# Exelon Corp: Form 10-K for the period ended Dec 31, 2024

- Company: [Exelon Corp](/companies/exc.md) (CIK 1109357)
- Form: 10-K
- Filed: 2025-02-12
- Accepted by EDGAR: Feb 12, 2025, 14:17 ET
- Period: 2024-12-31
- Accession: 0001109357-25-000043
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1109357/000110935725000043/exc-20241231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1109357/000110935725000043/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2024-01-01 to 2024-12-31 | $23.03bn | us-gaap:Revenues |
| Operating income | 12 months, 2024-01-01 to 2024-12-31 | $4.32bn | us-gaap:OperatingIncomeLoss |
| Income tax | 12 months, 2024-01-01 to 2024-12-31 | $207.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2024-01-01 to 2024-12-31 | $2.46bn | us-gaap:ProfitLoss |
| Diluted shares (weighted) | 12 months, 2024-01-01 to 2024-12-31 | 1,003,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2024-01-01 to 2024-12-31 | $5.57bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2024-01-01 to 2024-12-31 | $7.10bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 12 months, 2024-01-01 to 2024-12-31 | $1.52bn | us-gaap:PaymentsOfDividendsCommonStock |
| Cash and equivalents | at 2024-12-31 | $357.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-12-31 | $8.38bn | us-gaap:AssetsCurrent |
| Total assets | at 2024-12-31 | $107.78bn | us-gaap:Assets |
| Current liabilities | at 2024-12-31 | $9.61bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-12-31 | $80.86bn | us-gaap:Liabilities |
| Current portion of debt | at 2024-12-31 | $1.45bn | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2024-12-31 | $1.86bn | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-12-31 | $26.92bn | us-gaap:StockholdersEquity |

## Business

As filed, 53,143 characters.

### General

### Corporate Structure and Business and Other Information

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its subsidiaries, ComEd, PECO, BGE, Pepco, DPL, and ACE.

| Name of Registrant | Business | Service Territories |
| --- | --- | --- |
| **Commonwealth Edison Company** | Purchase and regulated retail sale of electricity | Northern Illinois, including the City of Chicago |
|  | Transmission and distribution of electricity to retail customers |  |
| **PECO Energy Company** | Purchase and regulated retail sale of electricity and natural gas | Southeastern Pennsylvania, including the City of Philadelphia (electricity) |
|  | Transmission and distribution of electricity and distribution of natural gas to retail customers | Pennsylvania counties surrounding the City of Philadelphia (natural gas) |
| **Baltimore Gas and Electric Company** | Purchase and regulated retail sale of electricity and natural gas | Central Maryland, including the City of Baltimore (electricity and natural gas) |
|  | Transmission and distribution of electricity and distribution of natural gas to retail customers |  |
| **Pepco Holdings LLC** | Utility services holding company engaged, through its reportable segments: Pepco, DPL, and ACE | Service Territories of Pepco, DPL, and ACE |
| **Potomac Electric Power Company** | Purchase and regulated retail sale of electricity | District of Columbia and Major portions of Montgomery and Prince George’s Counties, Maryland |
|  | Transmission and distribution of electricity to retail customers |  |
| **Delmarva Power & Light Company** | Purchase and regulated retail sale of electricity and natural gas | Portions of Delaware and Maryland (electricity) |
|  | Transmission and distribution of electricity and distribution of natural gas to retail customers | Portions of New Castle County, Delaware (natural gas) |
| **Atlantic City Electric Company** | Purchase and regulated retail sale of electricity | Portions of Southern New Jersey |
|  | Transmission and distribution of electricity to retail customers |  |

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 – Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information.

### Business Services

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, finance, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, finance, engineering, customer operations, transmission and distribution planning, asset management, system operations, and power procurement, to PHI operating Registrants. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

### Utility Registrants

### Utility Operations

### Service Territories and Franchise Agreements

The following table presents the size of service territories, populations of each service territory, and the number of customers within each service territory for the Utility Registrants as of December 31, 2024:

*Service Territories (in square miles)*

|  | ComEd | PECO | BGE | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Electric | 11,450 | 1,900 | 2,300 | 650 | 5,400 | 2,700 |
| Natural Gas | N/A | 1,900 | 3,050 | N/A | 250 | N/A |
| Total(a) | 11,450 | 2,100 | 3,250 | 650 | 5,400 | 2,700 |
| Service Territory Population (in millions) |  |  |  |  |  |  |
| Electric | 9.1 | 4.2 | 3.0 | 2.4 | 1.5 | 1.2 |
| Natural Gas | N/A | 2.6 | 2.9 | N/A | 0.6 | N/A |
| Total(b) | 9.1 | 4.2 | 3.2 | 2.4 | 1.5 | 1.2 |
| Main City | Chicago | Philadelphia | Baltimore | District of Columbia | Wilmington | Atlantic City |
| Main City Population | 2.6 | 1.6 | 0.6 | 0.7 | 0.1 | 0.1 |
| Number of Customers (in millions) |  |  |  |  |  |  |
| Electric | 4.1 | 1.7 | 1.3 | 1.0 | 0.6 | 0.6 |
| Natural Gas | N/A | 0.6 | 0.7 | N/A | 0.1 | N/A |
| Total(c) | 4.1 | 1.7 | 1.3 | 1.0 | 0.6 | 0.6 |

(a) The number of total service territory square miles counts once only a square mile that includes both electric and natural gas services, and thus does not represent the combined total square mileage of electric and natural gas service territories.

(b) The total service territory population counts once only an individual who lives in a region that includes both electric and natural gas services, and thus does not represent the combined total population of electric and natural gas service territories.

(c) The number of total customers counts once only a customer who is both an electric and a natural gas customer, and thus does not represent the combined total of electric customers and natural gas customers.

The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations. The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has become effective. ComEd is in the process of pursuing a new agreement with the City.

While Exelon and ComEd cannot predict the ultimate outcome, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

### Utility Regulations

State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight:

| Registrant | Commission |
| --- | --- |
| ComEd | ICC |
| PECO | PAPUC |
| BGE | MDPSC |
| Pepco | DCPSC/MDPSC |
| DPL | DEPSC/MDPSC |
| ACE | NJBPU |

The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. The U.S. Department of Homeland Security (Transportation Security Administration) provided new security directives in 2021 that regulate cyber risks for certain gas distribution operators. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.

### Seasonality Impacts on Delivery Volumes

The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating.

ComEd, BGE, Pepco, DPL Maryland, and ACE have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd's, BGE's, Pepco's, DPL Maryland's, and ACE's electric distribution revenues and BGE's natural gas distribution revenues are not intended to be impacted by delivery volumes. PECO's and DPL Delaware's electric distribution revenues and natural gas distribution revenues are impacted by delivery volumes.

