notes to the Consolidated Financial StatementsLong-term debt Note 14 — Debt and Credit Agreements
Interest payments on long-term debt Note 14 — Debt and Credit Agreements
Finance leases Note 9 — Leases
Operating leases Note 9 — Leases
Long-term renewable energy and REC commitments Note 2 — Regulatory Matters
ZEC commitments Note 2 — Regulatory Matters
Pension contributions Note 12 — Retirement BenefitsCredit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. P HI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.
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Capital StructureAs of December 31, 2025, the capital structures of the Registrants consisted of the following:Exelon ComEd PECO BGE PHI Pepco DPL ACELong-term debt 62 % 45 % 45 % 48 % 41 % 48 % 48 % 48 %Long-term debt to affiliates (a)— % 1 % 1 % — % — % — % — % — %
Common equity 37 % 54 % 54 % 52 % — % 49 % 49 % 48 %Member’s equity — % — % — % — % 56 % — % — % — %Commercial paper and notes payable 1 % — % — % — % 3 % 3 % 3 % 4 %__________
(a) Includes approximately $390 million, $206 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatory redeemable trust preferred securities of ComEd and PECO.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 13 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the year ended December 31, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.
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Intercompany Money PoolTo provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2025, are presented in the following tables.
For the Year Ended December 31, 2025 As of December 31, 2025Exelon Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed)Exelon Corporate $ 578 $ — $ 250
PECO 336 (253) —
BSC — (413) (233)
PHI Corporate — (85) (80)
PCI 63 — 63
For the Year Ended December 31, 2025 As of December 31, 2025PHI Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed)Pepco $ 20 $ (35) $ —
DPL 48 (1) —
ACE — (46) —Shelf Registration StatementsOn February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.
Pepco, DPL, and ACE periodically issue securities through the private placement markets. Pepco, DPL, and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings, and market conditions.
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Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:At December 31, 2025Short-term Financing Authority Remaining Long-term Financing Authority
Commission Expiration Date Amount Commission Expiration Date AmountComEd (a)(b)
FERC December 31, 2025 $ 2,500 ICC January 1, 2027, May 1, 2027 $ 1,593
PECO (a)
FERC December 31, 2025 1,500 PAPUC December 31, 2027 1,850
BGE (a)
FERC December 31, 2025 700 MDPSC N/A 1,850
Pepco (a)(c)(d)
FERC December 31, 2025 500 MDPSC / DCPSC December 31, 2025 100
DPL (a)(c)(e)
FERC December 31, 2025 500 MDPSC / DEPSC December 31, 2025 172
ACE (f)
NJBPU January 1, 2028 350 NJBPU December 31, 2026 625__________(a) On September 8, 2025, ComEd, PECO, BGE, Pepco, and DPL filed applications with the FERC for renewal of their short-term financing authority through December 31, 2027. On November 7, 2025, ComEd, PECO, BGE, Pepco, and DPL received approval for $2.5 billion, $1.5 billion, $900 million, $700 million, and $700 million, respectively, with an effective date of January 1, 2026.
(b) On December 18, 2025, ComEd received approval from the ICC for $2.8 billion in new long-term debt financing authority, with an effective date of January 1, 2026.
(c) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.
(d) On September 3, 2025 and December 17, 2025, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.1 billion in new long-term financing authority, with an effective date of January 1, 2026.
(e) On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.
(f) On November 21, 2025, ACE received approval from the NJBPU to extend their $350 million short-term financing authority through January 1, 2028, with an effective date of November 28, 2025.