### Electric and Natural Gas Distribution Services

The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. Beginning in 2024 through 2027, ComEd's electric distribution costs are recovered through a multi-year rate plan with case proceedings as filed with the ICC. PECO's and DPL's electric and gas distribution costs and ACE’s electric distribution costs have generally been recovered through base rate case proceedings, with PECO utilizing a fully projected future test year, DPL Delaware's electric and gas distribution services utilizing either a partial actual and partial forecast test year or a fully historical test year, and ACE utilizing a fully historical test year. BGE’s electric and gas distribution costs and Pepco’s and DPL Maryland's electric distribution costs are currently recovered through multi-year rate case proceedings, as the MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

ComEd, Pepco, DPL and ACE customers have the choice to purchase electricity, and PECO and BGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. DPL customers, with the exception of certain commercial and industrial customers, do not have the choice to purchase natural gas from competitive natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO, BGE, and DPL also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier.

For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do 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 a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs from customers without mark-up or with a slight mark-up and therefore record the amounts in Operating revenues and Purchased power and fuel expense. As a result, fluctuations in electricity or natural gas sales and procurement costs have no significant impact on the Utility Registrants’ Net income.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services.

### Procurement of Electricity and Natural Gas

Exelon does not generate the electricity it delivers. The Utility Registrants' electric supply for its customers is primarily procured through contracts as directed by their respective state laws and regulatory commission actions. The Utility Registrants procure electricity supply from various approved bidders or from purchases on the PJM operated markets.

PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms that currently do not exceed three years. PECO, BGE, and DPL each have annual firm transportation contracts of 437,000 mmcf, 283,000 mmcf, and 44,000 mmcf, respectively, for delivery of gas. To supplement gas transportation and supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources:

|  | Peak Natural Gas Sources (in mmcf) LNG Facility | Propane-Air Plant | Underground Storage Service Agreements(a) |
| --- | ---: | ---: | ---: |
| PECO | 1,200 | 150 | 19,400 |
| BGE | 1,056 | 550 | 22,000 |
| DPL | 250 | N/A | 3,900 |

(a) Natural gas from underground storage represents approximately 27%, 40%, and 33% of PECO's, BGE’s, and DPL's 2024-2025 heating season pipeline capacity, respectively.

PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas.

### Energy Efficiency Programs

The Utility Registrants are generally allowed to recover costs associated with energy efficiency and demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.

ComEd, with limited exceptions, earns a return on its energy efficiency costs through a regulatory asset. ACE earns a return on most of its energy efficiency and demand response program costs through a regulatory asset. Historically, BGE, Pepco Maryland, and DPL Maryland deferred most of their energy efficiency program costs to a regulatory asset and either deferred most of their demand response program costs to a regulatory asset or capitalized them. In 2024, BGE, Pepco, and DPL began deferring less energy efficiency and demand response program costs to a regulatory asset. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

### Capital Investment

The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2025 capital expenditures.

### Transmission Services

The Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities at cost-based rates pursuant to tariffs approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees.

PJM is the regional grid operator and operates pursuant to its FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Tariff. PJM operates the PJM energy, capacity, and other wholesale markets. PJM controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis through the transmission facilities of the PJM transmission owners.

The Utility Registrants' transmission rates are based on a FERC approved formula. The rates are updated on an annual basis.

### Exelon’s Strategy and Outlook

Exelon is a transmission and distribution company that delivers electricity and natural gas service to our customers and communities. Exelon's businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting clean energy policies including those that advance our jurisdictions' clean energy targets, and continued commitment to corporate responsibility.

Exelon’s strategy is to improve reliability and operations, enhance the customer experience, and advance clean and affordable energy choices, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The jurisdictions in which Exelon has operations have set some of the nation's leading clean energy targets and our strategy is to enable that future for all our stakeholders. The Utility Registrants invest in rate base that supports service to our customers and the community, including investments that sustain and improve reliability and resiliency and that enhance the service experience of our customers. The Utility Registrants make these investments prudently at a reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results.

Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets, and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.

The Utility Registrants anticipate investing approximately $38 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, new business, and transmission projects, which is projected to result in an increase to current rate base of approximately $20 billion by the end of 2028. These investments provide greater reliability, improved service for our customers, increased capacity to accommodate new technologies and support a cleaner grid, and a stable return for the company.

In August 2021, Exelon announced its Path to Clean goal to collectively reduce its operations-driven GHG emissions 50% by 2030 against a 2015 baseline and to reach net-zero operations-driven GHG emissions by 2050, while supporting customers and communities in achieving their GHG reduction goals (Path to Clean). Exelon's quantitative goals include its Scope 1 and 2 GHG emissions, with the exception of Scope 2 emissions associated with system losses of electric power delivered to customers ("line losses"), and build upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's Path to Clean efforts extend beyond these quantitative goals to include efforts such as customer energy efficiency programs, which support reductions in customers' direct emissions and have the potential to reduce Exelon's Scope 3 emissions and Scope 2 line losses as well. See ITEM 1. BUSINESS — Environmental Matters and Regulation — Climate Change for additional information.

Various regulatory, legislative, operational, market, and financial factors could affect Exelon's success in pursuing its strategies. Exelon continues to assess infrastructure, operational, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information.

### Employees

The Registrants strive to create a diverse workforce and an inclusive workplace so that they can innovate, grow, and meet the needs of their employees, customers, and community. Therefore, the Registrants take steps to attract, develop, and retain highly qualified talent with a broad range of skills, expertise, and backgrounds who reflect the communities they serve. The Registrants strive to foster an environment where all employees are engaged, feel a sense of belonging and can pursue their full potential – providing comprehensive employee development opportunities to build the skills of their workforce and create high performing teams. Employee well-being and safety are a priority. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental, and financial health, and industry-leading paid leave policies.

The Registrants typically conduct an employee engagement survey every other year to gain feedback from employees, help identify organizational strengths, and help identify areas of opportunity for growth. The survey results are reviewed with senior management and the Exelon Board of Directors.

### Diversity Metrics

The following tables show diversity metrics for all employees and management as of December 31, 2024. Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and/or supervisory responsibilities.

| Employees | Exelon(c) | ComEd | PECO | BGE | PHI(d) | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Female(a) | 5,651 | 1,605 | 793 | 845 | 1,345 | 339 | 135 | 104 |
| People of Color(a) | 8,370 | 2,791 | 1,093 | 1,359 | 1,948 | 866 | 236 | 157 |
| Aged \<30 | 2,341 | 784 | 429 | 379 | 440 | 140 | 95 | 61 |
| Aged 30-50 | 11,348 | 3,963 | 1,633 | 1,993 | 2,375 | 751 | 500 | 351 |
| Aged \>50 | 6,325 | 1,800 | 993 | 1,037 | 1,463 | 424 | 328 | 196 |
| Total Employees(b) | 20,014 | 6,547 | 3,055 | 3,409 | 4,278 | 1,315 | 923 | 608 |

12

| Management | Exelon(c) | ComEd | PECO | BGE | PHI(d) | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Female(a) | 1,173 | 253 | 137 | 155 | 254 | 56 | 13 | 18 |
| People of Color(a) | 1,314 | 368 | 143 | 202 | 319 | 117 | 35 | 31 |
| Aged \<30 | 23 | 8 | 2 | — | 8 | 3 | 1 | 1 |
| Aged 30-50 | 2,056 | 554 | 209 | 337 | 457 | 114 | 69 | 44 |
| Aged \>50 | 1,400 | 377 | 164 | 170 | 282 | 64 | 45 | 40 |
| Total Employees in Management(b) | 3,479 | 939 | 375 | 507 | 747 | 181 | 115 | 85 |

(a) Information concerning women and people of color is based on self-disclosed information.

(b) Total employees represents the sum of the aged categories.

(c) Exelon includes individuals employed by BSC in addition to those employed by ComEd, PECO, BGE, and PHI. Exelon Corporate does not employ any individuals.

(d) PHI includes individuals employed by PHISCO in addition to those employed by Pepco, DPL, and ACE.

### Turnover Rates

As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available.

The table below shows the average turnover rate for all employees for the last three years of 2022 to 2024.

|  | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Retirement Age | 2.80% | 3.38% | 3.10% | 2.16% | 2.48% | 2.19% | 2.86% | 2.92% |
| Voluntary | 3.00% | 2.64% | 2.65% | 2.06% | 3.15% | 3.43% | 1.61% | 2.81% |
| Non-Voluntary | 1.00% | 0.87% | 1.37% | 1.06% | 1.16% | 1.77% | 0.62% | 0.70% |

### Collective Bargaining Agreements

Approximately 43% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2024.

|  | Total Employees Covered by CBAs | Number of CBAs | CBAs New and Renewed in 2024(a) | Total Employees Under CBAs New and Renewed in 2024 |
| --- | ---: | ---: | ---: | ---: |
| Exelon | 8,549 | 10 | 3 | 851 |
| ComEd | 3,553 | 2 | — | — |
| PECO | 1,462 | 2 | — | — |
| BGE | 1,485 | 1 | — | — |
| PHI | 2,045 | 5 | 3 | 851 |
| Pepco | 818 | 1 | — | — |
| DPL | 633 | 2 | 2 | 633 |
| ACE | 395 | 2 | 1 | 26 |
| Corporate(b) | 203 | — | — | 192 |

(a) Does not include CBAs that were extended in 2024 while negotiations are ongoing for renewal.

(b) Corporate represents employees employed by BSC or PHISCO.

### Environmental Matters and Regulation

The Registrants are subject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats.

The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the President and Chief Executive Officer; the Senior Vice President and Chief Strategy and Sustainability Officer; as well as senior management of the Utility Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Audit and Risk Committee oversees compliance with environmental laws and regulations, including environmental risks related to Exelon's operations and facilities, as well as SEC disclosures related to environmental matters. Exelon's Corporate Governance Committee has the authority to oversee Exelon’s climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental issues related to these companies. The Exelon Board of Directors has general oversight responsibilities for Environmental, Social, and Governance matters, including strategies and efforts to protect and improve the quality of the environment.

### Climate Change

As detailed below, the Registrants face climate change mitigation and transition risks as well as adaptation risks. Mitigation and transition risks include changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions. Adaptation risk refers to risks to the Registrants' facilities or operations that may result from changes to the physical climate and environment, such as changes to temperature, weather patterns and sea level.

### Climate Change Mitigation and Transition

The Registrants support comprehensive federal climate legislation that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal climate legislation, Exelon supports the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.

The Registrants currently are subject to, and may become subject to additional, federal and/or state law and/or regulations addressing GHG emissions. The direct (Scope 1) GHG emission sources associated with the Registrants include sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, fossil fuel combustion in motor vehicles and refrigerant leakage from chilling and cooling equipment. In addition, PECO, BGE, and DPL, as distributors of natural gas, have natural gas (methane) leakage on the natural gas systems. The Registrants also have indirect (Scope 2 and 3) emissions associated with the production of the electricity they consume and deliver, and indirect (Scope 3) emissions associated with the production of natural gas they deliver and consumer use of such natural gas.

Exelon uses definitions and protocols provided by the World Resources Institute for its GHG inventory. In 2023, Exelon's Scope 1 and 2 GHG emissions were just over 5.3 million metric tons carbon dioxide equivalent using the World Resources Institute Corporate Standard Market-based accounting. Of these emissions, 0.4 million metric tons are considered to be operations-driven and in more direct control of our employees and processes. The majority of these operations-driven emissions are fugitive emissions from the gas delivery systems of Registrants PECO, BGE, and DPL. The remaining 4.9 million metric tons, approximately 92%, are the indirect emissions associated with the electric transmission and distribution system and primarily consists of losses resulting from the Utility Registrant's delivery of electricity to their customers (line losses). These emissions are driven primarily by customer demand for electricity and the mix of generation assets supplying energy to the electric grid. The Registrants do not own generation and must comply with applicable legal and regulatory requirements governing procurement of electricity for delivery to retail customers and use of the system to support other transmission transactions. However, the Registrants do engage in efforts that help to reduce these emissions, including customer programs to drive customer energy efficiency, to help manage peak demands, and to enable distributed solar generation.

In August 2021, Exelon announced a Path to Clean goal to collectively reduce its operations-driven GHG emissions 50% by 2030 against a 2015 baseline, and to reach net-zero operations-driven GHG emissions by 2050, while also supporting customers and communities to achieve their clean energy and emissions reduction goals. Exelon’s quantitative goals include its Scope 1 and 2 GHG emissions with the exception of Scope 2 line losses, and build upon Exelon's long-standing commitment to reducing our GHG emissions. Exelon's activities in support of the Path to Clean goal will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, investments in natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies. Beyond 2030, Exelon recognizes that technology advancement and continued policy support will be needed to ensure achievement of its net-zero goal by 2050. Exelon is laying the groundwork by partnering with national labs, universities, and research consortia to research, develop, and pilot clean technologies, as well as working with our states, jurisdictions, and policy makers to understand the scope and scale of energy transformation, and policies and incentives, needed to reach local ambitions for GHG emissions reductions. The Utility Registrants are also supporting customers and communities to achieve their clean energy and emissions goals through significant energy efficiency programs. Estimated customer program energy efficiency investments across the Utility Registrants for 2025 — 2028 total $4.9 billion. These programs enable customer savings through home energy audits, discounts on efficient lighting, appliance recycling, home improvement rebates, equipment upgrade incentives, and innovative programs like smart thermostats and combined heat and power programs.

As an energy delivery company, Exelon can play a role in helping to reduce GHG emissions in its service territories. In connecting end users of energy to electric and gas supply, Exelon can leverage its assets and customer interface to help support efficient use of lower emitting resources as they become available. Electrification, where feasible, for transportation, buildings, and industry coupled with simultaneous decarbonization of electric generation, can be an important means to reduce emissions. Exelon is advocating for public policy supportive of vehicle electrification, investing in enabling infrastructure and technology, and supporting customer education and adoption. In addition, the Utility Registrants have a goal to electrify 30% of their own vehicle fleet by 2025, increasing to 50% by 2030. Clean fuels and other emerging technologies can also support the transition, lessen the strain on electric system expansion, and support energy system resiliency. Exelon, and its registrants PECO, BGE, and DPL, which own gas distribution assets, are also continuing to explore these other decarbonization opportunities, supporting pilots of emerging energy technologies and clean fuels to support both operational and customer-driven emissions reductions. Exelon believes its market and business model could be significantly affected by the transition of the energy system, such as through an increased electric load and decreased demand for natural gas, potentially accompanied by changes in technology, customer expectations, and/or regulatory structures. See the risk factor entitled "The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry" in ITEM 1A. of this report for additional information.

### Climate Change Adaptation

The Registrants' facilities and operations are subject to the impacts of global climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for the Registrants and their service territories. Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information related to the Registrants' risks associated with climate change.

The Registrants' assets undergo seasonal readiness efforts to ensure that they are prepared for the weather projections for the summer and winter months. The Registrants consider and review national climate assessments to inform their planning. Each of the Utility Registrants also has well established system recovery plans and is investing in its systems to install advanced equipment and reinforce the local electric system, making it more weather resistant and less vulnerable to anticipated storm damage.

***International Climate Change Agreements.*** At the international level, the United States has been a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. Though under the first Trump Administration, the United States formally withdrew from the Paris Agreement, on January 20, 2021, President Biden accepted the Agreement, which resulted in the United States’ formal re-entry on February

19, 2021. Following this reentry, the United States set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030. On November 11, 2022, at the UNFCCC Conference of the Parties (COP 27), President Biden recommitted the U.S. to these goals and detailed the significant domestic climate actions the U.S. had taken to spur a new era of clean American manufacturing, enhance energy security, and drive down the costs of clean energy for consumers in the U.S. and around the world. In January 2025, President Trump issued an Executive Order instructing the federal government to begin the actions needed to withdraw from the Paris Agreement again. This withdrawal process will take a year to complete. President Trump also issued an Executive Order calling for many of the clean energy programs created under IIJA and the IRA to be suspended for 90 days while they are reviewed.

***State Climate Change Legislation and Regulation.*** A number of states in which the Registrants operate have state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact the power sector. See discussion below for additional information on renewable and other portfolio standards.

Certain northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont) currently participate in the RGGI. The program requires most fossil fuel-fired power plant owners and operators in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.

Broader state programs impact other sectors as well, such as the District of Columbia's Clean Energy DC Omnibus Act and cross-sector GHG reduction plans, which resulted in recent requirements for Pepco to develop a 15-year decarbonization program and strategy. Maryland expects to meet and exceed the mandate set in the Greenhouse Gas Emissions Reduction Act to reduce statewide GHG emissions 40% (from 2006 levels) by 2030, and the state’s Climate Solutions Now Act of 2022 further updates requirements with a proposal to reduce emissions 60% (from 2006 levels) by 2031 and achieve net-zero emissions by 2045. New Jersey accelerated its goals through Executive Order 274, which establishes an interim goal of 50% reductions below 2006 levels by 2030 and affirms its goal of achieving 80% reductions by 2050 and includes programs to drive greater amounts of electrified transportation. Delaware's Climate Change Solutions Act, established in August 2023, sets a statewide GHG emissions reduction goal of 50% by Jan 1, 2030 and a net-zero GHG emissions goal by Jan 1, 2050, on a net basis as compared to a 2005 baseline. Illinois’ climate bill, CEJA, establishes decarbonization requirements for the state to transition to 100% clean energy by 2050 and supports programs to improve energy efficiency, manage energy demand, attract clean energy investment, and accelerate job creation. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on CEJA.

The Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements. See ITEM 1A. RISK FACTORS for additional information related to the Registrants' risks associated with climate legislation.

***Renewable and Clean Energy Standards.*** Each of the states where Exelon operates have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through acquiring sufficient bundled or unbundled credits such as RECs, CMCs, or ZECs, or paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

### Other Environmental Regulation

### Water Quality

Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge water into waterways and are therefore subject to these regulations and operate under NPDES permits.

Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in waters of the United States. What constitutes a Water of the United States has been subject to varied definition over the past several Administrations. The most recent definitions established under the Biden Administration are subject to pending legal challenge. It is expected that, under the Trump Administration, the Environmental Protection Agency will issue new regulations that reflect a more narrow scope.

Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.

### Solid and Hazardous Waste and Environmental Remediation

CERCLA provides for response and removal actions coordinated by the EPA in the event of threatened or actual releases of hazardous substances. CERCLA authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly, and severally liable for the cleanup costs of hazardous substances at sites, many of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation, under EPA oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes, and cleanup of sites where such activities were conducted.

The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these federal and state environmental laws. Under these laws, the Registrants may be liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.

ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites, which were operated by ComEd's and PECO's predecessor companies. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover certain environmental remediation costs of the MGP sites through a provision within customer rates. BGE, Pepco, DPL, and ACE do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2025 for activities associated with the environmental investigation and remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $14 million, which consists primarily of $9 million at PECO.

As of December 31, 2024, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.

See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.

### Information about our Executive Officers as of February 12, 2025

### Exelon

| Name | Age | Position | Period |
| --- | ---: | --- | --- |
| Butler Jr., Calvin G. | 55 | President and Chief Executive Officer, Exelon | 2022 - Present |
|  |  | Chief Operating Officer, Exelon | 2021 - 2022 |
|  |  | Senior Executive Vice President, Exelon | 2019 - 2022 |
|  |  | Chief Executive Officer, Exelon Utilities | 2019 - 2022 |
|  |  | Chief Executive Officer, BGE | 2014 - 2019 |
| Glockner, David | 64 | Executive Vice President, Compliance, Audit and Risk, Exelon | 2020 - Present |
|  |  | Chief Compliance Officer, Citadel LLC | 2017 - 2020 |
| Honorable, Colette | 54 | Chief Legal Officer and Corporate Secretary | 2024 - Present |
|  |  | Executive Vice President, Public Policy | 2023 - 2024 |
|  |  | Chief External Affairs Officer | 2023 - 2024 |
|  |  | Partner, Reed Smith LLP | 2017 - 2023 |
| Innocenzo, Michael A. | 59 | Executive Vice President and Chief Operating Officer, Exelon | 2024 - Present |
|  |  | President and Chief Executive Officer, PECO | 2018 - 2024 |
| Jones, Jeanne | 45 | Executive Vice President and Chief Financial Officer, Exelon | 2022 - Present |
|  |  | Senior Vice President, Corporate Finance, Exelon | 2021 - 2022 |
|  |  | Senior Vice President and Chief Financial Officer, ComEd | 2018 - 2021 |
| Kleczynski, Robert A. | 56 | Senior Vice President, Controller and Tax, Exelon | 2023 - Present |
|  |  | Senior Vice President, Exelon | 2020 - 2023 |
|  |  | Vice President, Exelon | 2018 - 2020 |
|  |  | General Tax Officer, Exelon | 2018 - 2023 |

18

### ComEd

| Name | Age | Position | Period |
| --- | ---: | --- | --- |
| Quiniones, Gil | 58 | President, ComEd | 2024 - Present |
|  |  | Chief Executive Officer, ComEd | 2021 - Present |
|  |  | President and Chief Executive Officer, New York Power Authority | 2011 - 2021 |
| Binswanger, Lewis | 65 | Senior Vice President, Governmental, Regulatory and External Affairs, ComEd | 2022 - Present |
|  |  | Vice President, External Affairs, Nicor Gas | 2013 - 2022 |
| Levin, Joshua | 45 | Senior Vice President, Chief Financial Officer & Treasurer, ComEd | 2023 - Present |
|  |  | Vice President, Financial, Planning and Analysis, ComEd | 2021 - 2023 |
|  |  | Director of Financial Planning and Analysis, ComEd | 2019 - 2021 |
| Perez, David R. | 55 | Executive Vice President and Chief Operating Officer, ComEd | 2024 - Present |
|  |  | Senior Vice President, Distribution Operations, ComEd | 2019 - 2023 |
| Rippie, E. Glenn | 64 | Senior Vice President and General Counsel, ComEd | 2022 - Present |
|  |  | Senior Vice President and Deputy General Counsel, Energy Regulation, Exelon | 2022 - Present |
|  |  | Partner, Jenner & Block LLP | 2019 - 2022 |

19

### PECO

| Name | Age | Position | Period |
| --- | ---: | --- | --- |
| Velazquez, David | 65 | President and Chief Executive Officer, PECO | 2024 - Present |
|  |  | Executive Vice President, Operations and Technology, Exelon | 2023 - 2024 |
|  |  | Executive Vice President, Utility Operations, Exelon | 2021 - 2023 |
|  |  | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | 2016 - 2021 |
| Gay, Anthony | 59 | Vice President and General Counsel, PECO | 2019 - Present |
|  |  | Vice President, Governmental and External Affairs, PECO | 2016 - 2019 |
| Humphrey, Marissa | 45 | Senior Vice President, Chief Financial Officer and Treasurer, PECO | 2022 - Present |
|  |  | Vice President, Regulatory Policy and Strategy (NJ/DE), PHI, DPL, and ACE | 2021 - 2022 |
|  |  | Vice President, Finance, Exelon Utilities | 2019 - 2020 |
|  |  | Vice President, Financial Planning and Analysis, PHI, Pepco, DPL, and ACE | 2016 - 2019 |
| Levine, Nicole | 48 | Senior Vice President and Chief Operations Officer, PECO | 2022 - Present |
|  |  | Vice President, Electrical Operations, PECO | 2018 - 2022 |
| Oliver, Douglas | 50 | Senior Vice President, Governmental, Regulatory and External Affairs, PECO | 2023 - Present |
|  |  | Vice President, Governmental and External Affairs, PECO | 2019 - 2023 |
|  |  | Vice President, Communications, PECO | 2018 - 2019 |

20

### BGE

| Name | Age | Position | Period |
| --- | ---: | --- | --- |
| Khouzami, Carim V. | 50 | President, BGE | 2021 - Present |
|  |  | Chief Executive Officer, BGE | 2019 - Present |
| Cloyd, Michael | 54 | Senior Vice President, Chief Financial Officer, and Treasurer, BGE | 2024 - Present |
|  |  | Vice President, Support Services, BGE | 2021 - 2024 |
| Dickens, Derrick | 60 | Senior Vice President and Chief Operating Officer, BGE | 2021 - Present |
|  |  | Senior Vice President, Customer Operations, PHI, Pepco, DPL, and ACE | 2020 - 2021 |
|  |  | Vice President, Technical Services, BGE | 2016 - 2020 |
| Núñez, Alexander G. | 53 | Senior Vice President, Governmental, Regulatory and External Affairs, BGE | 2021 - Present |
|  |  | Senior Vice President, Regulatory Affairs and Strategy, BGE | 2020 - 2021 |
|  |  | Senior Vice President, Regulatory and External Affairs, BGE | 2016 - 2020 |
| Ralph, David | 58 | Vice President and General Counsel, BGE | 2021 - Present |
|  |  | Associate General Counsel, BGE | 2019 - 2021 |
|  |  | Assistant General Counsel, Exelon | 2017 - 2019 |

### PHI, Pepco, DPL, and ACE

| Name | Age | Position | Period |
| --- | ---: | --- | --- |
| Anthony, J. Tyler | 60 | President and Chief Executive Officer, PHI, Pepco, DPL, and ACE | 2021 - Present |
|  |  | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | 2016 - 2021 |
| Bancroft, Anne | 58 | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | 2021 - Present |
|  |  | Associate General Counsel, Exelon | 2017 - 2021 |
| Oddoye, Rodney | 48 | Senior Vice President, Governmental, Regulatory and External Affairs, PHI, Pepco, DPL, and ACE | 2021 - Present |
|  |  | Senior Vice President, Governmental and External Affairs, BGE | 2020 - 2021 |
|  |  | Vice President, Customer Operations, BGE | 2018 - 2020 |
| Olivier, Tamla | 52 | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | 2021 - Present |
|  |  | Senior Vice President, Customer Operations, BGE | 2020 - 2021 |
|  |  | Senior Vice President, Constellation NewEnergy, Inc. | 2016 - 2020 |
| Vahos, David | 52 | Senior Vice President, Chief Financial Officer, and Treasurer, PHI, Pepco, DPL, ACE | 2024 - Present |
|  |  | Senior Vice President, Chief Financial Officer, and Treasurer, BGE | 2016 - 2024 |

21

## Risk factors

As filed, 46,911 characters.

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.

**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, 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.

**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 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.

### 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 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.

**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, 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 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

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 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 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.

**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.

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.

**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.

**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.

## Cybersecurity

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### Risk management and strategy

Cybersecurity risk for all Registrants is managed at the enterprise-level. Management of material risks from cybersecurity threats is integrated into the Registrants' overall risk management processes and is monitored as an enterprise risk. Exelon's Chief Information Security Officer (CISO) and cybersecurity management team regularly hold meetings with senior management of each Registrant, facilitated by Exelon’s enterprise risk management team, to discuss issues pertaining to cybersecurity risk management, including changes in the nature and origin of threats, threat actor and risk mitigation activities, and regulatory developments. Exelon Legal and compliance professionals engage with the CISO and cybersecurity management team to address tactical and strategic cybersecurity risks. Exelon monitors cybersecurity risks through key risk indicators to identify potential changes in risk exposure and provide the Board of Directors with information about the monitoring of key risks in connection with its oversight of the Registrants' enterprise risk management system.

The CISO, through Exelon’s Cyber Information and Security Services (CISS), reviews external and internal sources to obtain cyber threat intelligence to develop strategic and tactical threat assessments that inform the enterprise-wide cyber risk mitigation programs and actions. Exelon uses a wide range of tools, including endpoint, anomaly and network detection, logging and monitoring of security events, network segmentation, firewalls, hardening and securing devices, cyber vulnerability detection and patch management, cyber threat hunting, malware forensic analysis, industry-specific reports, and tabletop exercises to inform the cybersecurity management team. Exelon protects assets critical to grid reliability and national security through the implementation of the North American Electric Reliability Corporation’s Critical Infrastructure Protection requirements, and gas pipeline security under the U.S. Department of Homeland Security’s Transportation Safety Administration’s Security Directives. Exelon maintains security relationships with law enforcement and U.S. intelligence agencies, coordinates with the Electricity Information Sharing and Analysis Center (E-ISAC) and participates in the Department of Energy’s Cybersecurity Risk Information Sharing Program (CRISP) to strengthen the security of the energy grid, share information, design and participate in drills and exercises such as the bi-annual Grid Security Exercises and facilitate cross-sector coordination. Exelon applies stringent employee and contractor screening, and advances security awareness through training and monitoring programs that address both cyber and physical threats. Exelon employees are subject to annual mandatory training addressing security awareness, including cybersecurity and phishing. Exelon maintains cyber insurance coverage at limits consistent with the utility industry and reviews policy coverage and limits on an annual basis.

In assessing the effectiveness of its cybersecurity risk management program, the CISO makes use of external perspectives from regulatory compliance audits and inspections, external audits of the Registrants' financial systems, and third-party incident response and detection analytics. Cybersecurity risks associated with the Registrants’ use of certain third-party service providers are evaluated and managed through CISS' Third Party Security team that leverages security risk assessments, contractual terms and conditions, and security awareness training for such providers. Additionally, those providers are required to report cybersecurity incidents, including the unauthorized use or disclosure of Registrants’ confidential information to Exelon’s security operations center. Third Party Security investigates certain third-party cybersecurity events as part of Exelon’s incident response program.

### Governance

The Exelon Board of Directors is responsible for oversight of risks from cybersecurity threats. As part of its responsibility and as documented in the Cybersecurity Oversight Policy, the Board of Directors oversees Exelon's cybersecurity program and Exelon’s enterprise-wide risk related to cybersecurity, including management’s identification, assessment, and mitigation of cybersecurity risks. At each regular quarterly meeting, the Board of Directors engages with the CISO and a cross-functional management team regarding the risks from cybersecurity threats. The CISO and professionals from the legal and compliance departments brief the Board of Directors on relevant topics, including information security and operational security, legislative and regulatory developments, and notable external cyber events relevant to Exelon and the industry more broadly. Management engages with the Board of Directors on risks from cybersecurity threats as appropriate outside of the quarterly meetings.

The CISO manages Exelon's enterprise-wide cybersecurity programs and reports to Exelon’s Chief Information Officer. The CISO has been responsible for assessing and managing material risks from cybersecurity threats at Exelon since 2018 and was named to the current role in 2022. The CISO has 26 years of information technology and cybersecurity experience in the critical infrastructure sector, of which 24 years have been in the utility industry. The CISO leads CISS, which manages centralized information technology and operational technology security programs for the Registrants. The programs are aligned to the National Institute of Standards and Technology Cyber Security Framework (NIST CSF) and integrate cyber asset identification; threat assessment;

risk assessment; risk management; and risk monitoring. CISS operates a security operations center for monitoring, identifying, and mitigating potential cybersecurity events or incidents.

Exelon maintains a single, centralized cybersecurity incident response program and plan that aligns with NIST CSF by integrating the identify, determine/classify, escalate and respond functions (which track the lifecycle of an event or incident). Security threats and incidents are identified and assessed to determine potential impact and escalated to senior cybersecurity management and the CISO. The CISO directs the security incident response team to contain, eradicate, and recover from an active threat. Exelon leverages the expertise of dedicated incident response vendors that can provide timely and specialized support to respond and recover from an event. The CISO and a cross-functional team convene as needed to evaluate cybersecurity events, including third-party events. The legal and compliance departments provide incident response support to the CISO, manage cybersecurity-related legal and compliance issues, and direct materiality evaluations using both qualitative and quantitative factors for each Registrant.

Although the Registrants have not experienced any material cybersecurity events to date, cybersecurity threats could materially affect each Registrant’s business strategy, results of operations, or financial condition, as further discussed in the risk factor entitled “The Registrants are subject to physical and cybersecurity risks" in ITEM 1A. of this report.

## Properties

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### The Utility Registrants

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

### Transmission and Distribution

The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2024 were as follows:

| Voltage (Volts) | Circuit Miles ComEd | PECO | BGE | Pepco | DPL | ACE |
| ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 765,000 | 90 | — | — | — | — | — |
| 500,000(a) | — | 188 | 216 | 109 | 16 | — |
| 345,000 | 2,678 | — | — | — | — | — |
| 230,000 | — | 550 | 352 | 792 | 472 | 259 |
| 138,000 | 2,268 | 135 | 55 | 61 | 587 | 215 |
| 115,000 | — | — | 700 | 26 | — | — |
| 69,000 | — | 177 | — | — | 568 | 675 |

(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 8 — Jointly Owned Electric Utility Plant of the Combined Notes to the Consolidated Financial Statements for additional information.

The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines:

| Circuit Miles | ComEd | PECO | BGE | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Overhead | 35,340 | 12,982 | 9,128 | 4,170 | 6,022 | 7,339 |
| Underground | 32,993 | 9,814 | 18,197 | 7,385 | 6,669 | 3,055 |

### Gas

The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2024:

|  | PECO | BGE | DPL |
| --- | ---: | ---: | ---: |
| Transmission(a) | 6 | 146 | 8 |
| Distribution | 7,305 | 7,644 | 2,225 |
| Service piping | 6,533 | 6,518 | 1,497 |
| **Total** | 13,844 | 14,308 | 3,730 |

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

The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:

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

PECO, BGE, and DPL also own 30, 27, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.

### First Mortgage and Insurance

The principal properties of ComEd, PECO, Pepco, DPL, and ACE are subject to the lien of their respective mortgages under which their respective First Mortgage Bonds are issued. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.

### Exelon

### Security Measures

The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.

## Legal proceedings

As filed, 408 characters.

### All Registrants

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

## Management's discussion and analysis

As filed, 156,816 characters.

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

### Exelon

### Executive Overview

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 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 Operations

***GAAP 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 | 35 |
| Other(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.

***Year 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.

The 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:

*(In millions, except per share data)*

|  | 2024 | Earnings per Diluted Share | 2023 | Earnings per Diluted Share |
| --- | ---: | ---: | ---: | ---: |
| **Net 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 | 0.01 |
| Income 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 Developments

### At-the-Market Program

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 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.

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

44

#### Pending Distribution Base Rate Case Proceedings

| Registrant/Jurisdiction | Filing Date | Service | Requested Revenue Requirement Increase | Requested ROE | Expected Approval Timing |
| --- | --- | --- | ---: | ---: | --- |
| DPL - 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 2025 |

### Transmission Formula Rates

The 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 Proceedings

The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 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 Act

On 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 negotiation: (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.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital 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.

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.

### 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.

***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:

| Actuarial Assumption Change in 2024 cost: | Actual Assumption Pension | OPEB | Change in Assumption | (Decrease) Increase Pension | OPEB | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| 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.

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.

***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 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 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.

### 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.

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.

ComEd

### Results of Operations by Registrant

### Results of Operations—ComEd

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $8,219 | $7,844 | $375 |
| **Operating expenses** |  |  |  |
| Purchased 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 | $375 |

***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.*** 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

ComEd

recoverable 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 recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission 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 utilities 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.

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 Increase |
| --- | ---: |
| Depreciation and amortization(a) | $70 |
| Regulatory 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.

PECO

### Results of Operations—PECO

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $3,973 | $3,894 | $79 |
| **Operating expenses** |  |  |  |
| Purchased 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. 2023 Increase (Decrease) Electric | Gas | Total |
| --- | ---: | ---: | ---: |
| Weather | $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:

PECO

| PECO Service Territory | For the Years Ended December 31, 2024 | 2023 | Normal | % Change 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% |

| Number of Electric Customers | At December 31, 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)% |

| Number of Gas Customers | At December 31, 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.

PECO

***Transmission Revenue.*** Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue 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. 2023 Increase (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 | $117 |

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

|  | 2024 vs. 2023 Increase |
| --- | ---: |
| Depreciation 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.

PECO

**Interest 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.

BGE

### Results of Operations—BGE

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $4,426 | $4,027 | $399 |
| **Operating expenses** |  |  |  |
| Purchased 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 | Total |
| --- | ---: | ---: | ---: |
| Distribution | $94 | $128 | $222 |
| Transmission | 25 | — | 25 |
| Other | 2 | (2) | — |
|  | 121 | 126 | 247 |
| Regulatory required programs | 207 | (55) | 152 |
| Total increase | $328 | $71 | $399 |

62

BGE

***Revenue 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.

| Number of Electric Customers | At December 31, 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 | 1,341,009 |

| Number of Gas Customers | At December 31, 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.

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) | 77 |
| Other(b) | 33 |
|  | 175 |
| Regulatory 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 information

The 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.

PHI

### Results of Operations—PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the year ended December 31, 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 | 35 |
| Other(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.

Pepco

### Results of Operations—Pepco

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $3,039 | $2,824 | $215 |
| **Operating expenses** |  |  |  |
| Purchased power | 1,055 | 974 | (81) |
| Operating and maintenance | 534 | 572 | 38 |
| Depreciation and amortization | 407 | 441 | 34 |
| Taxes other than income taxes | 424 | 390 | (34) |
| Total operating expenses | 2,420 | 2,377 | (43) |
| **(Loss) gain on sales of assets** | (1) | 9 | (10) |
| **Operating income** | 618 | 456 | 162 |
| **Other income and (deductions)** |  |  |  |
| Interest expense, net | (192) | (165) | (27) |
| Other, net | 54 | 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. 2023 Increase (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.

Pepco

| Number of Electric Customers | At December 31, 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.

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. 2023 Increase (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.

DPL

### Results of Operations—DPL

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $1,787 | $1,688 | $99 |
| **Operating expenses** |  |  |  |
| Purchased power and fuel | 760 | 737 | (23) |
| Operating and maintenance | 377 | 364 | (13) |
| Depreciation and amortization | 245 | 244 | (1) |
| Taxes other than income taxes | 79 | 75 | (4) |
| Total operating expenses | 1,461 | 1,420 | (41) |
| **Operating income** | 326 | 268 | 58 |
| **Other income and (deductions)** |  |  |  |
| Interest expense, net | (93) | (74) | (19) |
| Other, net | 25 | 18 | 7 |
| Total 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 Increase Electric | Gas | Total |
| --- | ---: | ---: | ---: |
| Weather | $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.

DPL

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, 2024 compared to same period in 2023 and normal weather consisted of the following:

| Delaware Electric Service Territory | For the Years Ended December 31, 2024 | 2023 | Normal | % Change 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)% |

| Delaware Natural Gas Service Territory | For the Years Ended December 31, 2024 | 2023 | Normal | % Change 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% |

| Number of Total Electric Customers (Maryland and Delaware) | At December 31, 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% |

70

DPL

| Number of Delaware Natural Gas Customers | At December 31, 2024 | 2023 |
| --- | ---: | ---: |
| Residential | 131,392 | 129,903 |
| Small commercial & industrial | 10,218 | 10,133 |
| Large commercial & industrial | 14 | 14 |
| Transportation | 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.

DPL

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

|  | 2024 vs. 2023 Increase (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) |
|  | $1 |
| Regulatory 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. 2023 Increase (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.

ACE

### Results of Operations—ACE

|  | 2024 | 2023 | Favorable (Unfavorable) Variance |
| --- | ---: | ---: | ---: |
| **Operating revenues** | $1,628 | $1,522 | $106 |
| **Operating expenses** |  |  |  |
| Purchased power | 698 | 637 | (61) |
| Operating and maintenance | 368 | 386 | 18 |
| Depreciation and amortization | 278 | 283 | 5 |
| Taxes other than income taxes | 9 | 8 | (1) |
| Total operating expenses | 1,353 | 1,314 | (39) |
| **Operating income** | 275 | 208 | 67 |
| **Other income and (deductions)** |  |  |  |
| Interest expense, net | (79) | (72) | (7) |
| Other, net | 14 | 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.

| Number of Electric Customers | At December 31, 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 |

73

ACE

***Distribution 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. 2023 Increase (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.

ACE

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

|  | 2024 vs. 2023 Increase (Decrease) |
| --- | ---: |
| Depreciation and amortization(a) | $15 |
| Regulatory asset amortization | 5 |
| Regulatory 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 Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so 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 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 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 | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Net income (loss) | $132 | $(24) | $(12) | $42 | $151 | $84 | $32 | $35 |
| Adjustments 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

and 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 Activities

The 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 Activities

The 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.
- **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.

### Debt Issuances and Redemptions

See 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 Proceeds |
| --- | --- | ---: | --- | ---: | --- |
| Exelon | 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. |

79

During 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 | 400 |
| DPL(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.

(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.

### Dividends

Quarterly 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 Requirements

The 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.

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.

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 Collateral |
| --- | ---: | ---: | ---: |
| ComEd | $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

As 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 Benefits

Management 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.

The 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 | OPEB |
| --- | ---: | ---: | ---: |
| Exelon | $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 | — | 1 |

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 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

### Cash Requirements for Other Financial Commitments

The following tables summarize the Registrants' future estimated cash payments as of December 31, 2024 under existing financial commitments:

### Exelon

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt and finance leases(a) | $1,453 | $43,215 | $44,668 | 2025 - 2054 |
| Interest payments on long-term debt(b) | 1,922 | 29,825 | 31,747 | 2025 - 2054 |
| Operating leases | 49 | 265 | 314 | 2025 - 2099 |
| Fuel 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.

### ComEd

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt(a) | $— | $12,368 | $12,368 | 2026 - 2054 |
| Interest 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 - 2044 |
| Other 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.

### PECO

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt(a) | $350 | $5,609 | $5,959 | 2025 - 2054 |
| Interest payments on long-term debt(b) | 250 | 4,752 | 5,002 | 2025 - 2054 |
| Operating leases | — | — | — | 2025 - 2034 |
| Fuel purchase agreements(c) | 135 | 534 | 669 | 2025 - 2039 |
| Electric supply procurement | 698 | 188 | 886 | 2025 - 2026 |
| Other 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.

### BGE

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt | $— | $5,450 | $5,450 | 2026 - 2054 |
| Interest payments on long-term debt(a) | 228 | 4,418 | 4,646 | 2025 - 2054 |
| Operating leases | 4 | 33 | 37 | 2025 - 2099 |
| Fuel purchase agreements(b) | 125 | 882 | 1,007 | 2025 - 2038 |
| Electric supply procurement | 1,197 | 800 | 1,997 | 2025 - 2027 |
| Other 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.

### PHI

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt and finance leases | $290 | $8,502 | $8,792 | 2025 - 2054 |
| Interest payments on long-term debt(a) | 394 | 5,802 | 6,196 | 2025 - 2054 |
| Operating leases | 36 | 132 | 168 | 2025 - 2032 |
| Fuel 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 - 2033 |
| Other 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.

### Pepco

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt and finance leases | $6 | $4,421 | $4,427 | 2025 - 2054 |
| Interest 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 - 2028 |
| Other 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.

### DPL

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt and finance leases | $130 | $2,106 | $2,236 | 2025 - 2054 |
| Interest payments on long-term debt(a) | 96 | 1,620 | 1,716 | 2025 - 2054 |
| Operating leases | 8 | 40 | 48 | 2025 - 2032 |
| Fuel 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 - 2033 |
| Other 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.

### ACE

|  | 2025 | Beyond 2025 | Total | Time Period |
| --- | ---: | ---: | ---: | --- |
| Long-term debt and finance leases | $154 | $1,789 | $1,943 | 2025 - 2054 |
| Interest 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 - 2027 |
| Other 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 Statements |
| --- | --- |
| Long-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 Benefits |

### Credit 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. PHI 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.

### Capital Structure

As of December 31, 2024, the capital structures of the Registrants consisted of the following:

|  | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Long-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'.

### Intercompany Money Pool

To 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.

| Exelon Intercompany Money Pool | For the Year Ended December 31, 2024 Maximum Contributed | Maximum Borrowed | As of December 31, 2024 Contributed (Borrowed) |
| --- | ---: | ---: | ---: |
| Exelon Corporate | $626 | $— | $217 |
| PECO | 241 | (255) | — |
| BSC | — | (420) | (213) |
| PHI Corporate | — | (86) | (63) |
| PCI | 59 | — | 59 |

| PHI Intercompany Money Pool | For the Year Ended December 31, 2024 Maximum Contributed | Maximum Borrowed | As of December 31, 2024 Contributed (Borrowed) |
| --- | ---: | ---: | ---: |
| Pepco | $171 | $(48) | $— |
| DPL | 130 | (33) | — |
| ACE | — | (197) | — |

### Shelf Registration Statements

As 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.

### Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

| Commission | At December 31, 2024 Short-term Financing Authority Expiration Date | Amount Commission | Expiration Date | Remaining Long-term Financing Authority Amount |  |  |
| --- | --- | --- | ---: | --- | --- | ---: |
| ComEd | 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.

## Market risk

As filed, 5,689 characters.

The Registrants hold commodity and financial instruments that are exposed to the following market risks:

- Commodity price risk, which is discussed further below.
- Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
- Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
- Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.

Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Board of Directors, Exelon's Audit and Risk Committee, and/or the applicable Utility Board Registrant. The Registrants do not execute derivatives for speculative or proprietary trading purposes.

### Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market.

For additional information on these contracts, see Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

The following table presents maturity and source of fair value for Exelon's and ComEd's mark-to-market commodity contract liabilities. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and require cash. See Note 17 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

| Commodity derivative contracts(a): | Maturities Within 2025 | 2026 | 2027 | 2028 | 2029 | 2030 and Beyond | Total Fair Value |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Prices based on model or other valuation methods (Level 3) | $(29) | $(20) | $(18) | $(16) | $(15) | $(34) | $(132) |

(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

## Controls and procedures

As filed, 3,155 characters.

### All Registrants—Disclosure Controls and Procedures

During the fourth quarter of 2024, each of the Registrant's management, including its principal executive officer and principal financial officer, evaluated disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in that Registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of December 31, 2024, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives.

### All Registrants—Changes in Internal Control Over Financial Reporting

Each Registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. In the first quarter of 2024, ComEd and PECO implemented a new customer care and billing information system replacing the existing system. ComEd and PECO expect the new system to further automate, enhance and standardize the processes by which they engage with their customers. As part of this system implementation, ComEd and PECO appropriately considered the impacts to internal controls over financial reporting. There were no other changes in internal control over financial reporting that occurred during the year ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, any of the Registrant's internal control over financial reporting.

### All Registrants—Internal Control Over Financial Reporting

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2024. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2024 and, therefore, concluded that each Registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Filed Feb 12, 2025.
Source: SEC EDGAR, the filing index for accession 0001109357-25-000043. Last ingested by Listed: Oct 30, 2026, 12:46 ET. No prices; not investment advice.